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2025, Volume 42,  Issue 1

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Research Progress, Current Situation Analysis and Development Suggestions of Drilling Fluid Treatment Agents in China
WANG Zhonghua
2025, 42(1): 1-19. doi: 10.12358/j.issn.1001-5620.2025.01.001
Abstract(174) HTML (52) PDF (2278KB)(58)
Abstract:
To understand the new achievements of drilling fluid additives in China, this article reviews the recent development and application of drilling fluid additives, based on modified biomass materials, synthetic polymers, condensation reaction products, modified industrial by-products, and domestic waste modification products. Modified biomass materials, containing starch, cellulose, lignin, and humic acid, are mainly used for fluid loss reducers, and starch is the most common one; the most studied synthetic polymer materials are water-soluble polymers for fluid loss reducers, viscosity enhancers, encapsulating agents, and viscosity reducers. There are also some studies on water-insoluble materials used for plugging and fluid loss reducers. Monomers with good hydrolytic stability such as NVP as well as DMAM are used to enhance temperature-resistant, salt-resistant, and high valent ion-resistant ability. Condensation reaction products focus on emulsifiers and viscosity enhancers of oil-based drilling fluid, and esterification and amidation reaction of lubricants in water-based drilling fluid as well. Some research has also been conducted on the preparation of drilling fluid treatment agents using industrial by-products and household waste. Although there has already been a large number of research on drilling fluid additives, the research is still not innovative, in-depth, and comprehensive enough. Due to the limitations of molecular design, synthetic means, and evaluation methods, there are relatively few drilling fluid additives that can meet the needs of complex fields on site.There is still a phenomenon of similar or low-level repetitive research. Combining with practice. The research on treatment agents should aim to break through traditional thinking and mechanisms. Around the goals of simplifying drilling fluid components, reducing drilling fluid costs, improving drilling fluid functions, enhancing drilling fluid quality, and promoting green development. Strengthen the development and utilization of biomass resources, innovate synthesis methods and processes, and develop low-cost, high-quality, and long-term multifunctional materials with good comprehensive performance.
Research Progress in Preparation of Nanocellulose and Its Application in Drilling Fluids
ZHAO Xionghu, WANG Can, XIAO Zhe, ZHANG Xi, ZHAO Yueqin
2025, 42(1): 20-29. doi: 10.12358/j.issn.1001-5620.2025.01.002
Abstract(112) HTML (46) PDF (2409KB)(30)
Abstract:
Celluloses are a common additive used in various water-based drilling fluids to effectively reduce the filtration rate, enhance the drilled solids suspending capacity and improve the rheology of the drilling fluids. Nanocellulose as an innovative drilling fluid additive has, apart from the advantages of the common cellulose, new properties such as high temperature stability and resistance to salt and alkali contamination. The nanocellulose also remarkably improve the stability and rheology, and effectively reduce the filtration rate of the drilling fluids. This paper introduces the methods presently used to produce nanocellulose and the application of nanocellulose in drilling fluids. Prospects are made in the paper of the application of the nanocellulose in drilling fluids, aiming at providing a reference for producing new environmentally-friendly high temperature drilling fluid additives.
DRILLING FLUID
Stress Sensitivity Experiment on Shale Gas Formations in Marine-Continental Transitional Facies in Easten Margin of Ordos Basin
LI Bing, NING Xianyi, ZHU Weiping, CHEN Mingjun, HE Pengbo, KANG Yili, LAI Zhehan
2025, 42(1): 30-40. doi: 10.12358/j.issn.1001-5620.2025.01.003
Abstract(89) HTML (34) PDF (2417KB)(16)
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The shale gas formations in the marine-continental transitional facies of the eastern margin of the Ordos Basin are tight gas formations with complex pore and fracture structures as well as high heterogeneity which result in special stress sensitivity of the formations. To understand the degree of the stress sensitivity of the reservoirs, stress sensitivity experiments were performed on cores taken from the marine-continental transitional facies of the eastern margin of the Ordos Basin. The experimental results, combined with the understanding of the lithology and the physical properties of the reservoirs, help reveal the mechanisms of stress sensitivity of the shale gas reservoirs concerned. The studies performed indicate that when the effective stress is increased from 3 MPa to 35 MPa, the permeability of the artificial fractures, the natural fractures and the base core decreases by 97.1%, 86.8% and 50,5%, respectively. During unloading of the effective stress, the permeability of the artificial fractures, the natural fractures and the base core is recovered by 21.4%, 19.0% and 11.6%, respectively, showing significant stress sensitivity hysteresis effects. The stress sensitivity coefficients of the artificial fractures, the natural fractures and the base core are 0.65, 0.58 and 0.19, respectively, and the degrees of stress sensitivity corresponding to these stress sensitivity coefficients are classified as strong-moderate to strong, strong-moderate to weak and weak. The stress sensitivity coefficients show that the multi-scale pore-fracture structure of the shales under research have significant stress sensitivity. The main control factors of formation damage by stress sensitivity include the mineral components, the development of the fractures as well as the pore structure of the shales in the marine-continental transitional facies. It is thus suggested that a reservoir-protective gas production system be developed, and the production of gas be controlled to ensure high production rate and stable production of the gas wells drilled in the marine-continental transitional facies of the eastern margin of the Ordos Basin.
Visual Experimental Study on Evolution and Particle’s Characteristic Behavior of Plugging Layers inside Fractured Loss Zones
PU Lei, XIE Lingzhi, XU Peng, CHEN Huan, XU Mingbiao, WANG Bangzhe
2025, 42(1): 41-50. doi: 10.12358/j.issn.1001-5620.2025.01.004
Abstract(83) HTML (39) PDF (7521KB)(20)
Abstract:
Mud losses into fractures is one of the most difficult problems encountered in drilling unstable formations. Particle bridging is the most effective method of controlling mud losses into fractures. In traditional fracture experimental apparatus how the plugging layers are formed inside the fractures by the flow of particles is still not clearly understood, and this restricts the scientific build-up of a lost circulation slurry. To investigate the characteristic behavior of particles and the dynamic evolution of plugging layers inside fractures, a wellbore-fracture visualization experimental device is set up, and is used to systematically study the behavioral characteristics of the particles, the pattern in which the plugging layers are formed as well as the influencing mechanisms of the formation of the plugging layers under the effects of key factors such as particle size, particle concentration, flowrate of the particle slurry pumped into the fractures and the viscosity of the carrying fluid etc. The experimental results show that the plugging process taking place inside the fractures can be divided into four stages in each of which co-exist the mixing of the particles and the change of the characteristic behavior of the particles. The position at which a plugging layer is set up is highly sensitive to the size distribution of the particles, the concentration of the particles affects the time required for the fractures to be plugged, the structure of the plugging layers is easily altered by the viscosity of the carrying fluid, and too high a pump rate may damage the plugging structure previously formed.
Wellbore Stability Technology of Fractured Carbonate Formation Drilling Fluid in Shunbei Region
LIU Xiongwei, FAN Sheng, GUAN Jintian, HE Yinbo
2025, 42(1): 51-57. doi: 10.12358/j.issn.1001-5620.2025.01.005
Abstract(93) HTML (28) PDF (2762KB)(27)
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Based on the geological analysis of the carbonate rock formation in Shunbei oil and gas field, the reasons for the formation's easy wellbore instability are clarified: first, the rock is easy to be broken and the fracture develops, which is easy to have secondary fracture development, malignant leakage and even well collapse; Second, the bottom hole temperature is high, and the drilling fluid treatment agent is easy to fail at high temperature; Third, the plugging capacity of the currently used polysulfonate drilling fluid is insufficient, which can’t effectively plug formation cracks and reduce pressure transfer; Fourth, the cementation ability of the current drilling fluid is insufficient, which can’t effectively improve the compressive strength of the near-wellbore rock. To solve the above difficulties, a high temperature resistant cementing sealer AD-1 was synthesized from acrylamide, dimethyldiallyl ammonium chloride, 2-acrylamide-2-methylpropanesulfonate sodium and dopamine hydrochloride. The cementation and plugging properties of the cementing agent were evaluated. The experimental results show that the axial compressive strength of the cemented dry carbonate sand beds is up to 2.5-5.0 MPa at 180℃, and the compressive strength is increased by more than 4 times. The compressive strength of the unconsolidated wet sand beds is 0 MPa, and the compressive strength of the consolidated wet carbonate sand beds is increased to 0.2-0.5 MPa. After adding the cementing sealer, the plugging ability of the polysulfonate drilling fluid was significantly improved, and the drilling fluid could effectively plug the sand beds composed of 40-60 and 60-80 mesh carbonate debris, with the maximum pressure ≥6 MPa, and the cumulative loss in 30 minutes was about 10 mL. In addition, the viscosity of the drilling fluid will increase dramatically when the additive amount exceeds 1.0%, and the additive amount should be controlled as appropriate. Therefore, the polysulfonate drilling fluid system with AD-1 as the core has good temperature resistance, cementation and plugging properties, which can provide strong technical support for borehole stability technology in Shunbei region.
Mechanisms of Borehole Wall Destabilization in Drilling Shale Formations in the Central Part of Block Jinzhou-25-1 in Bohai Basin and Drilling Fluid Countermeasures
GENG Lijun, LIU Feng, GANG peng, DONG Xinrou, LIU Wei, LI Bojia
2025, 42(1): 58-65. doi: 10.12358/j.issn.1001-5620.2025.01.006
Abstract(84) HTML (31) PDF (2916KB)(23)
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Well drilling in the central part of the block Jinzhou-25-1 in Bohai basin has frequently encountered borehole wall destabilization when drilling the Dongying formation shales. Based on the analyses of the components and structure of the shales as well as the measurement of their mechanical properties, it was found that the borehole wall destabilizes mainly in two mechanisms, first is the weakening of the shales caused by hydration and swelling, second is the shearing slip of the formations along the bedding planes. Based on this understanding, a water based drilling fluid PEM and a synthetic based drilling fluid BIODRILL S were compared for their performance from several aspects such as basic properties, plugging capacity, inhibitive capacity and the ability to maintain mechanical strength of a formation etc. It was found that the BIODRILL S drilling fluid has several advantages over the PEM drilling fluid, such as high percentage of shale cuttings recovery in hot rolling test, lower linear expansion rate, lower high temperature high pressure filtration rate as well as better performance in maintaining the mechanical strength of the shale formations. A nano-latex plugging agent PF-NSEAL was added into the BIODRILL S drilling fluid at concentrations between 2% and 2.5%, rendering it better microfracture plugging performance. In field operation, the optimized BIODRILL S drilling fluid was used to drill two extended reach wells, the number of downhole problems was greatly reduced, and the drilling rate was increased by 43.7%. The use of the optimized BIODRILL S synthetic based drilling fluid has provided a technical support for solving the borehole wall destabilization problem encountered in block Jinzhou-25-1.
Investigation of High-Temperature Resistant Ionic Liquid Inhibitors for Xinjiang ShapaiGroup 9 and Their Inhibition Mechanism
GAO Shifeng, QU Yuanzhi, HUANG Hongjun, REN Han, JIA Haidong, LIU jingping, JIA Han
2025, 42(1): 66-73. doi: 10.12358/j.issn.1001-5620.2025.01.007
Abstract(90) HTML (28) PDF (3543KB)(18)
Abstract:
The effect of reservoir lithology on the stability of the wellbore in Xinjiang Shapai Group 9 was investigated from multiple perspectives via X-ray diffraction, infrared spectroscopy, scanning electron microscopy, and water contact angle. The inhibition performance, inhibition mechanism, and application of three typical ionic liquids (MOA, CP-DES, MM6) were evaluated.The rocks in this group have a high content of clay minerals and contain a large number of hydroxyl groups on their surfaces, which are highly susceptible to swelling with water. Among the samples treated by three ionic liquid inhibitors, the lowest linear swelling rate (21.2%), the highest hot-rolling recovery (63.1%, 180℃), and the excellent application results of drilling fluid system indicate that deep eutectic solvent ionic liquid (CP-DES) is the most suitable inhibitor for the Xinjiang Shapai Group 9.Further studies revealed that CP-DES could form strong interactions with the clay surface through hydrogen bonding and enter the clay interlayer to hinder the intrusion of water. Meanwhile, the cationic groups could compress the electric double layer on the clay surfaces and weaken the electrostatic repulsion between the particles, which consequently inhibited the hydration swelling of the clay.
Development of a Biodegradable Polymer Temporary Plugging Agent for Drilling Fluid
TIAN Zhiyuan, QI Duo, WANG Haibo, ZHANG Xinpeng, GUO Baohua, XU Jun
2025, 42(1): 74-81. doi: 10.12358/j.issn.1001-5620.2025.01.008
Abstract(87) HTML (44) PDF (2868KB)(24)
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Biodegradable polyester temporary plugging agents (TPAs) have good degradability and low damage to reservoirs, but the disadvantages, which include low thermal stability, low strength of the plugging layers formed and high production cost etc., make it difficult for them to be widely used. To satisfy the requirements for TPAs to work at elevated temperatures, a new biodegradable TPA is developed. This new TPA is prepared by melt blending polybutylene terephthalate (PBT), which has slower hydrolysis rate, and polyamide 6 (PA6), and an epoxy chain extender ADR is added to improve the compatibility of the melt blending materials. The new TPA has better thermal stability and forms plugging layers of higher strength. Experimental results show that the new TPA has better degradability, in a NaOH solution (pH=10) at 120-150℃, percent weight loss of the new TPA after 20-60 d is greater than 80%. When the ratio of PBT and PA6 in the melt blending system is 70% PBT/30% PA6, and into the melt blending system add 1.5% ADR, the compressive strength of the new TPA can be 91 MPa, after degrading at 150℃ for 16 h the compressive strength is still greater than 70 MPa. This new TPA has good compatibility with drilling fluids and excellent plugging performance, and after degrading at 120℃ for 14 d, the residual compressive strength of the plugging layer is 2 MPa.
High Density and High Performance Drilling Fluid System Research and Application at Pakistan North Region ADHI Block
LI Ling, ZHOU Chuxiang, JI Yongzhong, ZHANG Guangjin, WU Gang
2025, 42(1): 82-89. doi: 10.12358/j.issn.1001-5620.2025.01.009
Abstract(97) HTML (33) PDF (3282KB)(21)
Abstract:
The mid-upper Early Miocene Murree formation in the ADHI block, northern Pakistan, is a long red mudstone located in the Φ311.15 mm interval with a length of 1400-1600 m, which is a major difficulty and extremely challenging drilling operation in the block. The red mudstone section has the characteristics of strong dispersion and high slurry production, and the rheological property of drilling fluid is often out of control. Easy to expand and shrink, bit balling, return a large ball of cuttings, blocking the horn; The formation pressure coefficient is high, the density is as high as 1.80-2.00 g/cm3, and the accidents such as differential pressure sticking and broken drilling tools often occur. Formation water, high pressure and low permeability, 1-3 m3/h; The high density further increases the difficulty of controlling rheology and poor solid content of drilling fluid. In order to solve the above Drilling problems in the AHDI block, show Chuanqing's image as a pioneer in complex oil and gas drilling in the open oil and gas service market overseas, and establish the brand of "CCDC Drilling Fluid", the author conducted analysis and research on the mineral components and hydration characteristics of mudstone in the Murree formation. A high-density high-performance water-based drilling fluid system with a density of 2.20 g/cm3, yield point less than 20 Pa, temperature resistance of 100℃ and resistance to 5% mudstone pollution suitable for ADHI block in northern Pakistan was developed based on "efficient mudstone inhibitor, clay accretion inhibitor and ROP Enhancer, nano-microne plugging agent and application technology of macromolecule encapsulation inhibitor under high density conditions". Successfully applied 4 Wells in Pakistan.
A Thermodynamic Model for Predicting 3D Phase Equilibrium Surface of Natural Gas Hydrates Considering Salt Concentration
ZHANG Geng, LI Wentuo, HUANG Honglin, LUO Ming, MA Chuanhua, WU Yanhui, LI Jun
2025, 42(1): 90-101. doi: 10.12358/j.issn.1001-5620.2025.01.010
Abstract(69) HTML (37) PDF (4899KB)(19)
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Accurate prediction of the thermodynamic stability of gas hydrates in salt-bearing systems is of great significance for predicting the accumulation range and determining the decomposition domain of hydrate. Therefore, considering the non-spherical characteristics of hydrate crystal cavity and the electrolyte interaction in the salt-containing system, a thermodynamic model of gas hydrate phase equilibrium considering salt concentration was established, and compared with the experimental data. The results show that the established three-dimensional phase equilibrium surface can effectively predict the thermodynamic stability of NGH, and the absolute mean relative deviation of temperature is only 0.08 in pure water, and no more than 0.15 in salt. When the molar fraction of chloride is greater than 0.02 and the pressure is higher than 20 MPa, the chemical factors cause the p-T curve to shift. When the pressure is small, the equilibrium temperature changes dramatically along the gradient of salt concentration, and the p-T curve no longer has translation characteristics. At the same time, AlCl3 has stronger inhibitory effect on CH4 hydrate than other chlorine salts when the molar fraction is the same. The lnp-X-1/T three-dimensional surface of CH4 hydrate exhibits better Clausius-Clapeyron linear behavior locally, and the surface as a whole has certain nonlinear characteristics. Moreover, the better the inhibition effect of chloride electrolyte on CH4 hydrate, the stronger the nonlinear characteristics.
CEMENTING FLUID
Preparation and Application of a High Temperature Suspension Stabilizing Filter Loss Reducer for Cement Slurries
DU Yubin, LIU Zishuai, LYU Bin, ZHAO Weichao, ZHOU Chongfeng, FAN Ronghua
2025, 42(1): 102-109. doi: 10.12358/j.issn.1001-5620.2025.01.011
Abstract(80) HTML (35) PDF (2823KB)(33)
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High formation temperature gradients prevail in the Qinghai Oilfield (Tsaidam Basin). High bottom hole temperatures in deep and ultra-deep wells plus high formation pressures from the over-pressurized formation belts impose rigorous requirements on cement slurries as to their high temperature high pressure (HTHP) filter losses and rheology, the settling stability and mechanical performance after experiencing heat impact. To deal with these situations, a suspension stabilizing filter loss reducer DFS-200 containing temperature-sensitive groups and branched chain structures was developed. Evaluation of the general performance of DFS-200 shows that it can reduce the high temperature filter loss of a cement slurry (with density between 2.10 g/cm3 and 2.30 g/cm3) to less than 50 mL, and the cement slurry still has zero free water, small density difference between the top cement and the bottom cement of less than 0.03 g/cm3, as well as good rheology and thickening performance. The DFS-200 treated cement slurry does not viscosify at low temperatures and does not thin at elevated temperatures. The strength of the set cement develops quickly, the transition time of the static gel strength of the cement slurry is short. The 200℃ × 48 h compressive strength of the set cement is greater than 30 MPa and does not decline. DFS-200 has been used many times in liner cementing operations in Tsaidam Basin and has gained good results, it has provided a technical support to improving the job quality of cementing the deep and ultra-deep wells in Qinghai Oilfield and also to ensuring the borehole integrity.
Mechanisms of Organic Phosphonate Retarders to Abnormally Thicken Oil Well Cement
ZOU Yiwei, DAI Dan, WANG Yixin, GENG Chenzi, ZHU Sijia, YAO Xiao
2025, 42(1): 110-116. doi: 10.12358/j.issn.1001-5620.2025.01.012
Abstract(54) HTML (17) PDF (2330KB)(18)
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Organic phosphonates are generally used as retarders for cement slurries at high temperatures in Yanchang oilfield. This paper discusses the effects of the retarder sodium ethylene-diamine tetramethylene-phosphonate (EDTMPS) on the thickening performance of the class G high-sulfur-resistant (HSR) oil-well cements from four different manufacturers. The mechanisms of EDTMPS in retarding the thickening time of the four cement slurries were investigated through hydration heat measurement, XRD experiment and solubility measurement. The results of the measurement and experiment show that in the reactions of EDTMPS with the cements, EDTMPS inhibits the solution of dihydrate gypsum and accelerates the solution of C3A, thus the retarding effect of dihydrate gypsum is inhibited and C3A becomes fast hydrated, leading to an increase in the initial consistency of the cement slurry. On the other hand, EDTMPS can accelerate the solution of hemihydrate gypsum which releases SO42−. The SO42− ions released slow down the hydration process of C3A. By adjusting the concentrations of C3A, dihydrate gypsum and hemihydrate gypsum in the class G HSR oil-well cement slurry, the compatibility of the cement slurry with EDTMPS can be improved.
FRACTUREING FLUID & ACIDIZING FLUID
Study on Rheology and Reaction Kinetics of Low Corrosion Self-Heating Gelling Fracturing Fluids
LI Yuchi, LUO Mingliang, ZHAN Yongping, FAN Qiao, LYU Yuanjia, ZHAO Chunguang
2025, 42(1): 117-126. doi: 10.12358/j.issn.1001-5620.2025.01.013
Abstract(67) HTML (27) PDF (2693KB)(15)
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In heavy oil reservoir fracturing, the fracturing fluid, after entering into the reservoir, causes the reservoir temperature to decrease and the viscosity of the crude oils around the fractures to increase to even block the pore throats of the formation. To deal with this problem, a low corrosion self-heating gelling fracturing fluid has been formulated through solution blending method using urea, sodium nitrite and ammonium chloride as heat generation materials, hydrochloric acid as catalyst, the high temperature salt-resistant copolymer FS-1 as viscosifier and organic zirconium as crosslinking agent. In laboratory experiment, the heat generation and gas production properties, rheology and corrosion resistant performance of the fracturing fluid were evaluated, the constituents of the gas produced were identified, the effects of different factors on the rate of heat generation reaction were investigated, and the kinetic parameters of the heat generation reaction were understood. It was found that the self-heating generation system has good heat generation and gas production properties. The higher the concentrations of the reactants, the concentration of the acid catalyst and the initial temperature, the higher the amount of gas produced, and the shorter the time required to reach the highest temperature; on the other hand, the amount of gas is slightly decreasing with an increase in the initial temperature. In the reactant system, the existence of ammonium chloride remarkably reduces the concentration of chloric acid, this not only reduces the rate of corrosion of the fracturing fluid to the pipes for fracturing, but also is beneficial to the gelling of the fracturing fluid. The reaction produces large amount of CO2 and N2 as well as heat. Gelling of the fracturing fluid to some extent weakens the heat generation and gas production properties of the heat generation agents. The gelling fracturing fluid, after shearing at 60℃ and 170 s-1 for 90 min, has viscosity of greater than 50 mPa·s. The reaction order m and n, the activation energy ΔE and the preexponential factor A of the reaction are 2.76, 1.69, 49.54 kJ/mol and 6.82 × 102, respectively. Compared with the self-heating system, the reaction rate of the self-heating gelling fracturing fluid system is greatly reduced. The process parameters of this reaction can be predicted using reaction kinetic equation and adjusted. This study has provided a base for the optimization and design of self-heating fracturing fluids.
Recycling in Drilling Fluids of Flowback Fluids from Slick Water Fracturing Operation
LIU Huaizhu, ZHAO Kangning, CHEN Dong, ZHANG Chao, CHANG Xiaofeng, ZHANG Jie, ZHANG Wangyuan, ZHANG Fan
2025, 42(1): 127-133. doi: 10.12358/j.issn.1001-5620.2025.01.014
Abstract(56) HTML (18) PDF (2372KB)(18)
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When using slickwater fracturing fluids in reservoir stimulation, large amount of fluids flowed back from the hole have complex compositions and need to be discharged. In disposing these fluids, the “zero discharge” technology does not work. To solve this problem, the techniques for the treatment of the flowback slickwater fracturing fluid are optimized to retain the effective components to the maximum, and the slickwater fracturing fluid after treatment is then used as a component of drilling fluids, thereby realizing the recycling of the water phase and part of the additives in the flowback fracturing fluid. An environmentally friendly low-friction drilling fluid is formulated with flowback slickwater fracturing fluids, the composition of which is as follows: make-up water+4%sodium bentonite+0.3%soda ash + 3%polysaccharide+0.1%FA-367+1.0%CMC-LV+1.0%methyl oleate. Laboratory experiment results show that the properties of this drilling fluid are stable at temperatures between 25℃ and 150℃, the percent shale core recovery on hot rolling test is at least 90%, the linear rate of expansion of shale cores is reduced by at least 72%, the friction coefficient is reduced by at least 80%, and the drilling fluid satisfies the requirements of environment protection. The micromorphology of the mud cakes under SEM proves that this drilling fluid has good shale inhibitive capacity and good filtration control property at elevated temperatures.
COMPLETION FLUID
A Single Phase Acid for One Step Removal of Organic Deposition and Inorganic Scale
CUI Bo, RONG Xinming, FENG Puyong, YAO Erdong, ZHOU Fujian, WANG Shun
2025, 42(1): 134-142. doi: 10.12358/j.issn.1001-5620.2025.01.015
Abstract(48) HTML (17) PDF (3754KB)(15)
Abstract:
The deposition of organic and inorganic scales in the near wellbore zone seriously affects the normal production of oil and gas. Conventional blockage removal systems cannot simultaneously remove organic, inorganic, and their mixed scales. A new multifunctional unblocking system, single phase acid, has been developed to solve the above issues. The system consists of two immiscible liquids (aromatic solvent for organic scale and acid solution for inorganic scale), surfactants, cosurfactants, and functional additives. The performance of single phase acid system was systematically analyzed and evaluated using experimental instruments such as rotary rock disk analyzer, conductivity meter, particle size analyzer, interfacial tension meter, wetting angle tester, friction meter, core flow meter, CT scanning, etc. The experimental results show that the single phase acid is a nano homogeneous dispersion system with an external phase of oil and an internal phase of acid, with a particle size distribution of 7-50 nm;The interfacial tension is 0; It has the performance of relieving reservoir emulsification (demulsification rate greater than 90%), water locking, and wetting modification (oil wet modification to water wet); it can simultaneously dissolve organic scale, inorganic scale, and their mixed scale (dissolution rate 100%); low friction resistance (lower resistance rate greater than 80%), and can achieve large injection rate operations; It has high retarded rate (retarded rate greater than 99%) and can achieve deep depth of reservoirs. Single phase acid utilizes the principle of mutual solubility between oil and acid to achieve the simultaneous dissolution of organic scale, inorganic scale, and their mixed scale in a one step. It is of great significance for the efficient removal of mixed scale pollutants in the near-well area of oil and gas Wells and transfer Wells. Single phase acid system has been carried out field test in Missan Oilfield in Iraq, and get good stimulation result.

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