2022 Vol. 39, No. 2

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DRILLING FLUID
A Modified Hectorite Viscosifier and Gelling Agent for Oil Based Drilling Fluids
NI Xiaoxiao, SHI He, CHENG Rongchao, ZHANG Jiaqi, WANG Jianhua
2022, 39(2): 133-138. doi: 10.12358/j.issn.1001-5620.2022.02.001
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A modified hectorite viscosifier and gelling agent, MLap-1, for oil based drilling fluids, has been developed through one-step sol-gel method using triethoxyoctylsilane and hectorite. Characterization of the product with IR spectroscopy, TGA, TEM and surface wettability has proved the success of the synthesis. Evaluation of MLap-1 showed that it can improve the emulsion efficiency and electric stability of 80∶20 (O/W) emulsion; at 0.3% concentration of MLap-1 the electric stability of the emulsion was at least 1,200 V, and the apparent viscosity and yield point of the emulsion were increased from 12 mPa·s and 0 Pa to 23 mPa·s and 10 Pa, respectively. A high density oil based drilling fluid treated with MLap-1, after aging at 200 ℃, had its yield point maintained at above 4 Pa, low-shear-rate yield point above 3 Pa, electric stability above 1,000 V, and filtration rate less than 5.0 mL. These data indicate that MLap-1 is able to maintain the oil based drilling fluid in good suspension stability, good emulsion stability and good filtration control. The development of MLap-1 can be used to technically support the deep and ultra-deep drilling with oil based drilling fluids.
The Synthesis and Evaluation of a High Temperature Nano Micro-Spherical Polymer Plugging Agent
HUANG Chengsheng, CHU Qi, LI Tao, LIU Jinhua
2022, 39(2): 139-145. doi: 10.12358/j.issn.1001-5620.2022.02.002
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A nano micro-spherical polymer plugging agent OPTB was developed to try to replace the flexible plugging agents presently in use, which have the shortage of low thermal stability. OTPB is a high temperature plugging agent and is synthesized through free radical micellar polymerization with several raw materials such as acrylamide (AM), sodium p-styrene sulfonate (SSS), sodium acrylate (AAS), 1H,1H,2H,2H-perfluorooctyl acrylate (TEAC) and 1,3,5-tris(methacrylamido) benzene (B-TMAC). The polymerization used 1-((cyano-1-methylethyl) azo) formamide as the initiator, and dodecyl mercaptan (TDDM) as the molecular weight regulator. The optimum synthesis conditions were determined through orthogonal experiment, as follows: reaction temperature = 105 ℃, reaction time = 20 h, concentration of the monomeric raw materials = 7.5%, concentration of CABN = 0.4%, and concentration of TDDM = 1.5%. The molecular structure of OPTB was characterized with 1H-NMR. Experiment on the properties of the drilling fluid treated with OPTB showed that OPTB has little effect on the rheology of the drilling fluid, and the quality of the mud cake was significantly improved. After aging at high temperature, the particle size of OPTB is still in a monodisperse state. At a concentration of 3.0%, 90.84% of the nanometer-sized and micron-sized pores can be plugged by OPTB, and this plugging effect can effectively slow down the transmission of the pressure of the fluid column in the wellbore into the formations. The micromorphology of OPTB before and after aging at 160 ℃ for 16 h observed under SEM showed that the particles of OPTB are spherical with narrow size distribution. At elevated temperatures, part of the OPTB particles is still in monodisperse state.
High Density Clay-free Oil Based Drilling Fluid
YOU Fuchang, WEN Hua, WU Jiao, ZHANG Ya
2022, 39(2): 146-150. doi: 10.12358/j.issn.1001-5620.2022.02.003
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Barite in oil based drilling fluids at elevated temperatures is easy to sag, resulting in poor stability of the muds. Conventionally this is solved by adding more organophilic clay. High clay content in the mud results in high mud viscosity and high ECD, causing mud losses to happen. To deal with this problem, a small particle size emulsifier DEMUL with high electric stability and viscosifying property has been developed to formulate a high density clay-free oil based drilling fluid. The drilling fluid was treated with DEMUL, SEBS (a styrene-butene/butadiene-styrene block copolymer) and a gellant, the synergy of these additives helps improve the stability of the oil based drilling fluid. This drilling fluid has simple formulation, and each additive is added at a low concentration. Laboratory experiment showed that the oil based drilling fluid still retained good rheology after aging at 200 ℃ for 160 h. After standing still at 160 °C for 336 h, the settling factor of the drilling fluid was 0.5074, indicating that the drilling fluid had good stability. Furthermore, this drilling fluid also has good inhibitive capacity and extreme-pressure lubricity. This drilling fluid has been used in drilling the horizontal section of a high pressure shale gas well in Chuanyu area. During the whole drilling operation, the drilling fluid showed stable rheology, good sand carrying capacity and high inhibitive capacity, and no downhole trouble has ever been encountered.
Study on Effects of Temperature and Pressure on Density of Oil Based Drilling Fluids and the Mathematical Model Thereof
YANG Lanping, LI Zhiqiang, NIE Qiangyong, LIANG Yi, JIANG Guancheng
2022, 39(2): 151-157. doi: 10.12358/j.issn.1001-5620.2022.02.004
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The density of oil based drilling fluids is significantly affected by temperature and pressure. Understanding the change of the density of oil based drilling fluids is of importance to the safety of the drilling operation. Oil based drilling fluids of 4 different densities with the same composition copied from the composition of a field drilling fluid were formulated in laboratory and were tested for the change of density with an HTHP density balance made by Anton Paar Company in temperature range of 60 – 220 ℃ and pressure range of 20 – 120 MPa. Using the teste results, the effects of temperature and pressure on the density of the oil based drilling fluids were investigated, and a temperature-pressure binary mathematical model about the density of oil based drilling fluid was established. The accuracy of the model was verified with field oil based drilling fluids of different densities, and it was found that the values predicted with the model and the values measured agreed closely with each other, the average prediction accuracy of the model is up to 97.93%, meaning that the model is able to satisfy the needs of field application. Verification of the model on another two oil based drilling fluids with similar composition showed an average error of 9.24%, indicating a high prediction accuracy.
Study and Application of Dispersion Polymerization in Preparing PAM Filter Loss Reducer
YANG Lili, LIU Hanqing, AO Tian, JIANG Guancheng, WANG Aijia
2022, 39(2): 158-163. doi: 10.12358/j.issn.1001-5620.2022.02.005
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A microsphere polyacrylamide (PAM) filter loss reducer FA-25 has been developed with acrylamide monomer through dispersion polymerization. The filtration control performance of FA-25 and other PAMs made through aqueous polymerization and inverse emulsion polymerization was compared. The dispersion polymerization is nontoxic and environmentally friendly, and the product does not need any post-treatment. The product FA-25 was characterized through TEM analysis, TG analysis, particle size analysis and molecular weight analysis through gel chromatography. It was proved that the particles of FA-25 are in a shape of sphere, with particle sizes between 40 nm and 200 nm. The molecular weight of FA-25 is 104,928, and the initial thermal decomposition temperature is 200 ℃. A bentonite slurry treated with 1% FA-25 had its API filtration rate reduced to 13.8 mL, this proves that FA-25 has filtration control performance better than the PAMs made through water solution polymerization and inverse emulsion polymerization. FA-25 functions normally at temperatures up to 200 ℃. Good performance of FA-25 renders it good application prospect.
Ammonolysis Modified Soybean Lecithin as a Drilling Fluid Lubricant
SUN Bingxiang, LI Wenbo
2022, 39(2): 164-170. doi: 10.12358/j.issn.1001-5620.2022.02.006
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Soybean lecithin is a derivative of difatty acid glycerophospholipid, whose molecular structure is rich in lubricant adsorption groups, such as phosphate group, hydroxyl and amino group. The difatty acid glyceride in the molecule of the difatty acid glycerophospholipid has very strong hydrophobicity and very low dispersity, makes it difficult to act as a drilling fluid lubricant. By heating the mixture of soybean lecithin, alcohol amine, catalyst and mineral oil dispersant, these chemicals react to produce a modified phospholipid lubricant. The working mechanisms of the ammonolysis (by alcohol amine) modified soybean lecithin was studied with IR and PNMR. The ammonolysis modified soybean lecithin lubricant was tested to determine their performance as a drilling fluid. In the test, the lubricity, high temperature stability, salt and calcium resistance of the new lubricant were compared with those of the other commercially available lubricants. The new lubricant was also tested for its compatibility with the polymer sulfonate drilling fluid and its ability to improve the lubricity of the drilling fluid. The optimum amount of alcohol amine used in the ammonolysis process was determined to be 10%-25%. The alcohol amine can be used to ammonolyze the fatty acid ester in the soybean lecithin to form fatty amide, thereby reducing the content of hydrophobic fatty chain in the soybean lecithin and enhancing its water dispersity. The hydroxyl formed during the ammonolysis can react with the ionic phosphate to form pentacyclic phosphate through lactonization reaction, and the ionic phosphate is thus masked. The modified soybean lecithin lubricant developed has excellent lubricating capacity, good high-temperature resistance, good salt- and calcium-resistance, as well as good compatibility with many water based drilling fluids, making it a potential high performance drilling fluid lubricant.
Drilling Fluid with Superior Plugging Performance Used in Deep Well Drilling in Manshen Block
YU Huamin, XUE Li, WU Hongling, LI Haibiao, FENG Dan, YANG Jiping, LU Na
2022, 39(2): 171-179. doi: 10.12358/j.issn.1001-5620.2022.02.007
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The deep formations drilled in the Manshen block are broken and full of microfractures. They have high clay contents with large differences in clay composition. Hard and brittle shales and water-sensitive shales are coexisting in the formations drilled. These formations easily lose their stability during drilling because of hydraulic splitting and difference in the speed of hydration. A technical measure named “physical support plus chemical inhibition and plugging” was presented and an anti-collapse drilling fluid with superior plugging capacity formulated to deal with the borehole wall instability problem. Laboratory study showed that the drilling fluid functioned normally at 180 ℃ and was able to resist contamination by 10% saltwater. Shale samples taken from the T layer and S layer were tested in the drilling fluid formulated. Hot rolling test gave percent cuttings recovery of 89.36% and 91.33% respectively, and expansion test gave rate of expansion of 7.3% and 4.2% respectively. This drilling fluid can plug the pores in cores made with quartz particles from 20 mesh to 120 mesh. In drilling the well ManS5-H4, the drilling fluid showed stable properties and had low filtration rate. It had good inhibitive capacity and collapse prevention performance. Tripping was smooth with no overpulls and resistance, the second and the third interval found average hole enlargement of 4.28% and 6.75% respectively. The cuttings returned to the shake shakers kept their original shakes and no downhole troubles were ever encountered. This drilling fluid has satisfied the needs of drilling the complex formations and saved the total cost of drilling.
Application of Two-Stage Strengthened Bridging Technique in Well Nanpu27-Ping201
GUO Minghong, ZHANG Kezheng, LYU Donghua, LAI Dongfeng, WANG Baojun, XU Wenguang, LIU Yan, LI Xiumei
2022, 39(2): 180-184. doi: 10.12358/j.issn.1001-5620.2022.02.008
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Wells drilled in the Dongsan member of the 2-27 block, the 2nd Structure in Jidong Oilfield penetrate several sections of igneous rocks with fractures, vugs and low pressure-bearing capacity. In the same interval of the wells, there are dark gray colored shales with high collapse pressure and very narrow safe drilling window. In deviated well drilling, the coexistence of wellbore collapse and mud losses is frequently encountered, resulting in many downhole accidents. In the drilling operation of the well Nanpu27-Ping201, mud losses were encountered several times. One of the severe mud losses, lost circulation, took place when drilled to 4,574 m. Bridging method was tried twice without success in controlling the lost circulation. Based on the analysis of the downhole situations, it was decided to use the two-stage strengthened bridging method to cure the mud loss. In the first stage, the lost circulation control slurry was formulated mainly with fine and medium particles and 3% solidifying agent. Laboratory test results showed that when the solidifying agent was added, the lost circulation control slurry still has good pumpability, the particles pack much denser, and the internal friction of the slurry was increased by 6 times. In the second stage, a high temperature, high-temperature resin particles in triangular-cone shape were used to control the mud loss. The resin particles are easy to go into the channels through which the mud was lost, and are easy to be retained in the channels. If it is necessary, the resin particles are also easy to flow back. The lost circulation control slurry was pushed and squeezed into the channels and the mud loss was controlled in the first try. In subsequent drilling operation, no mud losses occurred again.
Factors Affecting Measurement of Polyether Amine Content and Elimination Thereof
LIU Xiaoyan
2022, 39(2): 185-189. doi: 10.12358/j.issn.1001-5620.2022.02.009
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Polyether amine is a highly effective shale inhibitor which are more and more widely used in drilling fluids. Since there are no methods of determining the free content of the polyether amine in a drilling fluid, there is no basis for determining the amount of polyether amine when maintaining the properties of the drilling fluid. In laboratory studies, the methods of determining the content of polyether amine in drilling fluids were investigated. It was found that the common drilling fluid additives, such as caustic soda, sodium carboxy methyl cellulose, sulfonated methyl phenolic resin and potassium salts of hydrolyzed polyacrylamide make the measurement results higher than the theoretical value. A method was found able to eliminate the factors interfering the determination of the polyether amine concentration. In verifying the new method in laboratory experiment, it was found that it gave results with errors ≤10%, satisfying the needs of field application.
A New Method for On-site PSD Evaluation of Oil Based Mud
LI Bing
2022, 39(2): 190-193. doi: 10.12358/j.issn.1001-5620.2022.02.010
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Particle size distribution (PSD) has major effects on the properties of oil based drilling fluids in field operations, and the on-site determination of the solids particle sizes is therefore important to the controlling and maintenance of the drilling fluid properties. Using the PSD date of field oil based drilling fluids prior to and after passing through solids control equipment, a relationship between the solids removal efficiency of the solids control equipment and the PSD of the drilling fluids was established. The solids removal efficiency of the field solids control equipment can be obtained by measuring the solids content of a drilling fluid, and the range of the solids particle sizes can then be also determined. Field tests of different drilling fluids have shown that there is a strong correlation between the solids removal efficiency of a solids control equipment and the solids PSD, the coefficient of correlation R2 being 0.97. A field oil based drilling fluid, after passing through a set of solids control equipment, had its solids content reduced from 45.0% to 16.2%, the efficiency of solids removal was therefore 36.0%. Using the aforementioned test method, the particle size of the solids was 12.50 μm, falling in the range of particle size peaks (7.11 – 12.73 μm) obtained with laser particle size tester. These data indicate that the proposed test method has good accuracy, making it feasible to be used in measuring the solids sizes of field drilling fluids.
Laboratory Research on Offshore Oil-Based Drill Cuttings Cleaning
WANG Kunjian, FENG Shuo, LIU Yang, ZHANG Yuchen, LI Bin, LI Kuncheng, SUN Dejun
2022, 39(2): 194-199. doi: 10.12358/j.issn.1001-5620.2022.02.011
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Drilled cuttings from wells drilled with oil based drilling fluids contain base oils and drilling fluid additives. These drilled cuttings, if discharged directly without proper disposal, will not only severely harm the environment, but also cause a huge waste of oils. To avoid this problem, the oily cuttings generated from offshore wells are generally cleaned with surfactant water solution. An oily cuttings cleaning fluid formulated with artificial seawater has this composition: 0.7% fatty alcohol polyoxyethylene ether AEO-5 + 0.3% anionic surfactant SDBS + 0.15% Na5P3O10. In laboratory experiment, the oily cuttings were cleaned with this solution and the effects of drilling fluid additives and the minerals of the drilled cuttings on the residue oils on cuttings were investigated. It was found that the presence of drilling fluid additives in the residue oil on cuttings makes the cleaning more difficult. Compared with mica, feldspar and quartz, kaolinite cuttings are more difficult to clean. Based on laboratory experiments, the optimum cuttings cleaning technique was determined as follows: mixing speed = 500 r/min, ratio of solid to liquid = 1:4, cleaning time = 15 min, temperature for the cleaning = 25 ℃. After the cuttings were cleaned, the residue oils on cuttings can be reduced to less than 1%, which satisfies the requirements of the standard “Effluent Limitations for Pollutants from Offshore Petroleum Exploration and Production”.
CEMENTING FLUID
Effects of High Temperature Synthesized Calcium Silicate Hydrate on Hydration Process of Oil Well Cement
LIU Xuepeng
2022, 39(2): 200-207. doi: 10.12358/j.issn.1001-5620.2022.02.012
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A granular crystalline calcium silicate hydrate has been synthesized through high temperature hydrothermal reaction at 160 ℃ and 80 MPa with CaO, Ca(OH)2 and white carbon black (a silica) as the major raw materials. Study on the effects of the synthesis product on the hydration process of oil well cement showed that the use of the synthesized calcium silicate hydrate caused the released heat of hydration of the cement to double, and was able to significantly accelerate the heat release process of the cement slurry. The particle sizes of the calcium silicate hydrate have some effects on the hydration process of the cement. When the particle size is in nano-scale, the rate of heat release and the total heat released of the cement slurry increase more obviously. By adding a specific amount of the calcium silicate hydrate into a cement slurry, the compressive strength of the set cement, the overall properties of the cement slurry and the set cement can all be improved. The study has shown that the ratio of SiO2/CaO of the cement affects its hydration process.
A High Temperature CO2 Resistant Hydroxyapatite Cement Slurry
TIAN Jin
2022, 39(2): 208-213. doi: 10.12358/j.issn.1001-5620.2022.02.013
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Cement slurries used in high temperature gas wells must have corrosion resistance. Reports on corrosion resistance of set cement in high temperature wells are rarely seen because of the corrosion of the cement slurries to the testing equipment and the lack of high temperature polymer corrosion inhibitors. A high temperature CO2 resistant hydroxyapatite cement slurry was formulated with the hydroxyapatite as inorganic corrosion inhibitor and a self-made polymer emulsion as the polymer corrosion inhibitor. Laboratory evaluation results have sown that the cement slurry has good rheology and anti-channeling performance. Depth of corrosion on the set cement in 90 d is less than 0.5 mm. XRD and SEM analyses of the set cement have demonstrated that the gelatinous substance and calcium hydroxide almost disappeared in the high temperature area. The only corrosion reaction was the reaction between the xonotlite and CO2. LKseal polymer corrosion inhibitor minimizes the corrosion of the set cement by CO2 through filming action. The hydroxyapatite repairs the vugs and pores formed by corrosion on the set cement through adsorption of CO2 which then produces laminated carbonate hydroxyapatite, thereby enhancing the corrosion resistance of the hydroxyapatite cement.
Encapsulation of Energy-storage Microspheres
LIANG Jiwen, LIU Hexing, WANG Chenglong, HUANG Jing, SHEN Shengda, LIU Huajie
2022, 39(2): 214-220. doi: 10.12358/j.issn.1001-5620.2022.02.014
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To maintain the gas hydrate in stable conditions during deep offshore well cementing, a cement slurry with low heat of hydration should be used. Presently this is realized by adding heat energy storage agents in the oil well cement. The problem with this method is that the heat energy storage agent directly added into the cement slurry has poor compatibility. If the heat energy storage agent is absorbed into a high strength carrier microsphere to form an energy storage microsphere, the direct contact of the heat energy storage agent with the cement slurry can be avoided, and this should be an effective measure to solve the negative effects of heat energy storage agents on cement slurries. Opening of carrier microsphere walls will cause the leaking of the heat energy storage agent from the carrier microspheres, encapsulation of the microspheres is thus necessary. A new encapsulation methos is required to solve the problems existed with the existing encapsulation technology such as high cost and time consuming. In laboratory experiment, acrylic acid resin was chosen as the encapsulation material, and the carrier microspheres were encapsulated with spray method. Evaluation of the encapsulation showed that the best encapsulation can be achieved at a acrylic acid resin mass fraction of 20%. A simple efficient encapsulation method was thus developed. The energy storage microspheres thus encapsulated have good compressive strength, good high temperature stability and good resistance to alkaline environment. They can stay in marine environment for a long time. The development of this encapsulation technology and the energy storage microspheres has opened a new way of solving the incompatibility between heat energy storage agent and cement slurry, and is important to the effective isolation of natural gas hydrate. It has also provided a clue for the development of additive carriers for oil well cement.
Research on the Effect of Blast Furnace Slag on Low-temperature Hydration Characteristics and High-temperature Mechanical Properties of Aluminate Cement
GUO Hua, MA Qianyun, WU Zhiqiang, ZHANG Dangsheng
2022, 39(2): 221-226. doi: 10.12358/j.issn.1001-5620.2022.02.015
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Well cementing operation is now faced with more complex working conditions such as high temperature, high pressure and acidic environment in oil and gas exploration and development, demanding higher quality cement sheath. Silicate cement, because of its mineral composition and hydrational products, is easy to get corroded in acidic environment, resulting in failure of the cement sheaths to seal the annular spaces behind the casing string. Compared with silicate cement, the aluminate cement modified with blast furnace slag has properties that are more satisfactory, for example, it has better high-temperature resistance, long durability, and higher resistance to acid corrosion, as well as low cost and wider applicability. The corrosion resistance of the blast furnace slag modified aluminate cement was studied in simulated working conditions of high temperature high pressure offshore operation. The strength development and corrosion resistance mechanisms of the blast furnace slag modified aluminate cement were revealed by characterizing the mineral composition and micromorphology of the set cement before and after corrosion. It was found that addition of 40% blast furnace slag helps the aluminate cement retard its late-stage strength deterioration and improve its corrosion resistance. Microscopic analyses showed that the tricalcium aluminate hexahydrate (C3AH6) is produced directly from the main mineral component CA (calcium aluminate) of the aluminate cement, thereby avoiding the reaction of C2AH8 (dicalcium aluminate octahydrate) and CAH10 (calcium aluminate decahydrate) with the blast furnace slag to produce C2ASH8 (calcium aluminosilicate hydrate), a mineral having loose structure and low strength. The production of large amount of C3AH6 results in a set cement with much denser structure, reducing the number of channels through which acidic fluid can flow and greatly enhancing the mechanical property and corrosion resistance of the blast furnace slag modified aluminate cement.
Influence of Mosaic Shielding Drilling Fluid Filter Cake on the Cementing Quality of Second Interface and Improvement Method
HE Yuting, ZHAO Shuxun, GAO Qixuan, LI Mingze, LYU Baoyu, ZUO Tianpeng, ZHENG Yijie, CHENG Xiaowei
2022, 39(2): 227-233. doi: 10.12358/j.issn.1001-5620.2022.02.016
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The quality of cementing is the key to decide whether the later mining operation can proceed smoothly. The filter cake formed during drilling will affect the cementing quality of the second interface. Therefore, this paper analyzes the influence of embedded shielding drilling fluid filter cake on the cementing quality of the second interface through the evaluation method of the cementing strength of the second interface. Combined with SEM and EDS, it further shows that the virtual filter cake formed by drilling fluid will reduce the cementing quality of the second interface because of its loose gel state. Aiming at the above problems, this paper selects AEO, T60 and OP as penetrant to flush the filter cake of embedded shielding drilling fluid. The experimental results show that AEO has the best flushing effect on the filter cake of embedded shielding drilling fluid. After the filter cake is flushed by AEO, the cementing strength of the second interface of cementing is increased by 33.34%～166.67%, which greatly improves the cementing quality of the second interface of cementing.
Preparation and Application of Fluid Loss Additive GT-1 for High Temperature Cementing Slurry
ZHAO Jiansheng, DAI Qing, HUO Jinhua, LI Yang
2022, 39(2): 234-240. doi: 10.12358/j.issn.1001-5620.2022.02.017
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In exploration of deep and ultra-deep buried oil and gas resources, well cementing operation has long imposed more rigorous requirements on cement slurries and additives. Filter loss reducers commonly used in cement slurries, for example, have some shortages such as poor high-temperature and salt resistance, narrow temperature range in which the filter loss reducers can work, as well ss poor compatibility with other additives. To solve these problems, a high temperature filter loss reducer GT-1 was developed based on the design of molecular structure and the selection of functional monomers, with raw materials such as 2-acrylamido-2-methylpropane sulfonic acid (AMPS), acrylamide (AM), sodium p-styrene sulfonate (SSS) and nano silica. Using IR, gel chromatography, simultaneous thermal analyzer and SEM, the filtration control, high temperature resistance and salt resistance of GT-1, as well as GT-1’s effect on the rheology of cement slurry, the compressive strength of set cement and consistency of cement slurry were studied. The study showed that the chemical structure of GT-1 meets the requirements previously planned. The weight average molecular weight of GT-1 is 138,431, and GT-1 has excellent thermal stability. A regular spatial network structure can be measured in GT-1’s water solution. Good high temperature and salt resistance of GT-1 makes it suitable for controlling the filtration rate of cement slurry. Cement slurries formulated with GT-1 have good engineering performance which satisfies the needs of well cementing.
ACIDIZING FLUID & FRACTURING FLUID
Study on Formulating Fracturing Fluids with Used Fracturing Fluids for Tight Gas Reservoirs
SHEN Jinwei, YUAN Wenkui, ZHAO Jian, CHEN Lei, LI Meng, SUN Houtai
2022, 39(2): 241-247. doi: 10.12358/j.issn.1001-5620.2022.02.018
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In this paper, the effects of the water from the treatment of the flowback fracturing fluids on the properties of the guar gum fracturing fluid were discussed to solve the problem of the reuse of the water. In high salinity water, guar gum has poor swelling capacity and poor crosslinking performance. To overcome these problems, a salt-resistant guar gum PA-G, a chelating agent PA-CR and a synthesized organoboron crosslinking agent PA-CL were used to formulate a fracturing fluid with water from flowback fracturing fluids. Laboratory experimental results showed that this fracturing fluid is resistant to shearing damage at 90 °C. It has these functionalities such as: 1) the selected salt-resistant guar gum PA-G has high swelling rate and high viscosity; water solution containing 0.3% PA-G has its viscosity developed to 30 mPa·s in 5 min. 2) The high efficiency chelating agent, which was developed with organic base, EDTA, organophosphate and polymer, can effectively chelate calcium and magnesium ions. Using this chelating agent, the pH of a high salinity water containing 1,500 mg/L calcium and magnesium ions can be raised to above 10 without causing precipitation. 3) the organoboron crosslinking agent developed has the property of delaying crosslinking.
Study on Degradable Fiber Fracturing Fluid and Its Application in Sulige Gas Field
GAN Lin, QI Guodong, LI Zhaochuan, FU Yueying, WANG Hongke, JIN Jianxia
2022, 39(2): 248-252. doi: 10.12358/j.issn.1001-5620.2022.02.019
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To improve the placement efficiency of proppants in the Sulige gas field, prevent sand production and backflow of the proppants, a fiber used in fracturing fluids was surface modified, and the size distribution and concentration of the fiber particles were optimized. Laboratory experiments on several parameters related to fracturing job, such as the degradability, dispersibility, damage to core, sand suspension performance of fiber, high temperature resistance and gel breaking property of fracturing fluid, were performed. It was found that fiber particles with diameter of 10 μm and length of 12 mm have good dispersibility in a fracturing fluid at concentration of 0.15%, and 80% of the fiber particles can be degraded after 120 h of dissolution in the fracturing fluid. Rate of core damage caused by the degraded fibers is less than 5%. The fiber has good viscosifying performance in the fracturing fluid, the viscosity of the fracturing fluid after shearing at 170 s-1 and 110 ℃ for 120 min was still higher than 120 mPa·s. The fiber, by the bridging action between the particles, forms a network structure, thereby bonding the proppant particles within the fracturing fluid and reducing the settling velocity of the proppant. Field experiment found no sand production and backflow of proppant, and the open flow capacity of the well fractured with the GT-1 fracturing fluid is 108.61 × 104 m3/d, indicating that the fracturing job has met the expected goal.
Study on Compound Fracturing of Maokou Formation Marl in Southeast Sichuan
LIU Wei
2022, 39(2): 253-258. doi: 10.12358/j.issn.1001-5620.2022.02.020
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The Maokou formation in the southeast Sichuan is shallow buried. It is rich in sensitive minerals and has low porosity and low permeability. In reservoir stimulation operations, multi-cluster limited entry perforation, friction-reduced water with sand and fracturing with compound clear acids techniques were used to increase the volume of reservoir formations to be stimulated and to improve the conductivity of formation fractures. Based on the rock mechanics parameters, the artificial fracture density was increased using intensive cut perforation technique, the spacing between two fractures was optimized to 10 – 15 m by increasing the inducing force. When the fluid volume in a single section was 1,600 – 1,800 m3, and the ratio of friction-reduced water to clear acid was 6 : 4, the surfaces of the fractures can be itched away, thereby increasing the conductivity of the fractures and strengthening the seepage channels. A clear thickening agent with acid tolerance and high friction-reducing capacity was selected and used to formulate a clear acid with percent friction reduction of 63.5%. With this acid, the friction of acid fracturing operation was effectively reduced, which is beneficial to high flow rate acid fracturing job. At closure pressure of 30 MPa, the conductivity of the acid-itched fractures reached 14.9 μm2∙cm. The rocks, after being itched by the clear acid, had basically unform surface structures. The acid-itched wormholes and the surfaces of the factures are free of any attachment, which is less damaging to the reservoirs. This acid was used in the fracturing of the well FM1HF. Using a Φ12 mm choke, the daily gas production rate of the well reached 4.12 × 104 m3, a stable industrial gas production rate first obtained from the Maokou formation in southeast Sichuan, which proves the feasibility of this fracturing technology in stimulating marl reservoirs. This technology will provide a good reference and popularization value for stimulating similar reservoirs in China.
COMPLETION FLUID
Preparation and Properties of Slow-release Organic Acid Micro-emulsion with High Efficient Plugging Removal
HE Licheng, LAN Qiang, HUANG Wei’an, WANG Xuechen, SHANG Shufang, LI Xiuling
2022, 39(2): 259-264. doi: 10.12358/j.issn.1001-5620.2022.02.021
Abstract(1599) HTML (340) PDF (2364KB)(49)
Abstract:
In view of the problem of uneven acidizing profile and second damage during the acidification in stimulation, organic acids and inorganic acids were selected to form complex acids, and surfactant and co-surfactant also were optimized to prepare organic slow-release acid micro-emulsion. The formula is: AQAS∶AEO=1∶1, n-butanol: n-octanol =1∶1, water phase: oil phase = 3∶7, co-surfactant∶surfactant =1∶2, acetic acid∶hydrofluoric acid = 4∶1. The mud cake removal rate of the system is more than 85%, the plugging removal effect in the low-permeability core is remarkable, and the permeability recovery value is more than 100%.

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