Abstract: Polymer microgel , also known as microspheres,a kind of polymer cross-linked network particles, have been widely used in oilfield development in recent years due to their excellent temperature and salt resistance and special configuration. As the reservoir environment becomes more and more severe, new requirements are put forward for the performance of polymer microsgels. So it is necessary to make the high performance and stable polymer microgels. In this paper, the preparation of polymer microgels were reviewed, including inverse emulsion polymerization, inverse microemulsion polymerization, inverse suspension polymerization and dispersion polymerization. The applications of polymer microgels in deep control and displacement, oilfield tracer and fluid loss control in drilling fluid were summarized. The different mechanism of microgels used in profile control is discussed. The properties of different fluorescent polymer microgels were compared. In order to solve the problems of polymer microspheres, such as few reports on functional polymer microspheres, it is necessary to deepen the research on the configuration of microspheres. And the preparation and application of functional polymers in oil and gas field development was pointed out.
PAN Jianghao, JIA Wenfeng, SHENG Jiaping.Preparation and application progress of polymer microgel in oil and gas field[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：531-543. doi: 10.12358/j.issn.1001-5620.2021.05.001.
Abstract: A low temperature inhibitive drilling fluid was developed for use in offshore natural gas hydrate drilling to deal with several technical challenges such as low temperature in deep waters, narrow safe drilling window in shallow formations, inhibition of the formation and decomposition of gas hydrate and requirements on environment protection etc. The low temperature inhibitive drilling fluid was formulated with a gas hydrate inhibitor, which was developed by compounding the thermodynamic inhibitor KCl and a kinetic inhibitor A2, and high molecular weight additives with superior low temperature rheology stability. This drilling fluid has good rheology. The bentonite content, API filter loss and density of this drilling fluid are 2%, 4 mL and 1.07 g/cm3, respectively. It has a stable low temperature rheology: the ECD at 4 ℃ is only 0.004 g/cm3 (max.) higher than that of the drilling fluid at 25 ℃. This excellent rheological property is beneficial to the borehole wall stability and borehole cleaning in drilling the shallow formations in deep waters with narrow safe drilling windows. This drilling fluid also shows excellent performance in inhibiting the formation of gas hydrate. At 4 ℃ and 20 MPa, gas hydrate is completely inhibited in 20 h. After aging for 10 d and being contaminated with drilled cuttings, the drilling fluid still retains good inhibitive capacity, and is able to decompose the gas hydrate formed. The contents of heavy metals in the additives used to formulate the drilling fluid meet the requirements of relevant standards, the EC50 and LC50 of the drilling fluid are all greater than 30 000 mg/L, satisfying the needs of first-level environment protection in the sea area in China. The overall technical performance of this drilling fluid satisfies the technical requirements of drilling natural gas hydrate in offshore area.
MA Yongle, ZHANG Yong, LIU Xiaodong, et al.A drilling fluid which inhibits formation of natural gas hydrate at low temperatures in offshore drilling[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：544-551. doi: 10.12358/j.issn.1001-5620.2021.05.002.
Abstract: The oil-based drilling fluid presences the problems of difficulty to remove filter cake and treat oily cuttings. Based on the intelligent regulation mechanism of the pH stimulus-responsive emulsifier on the emulsion type, a pH-responsive reversible emulsifier RE-HT was synthesized through Hoffman reaction with 1-Bromo long-chain Alkane R and Diethanolamine to solve these problems. And a reversible emulsion drilling fluid was developed by utilizing it as the core agent. The infrared spectroscopy analysis and emulsion acid/base thixotropy test showed that the synthesized product contains the pH-responsive tertiary amine group and can be flexibly switched between water-in-oil emulsifier and oil-in-water emulsifier under acid/alkali stimulation. Thermogravimetric analysis and electric stability tests showed that the initial thermal decomposition temperature of RE-HT in an air atmosphere is as high as 257 ℃, and the demulsification voltage of the basic emulsion with 5% RE-HT is 1098 V after aging at 220 ℃. This indicated that it has good thermal stability and emulsifying performance. The developed reversible emulsion drilling fluid has good basic performance and can tolerate high-temperature up to 200 ℃, saturated saltwater contamination up to 15%, and drilling cuttings contamination up to 15%. The filter cake removal rate after pickling is 98.98%, the oil content of cuttings after pickling is less than 1%, EC50 is 2.05×105 mg/L, meeting the cuttings discharge standard and exhibiting a good application prospect in complex deep wells drilling.p wells drilling.
WANG Guoshuai, JIANG Guancheng, HE Yinbo, et al.Synthesis and evaluation of a ph stimulus-responsive high temperature-resistant reversible emulsifier[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：552-559. doi: 10.12358/j.issn.1001-5620.2021.05.003.
Abstract: Solidifying lost circulation materials (LCMs) are always used to control severe mud losses into fractured formations, they control mud losses by forming whole plugs near the borehole wall in the fractures. The solidifying LCMs entering the wellbore often inevitably are mixed with formation fluids. The volume distribution of the LCM slurry and the formation fluids changes with time and location, and is closely related to the physical-chemical properties of the formation fluids, the operation parameters and the geometry of the fractures. Using the computational fluid dynamics (CFD) method, the effects of the density and rheology of solidifying LCM slurries on the volume distribution of the LCM slurry and the formation fluids in the fractures and the flow velocity of the fluids were studied. In this study a 3D wellbore-vertical fracture model was used, the pressure differential used in the simulation was 1.9 MPa, the flow rate of the LCM slurry at the entry of the fractures was 2.5 m/s, the two-phase model was a VOF model, and the in-situ fluids in the wellbore and the fractures were a water based drilling fluid. The simulation results showed that the density and the yield point of the LCM slurry have little effect on the movement of the LCM slurry in the wellbore and the fractures, while the consistency index and the flow index significantly affected the residency of the LCM slurry in the fractures; the higher the consistency index and/or flow index, the lower the flow rate of the LCM slurry inside the fractures, and the higher the volume fraction of the LCM slurry inside the fractures. When the flow rate of the LCM slurry is less than the critical flow rate, the fractures will always be filled with the mixture of the LCM slurry and the drilling fluid. Compared with consistency index, flow index plays a more important role in affecting the residency of LCM slurries in formation fractures. LCM slurries of the Newtonian fluids and the shear-thickening fluids more easily form whole plugs in a fracture. This CFD simulation provides a theoretical basis for the optimization of the rheology of solidifying LCM slurries and is beneficial to the success rate at first try of controlling mud losses with the solidifying LCM slurries.
LIU Fan, CHENG Rongchao, HAO Huijun, et al.Simulation study on movement of solidifying lcms for controlling mud losses into fracturing formations[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：560-567. doi: 10.12358/j.issn.1001-5620.2021.05.004.
Abstract: Abstract To investigate the effects of temperature and pressure on the rheological characteristics of oil based drilling fluids under coupled high temperature and high pressure, the rheology of four high temperature oil based drilling fluids with densities of 1.4 g/cm3, 1.8 g/cm3, 2.2 g/cm3 and 2.4 g/cm3 was measured at coupled high temperature high pressure conditions with a Rheometer Fann iX77 which is able to measure the rheology of drilling fluids with ultra-high densities at elevated temperatures and pressures. It was found that the apparent viscosity and the plastic viscosity of the four oil based drilling fluids gradually decrease with increase in temperature and gradually increase with increase in pressure. The yield points of the four drilling fluids first increase and then decrease with increase in temperature. When the temperature was increased to above about 160 ℃, the effect of high temperature on the rheology of the four drilling fluids was greatly weakened. In addition, a mathematical model involving temperature and pressure of the oil based drilling fluids was obtained based on the analyses of the rheological parameters measured of the four drilling fluids under coupled high temperature and high pressure. Error analysis results show that the model has a good fit to the measured parameters in the experiment of the drilling fluids with different densities, with the coefficient of determination R being greater than 0.96. It is thus determined that the mathematical model can be used to accurately predict the rheological characteristics of oil based drilling fluids under each coupled temperature and pressure condition.
XIE Chunlin, YANG Lili, JIANG Guancheng, et al.Rheological characteristics of oil base drilling fluids and its mathematical model under coupled hthp conditions[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：568-575. doi: 10.12358/j.issn.1001-5620.2021.05.005.
Abstract: In the field application of high performance water based drilling fluids, several technical problems have been encountered, such as complex composition, properties difficult to adjust and control, as well as excessive biotoxicity and heavy metals. To solve these problems, an environmentally friendly filter loss reducer EFR-1 was developed with a natural high molecular weight polymer and an inorganic nanocomposite through hydrophobic association and grafting modification. Laboratory evaluation of the EFR-1 filter loss reducer showed that EFR-1 is able to function normally at high temperatures up to 170 ℃. Saturated saltwater drilling fluids treated with EFR-1 have filtration rate of only 14.8 mL, EC50 (biological toxicity) of 96 500 mg/L and BOD5/CODCr (biodegradability) of 18.56%. The use of EFR-1 helped solve the mutually restraining problems such as temperature resistance, salt resistance and environmental friendliness. A high performance water based drilling fluid HPHB was developed with EFR-1. HPHB, a drilling fluid of simple composition, has stable rheology and filtration property in field operations, its HTHP filter loss is only 7.8 mL and EC50 of 56 800 mg/L. HPHB has been successfully used on 20 wells drilled in Shengli Oilfield and Zhunzhong block in Xinjiang. Hole sections drilled with this HPHB drilling fluid have percent hole enlargement of less than 5%. The HPHB drilling fluid is not only technically feasible, but also environmentally friendly, it has provided a technical support to the “green” development of complex oil and gas reservoirs buried in deep/ultra-deep formations and in deep waters, as well as the “green” development of unconventional oil and gas reservoirs.
SU Zhenguo, WANG Ruihe, LIU Junyi, et al.Study and application of environmentally friendly high performance water base drilling fluid[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：576-582. doi: 10.12358/j.issn.1001-5620.2021.05.006.
Abstract: SEM experiment on core samples, X-ray diffraction experiment on drilled cuttings, as well as studies on regional geology data were performed in an effort to solve mud loss problem encountered in drilling the Liujiagou formation-Shiqianfeng formation in the east of Ordos Basin. The experimental result and the studies show that destabilization of rigid formations in contact with water and reticular fractures developed in the rigid formations are the main causes of severe mud losses and difficulties in controlling mud losses in this area. The rigid formations have high contents of illite and chlorite, and low contents of kaolinite and montmorillonite. It was decided to inhibit the destabilization of fractures in the formation in contact with water and to plug the fractures of different sizes with compounded bridging lost circulation materials (LCMs) containing particles of different sizes. A graded LCM slurry and techniques of using the LCM slurry were developed through laboratory experiment. The graded LCM contains 0.4%-0.8% bio-gel thickening agent, 5%-7% compounded LCM Ⅱ and rigid particles. Application of this LCM slurry on 8 wells showed that this technique was able to effectively plug mud losses into fracturs of 6mm in width. After the mud losses were stopped, the pressure bearing capacity of the loss zone became high enough to satisfy the needs of subsequent drilling operation, and no mud losses ever happened thereafter. The experimental results show that the graded LCM is suitable for controlling mud losses into complex fractured formations in the Liujiagou formation – Shiqianfeng formation in the east of Ordos Basin, and is worth popularizing.
ZHAO Hongbo, YANG Song, CHEN Guofei, et al.Study and application of mud loss control technique with graded lcms in the east of Ordos basin[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：583-592. doi: 10.12358/j.issn.1001-5620.2021.05.007.
Abstract: A lost circulation material (LCM) TP-C was developed for use in oil base muds to improve the residence of LCMs and the stability of the resident LCMs in fluid loss channels. TP-C is made by blending an amorphous lipophilic polymer AP, a crystalline polymer polypropylene (PP) and some other additives. In high temperature oils, the AP component of TP-C absorbs oils and swells, acquiring surface adhesion property; the PP component of TP-C has a lattice structure which is able to effectively control the solubility of the AP component. In an oil of 80 ℃, TP-C can absorb oil that is 2-3 times of the volume of TP-C itself, and also retains elastic deformability and adhesive capacity. In an oil of 130 ℃, TP-C as a whole shows high elasticity and has good elastic strength. Through the synergy of adhesion and squeezing bridging, TP-C is able to effectively reside on the slick walls of a fracture. A lost circulation control slurry formulated with TP-C and other materials was developed to control mud losses; it can form a whole densely bonded plug inside a 2 mm fracture, thereby improving the stability and pressure bearing capacity (which is at least 7.5 MPa) of the formations which are effectively plugged by the LCM slurry.
ZHANG Xianmin, JIANG Xueqing, HUANG Ning, et al.Study on polymer blend used for controlling loss of oil based drilling fluids[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：593-597. doi: 10.12358/j.issn.1001-5620.2021.05.008.
Abstract: Borehole wall instability has long been a problem in the development of the terrestrial tight oil in the Songliao Basin (Daqing Oilfield). To understand the mechanisms of the borehole wall instability, SEM and X-ray diffraction were used to analyze the microstructure of the core samples and the mineral composition of clays taken from the wells drilled in the basin. Laboratory studies were conducted on several aspects that are related to the stability of borehole walls, such as the hydration capacity of the core and clay samples, the impact of the mud cake quality, the physical-chemical parameters, the plugging capacity and inhibitive capacity of the drilling fluids used on the stability of the borehole walls etc. Based on these studies, a KCl oligomer polyamine drilling fluid was developed. Study on this drilling fluid showed that it functions normally at temperatures as high as 120 ℃, the extreme pressure friction coefficient of the drilling fluid is 0.12, percent recovery of shale cuttings in roller oven test with this drilling fluid is greater than 96%, and it is resistant to contamination by invasion of 10% bentonite. This drilling fluid has been used on 20 tight oil wells in Daqing, no borehole wall instability was encountered. The average percent hole enlargement of these wells was less than 6%, and 90% of the wells were cemented with excellent job quality. Tripping of drill string during drilling and casing running were all conducted smoothly. Field application has proved that this KCl oligomer polyamine drilling fluid is able to improve the borehole wall stability of the tight oil wells drilled in the Songliao Basin, and its use has provided technical support to the efficient development of the tight oil in Daqing Oilfield and to the mitigation of downhole troubles.
HOU Jie, LI Haodong, YU Xingdong, et al.Mechanisms of borehole wall instability of terrestrial tight oil wells in songliao basin and drilling fluid countermeasures[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：598-604. doi: 10.12358/j.issn.1001-5620.2021.05.009.
Abstract: In the light of there are some problems in X oilfield of Bohai Sea, such as clay dispersion, soft mud shrinkage, sticking when tripping out, medium and high porosity and permeability in reservoir section. Through the optimization of rheology regulator, fluid loss reducer, lubricant, inhibitor and other main treatment agents, The formula of soilless drilling fluid suitable for Bohai X oilfield is formed, The formula is: Seawater+0.2%NaOH+0.2%Na2CO3+0.3%PF-VIS+0.3%FA-367+0.6%PAC+2.0%PF-Lube+2%K-HPAM+1.5%ultrafine calcium carbonate+1.5%dual solution temporary plugging agent+1%nanoplugging agent JF-1+HCOONa(depending on density),The drilling fluid does not use bentonite to structure, which can effectively reduce the damage to the reservoir, The rolling recovery rate of drilling fluid is over 90%. It has good thermal stability and anti cuttings pollution ability. The compressive strength of the plugging layer is more than 7 MPa, Sodium Sodium formate is selected as weighting agent of drilling fluid, and the corrosion rate of weighted drilling fluid on WM95S pipe is only 0.0359 mm/a.
WAN Liping, ZHANG Xiaolong, ZHANG Li, et al.Laboratory study on clay-free water-based drilling fluid in x oilfield of bohai sea[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：605-610. doi: 10.12358/j.issn.1001-5620.2021.05.010.
Abstract: Slim-hole well drilling not only costs less, it can also be used to revive old wells by sidetracking, making it a way of economic and effective development of oil fields. When drilling slim-hole wells, some problems, such as high annular pressure loss and difficulty in carrying drilled cuttings out of hole, need to be solved. In slim-hole well drilling in Dixi block, a new high efficiency drilling fluid was used. The rheology and hydraulic performance of the drilling fluid was designed for different intervals: turbulent flow was used to drill the formations on top of the Permian system. The low-shear-rate rheology of the drilling fluid can maintain the pump pressures below 24 MPa, and the inhibitive capacity and the density of the drilling fluid are two key factors for the stabilization of the borehole walls. In drilling the Carboniferous system, turbulent-laminar transition flow pattern was used to improve the gel strength of the mud, and helped maintain the pump pressures below 26 MPa. In this way the disturbing of the drilling fluid flow pattern to the borehole walls was minimized, the carrying capacity of the mud in the horizontal section was enhanced, and the ROP increased by 66.4%. Field application showed that this high efficiency drilling fluid has played a role in stabilizing borehole walls and increasing the ROP in the drilling operation in Dixi block.
FANG Yanwei, WU Yicheng, ZHANG Wei, et al.Study on application of high efficiency drilling fluid for sidetracking slim horizontal wells[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：611-615. doi: 10.12358/j.issn.1001-5620.2021.05.011.
Abstract: To minimize the negative effects of conventional asphalt filter loss reducers on the environment and to enhance the plugging capacity of oil based drilling fluids at elevated temperatures, a liquid filter loss reducer BZ-FLA was produced by stepwise modifying a tall oil asphalt (a tail from natural oil processing) with maleic anhydride (MA) and polyamine, and then dissolving the product of the modification in an environmentally friendly solvent oil. IR spectroscopy and NMR analyses have proved that the final product of the aforementioned reaction, BZ-FLA, is a crosslinking tall oil asphalt amide resin which is a condensate of MA modified resin acid and polyamines. Evaluation of the performance of a typical oil based drilling fluid and a clay-free oil based drilling fluid both treated with BZ-FLA showed that BZ-FLA functions well at temperatures as high as 180 ℃. Filter loss of the typical oil based drilling fluid treated with 0.75%-1.0% BZ-FLA is less than 4.0 mL, comparable to the filtration control performance of 3% conventional asphalt filter loss reducer. Oil based drilling fluids treated with BZ-FLA, asphalt and lignite filter loss reducers exhibit enhanced plugging capacity. BZ-FLA is also equally effective in reducing filtration rate of clay-free oil based drilling fluids.
ZHAO Chong, ZHANG Xianbin, QIU Zhengsong, et al.Synthesis of liquid tall oil asphalt amide resin and evaluation of its filtration control performance[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：616-622. doi: 10.12358/j.issn.1001-5620.2021.05.012.
Abstract: In the oil and gas development in the Shunbei block and the Beipo (north slope) block in the middle of Tarim basin, the set cement of conventional cement slurries is found to be hard and brittle, therefore micro gaps are easily to form during fracturing operation, damaging the integrity of the cement sheath. A new method for improving the elasticity and toughness of set cement has been developed through theoretical analysis and laboratory experiment, converting the high performance materials in conventional technology into high performance structure. The elasticity of set cement is improved using a hydrophilically modified poly-fluorine rubber powder, the toughness of the set cement is enhanced through the synergy of organic and inorganic fibers, and the strength of the set cement is increased by improving the microstructure of the set cement with nano-silica. A high temperature elasticity and toughness enhancer was developed. As a cost-effective additive, it works properly at high temperatures up to 150 ℃, it is able to reduce the elastic modulus of set cement by 37.13% and helps the set cement to maintain a higher strength at the same time. Using this high temperature elasticity and toughness enhancer as the key additive, a cement slurry with high temperature elasticity and toughness was formulated with other additives selected through careful evaluation. The cement slurry has good rheology and proper thickening time. The API filter loss of the cement slurry is 45 mL, the elastic modulus and the compressive strength of the set cement are 6.089 GPa and 30 MPa respectively, satisfying the needs of oil and gas well cementing. The development of this cement slurry has set a foundation for the popularization of high temperature high strength high toughness cement slurries.
LI Fei.Study on optimization of high temperature cement slurry with elasticity and toughness[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：623-627. doi: 10.12358/j.issn.1001-5620.2021.05.013.
Abstract: In heavy oil fire flooding, the downhole set cement was experiencing steam huff and puff and steam flooding at first, and then heavy oil in-situ combustion. Based on these actual working conditions, an ultra-high-temperature set cement curing device and high temperature high pressure corrosion test kettle were used to study the changing pattern of the compressive strength and corrosion depth of set cement affected by CO2 under cumulative working conditions. Also, XRD and SEM were used to investigate the effect of CO2 on the chemical structure and micromorphology of set cement. Experimental results showed that set cement after curing at normal and high temperatures has high porosity and permeability, and low strength. The same set cement, when curing in CO2 corrosion test kettle under cumulative working conditions, the compressive strength increases to the contrary; the compressive strength of the set cement was increased to 53.4 MPa when curing for 28 days, increasing by 54.87% compared with the compressive strength of the set cement after steam flooding. With the corrosion of the set cement by CO2 going on, the corrosion depth on the set cement was gradually deepened, and the structure of the set cement was becoming denser, and after 28 days the set cement was fully carbonized. The reason for this phenomenon is that the corrosion product CaCO3 has low solubility, it precipitates and crystalizes inside the pores in the set cement. The crystal plugs the capillaries in the set cement, or just divides the big pores into smaller pores, thereby increasing the packing density of the cement particles. The results of this study further enrich the industry’s understanding of CO2 corrosion, and also provide reference to the performance evaluation and composition optimization of the heavy oil in-situ combustion cement slurries.
CHENG Tao, LIU Pengchao, OU Zhipeng, et al.Remediation of set cement in heavy oil thermal production wells with CO2 under cumulative working conditions[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：628-633. doi: 10.3969/j.issn.1001-5620.2021.05.014.
Abstract: Cementing of ultra-deep wells in the Keshen block in Tarim Basin is faced with many downhole problems such as salt and gypsum formation to be cemented, narrow clearance between casing string and borehole walls, high pressure, high temperature and big temperature difference etc., and poor quality of well cementing job is frequently seen in this area. Several measures have been taken to solve the problems encountered in well cementing. First, the borehole to be cemented was well prepared by engineered wiper trip, the formula for calculating the stiffness ratio was revised and the running of casing string was well controlled. Second, Laboratory experiment was conducted in selecting weighting agents and cement additives that are resistant to salt contamination and high temperature. Third, specific techniques were adopted to improve the resistance to high temperature and strength decline of set cement. Based on the experiment, an ultra-high density cement slurry was developed. Laboratory evaluation showed that this cement slurry has a fluidity of 18-22 cm. The difference of density between the top and the bottom of the cement slurry is 0.03 g/cm3. It has many advantages such as good flowability, high stability, good gas-channeling prevention capacity, high early strength and no long-term strength decline. The cementing technology based on this cement slurry and measures of using it formed the base of high quality well cementing job in Keshen block where ultra-deep wells were drilled through salt and gypsum formations. Five well times of field application gave high quality cementing job as indicated by sonic logging. The technology for cementing ultra-deep well penetrating salt/gypsum formations and with narrow clearance between liner string and borehole walls not only helped solve the difficulties encountered in well cementing, but also helped cement the high-pressure saltwater zones, ensuring the safe and efficient development of the Keshen block.
WANG Jingpeng, XIONG Youming, LU Zongyu, et al.Study on salt-resistant high density cement slurry technology for ultra-deep wells [J]. Drilling Fluid & Completion Fluid，2021, 38（5）：634-640. doi: 10.3969/j.issn.1001-5620.2021.05.015.
Abstract: Extension area of long 26 in Daqing oilfield is typical tight reservoir, which is more sensitive to fracturing fluid damage. According to ‘SY/T 5107-2005 Recommended practices on measuring the properties of water-based fracturing fluid’, the core displacement experiments of guar gum, high molecular polymer and surfactant fracturing gel-breaking fluids were conducted at reservoir temperature (90 ℃) with core flow meter, and the distribution of residue and residual gum of the three fracturing gel-breaking fluids in the cores and their damage degree to pore throats were evaluated with CT scanning. The results of core displacement experiments indicated that the core damage rates of guar gum, high molecular polymer and surfactant fracturing gel-breaking fluids were 43.5%, 24.3% and 13.1% respectively. The results of CT scanning showed that residues of guar gum and high molecular polymer fracturing gel-breaking fluids were concentrated in the first 1/10~2/5 and 1/2 sections of the core respectively, and the residues of surfactant fracturing gel-breaking fluid were less but penetrated into the core. The pore and the pore throat damage rates on cores of guar gum , high molecular polymer and surfactant fracturing gel-breaking fluids were 15.41% and 9.01%, 6.43% and 3.14%, 8.94% and 6.27% respectively. The analysis showed that the three kinds of fracturing gel-breaking fluids on reservoir cores were mainly liquid damage, followed by solid damage.
QI Shengjin, JIANG Jianfang, JIANG Jie, et al.Fracturing fluid damage evaluation and microscopic damage mechanism study for expansion tight oil test area of long 26[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：648-656. doi: 10.12358/j.issn.1001-5620.2021.05.017.
Abstract: Humic acid is sulfonated with sodium sulfite to produce sulfonated humic acid (SHA) which is mixed with carboxy methyl guar gum (CMGG) to form a new high temperature salt-resistant gel (SHA/CMGG) for use in fracturing fluids by crosslinking the mixture of SHA and CMGG with organic zirconium. Studies on the operational performance of fracturing fluids treated with the SHA/CMGG gel showed that the SHA/CMGG gel has better viscoelasticity and sand suspension capacity than the CMGG gel; a fracturing fluid treated with 0.3% SHA/CMGG has the best performance, the average settling velocity of sands in the fracturing fluid is 0.32 mm/min. The introduction of sulfonate ions into the humic acid molecules renders SHA/CMGG excellent salt resistance, the apparent viscosity of the SHA/CMGG treated fracturing fluid is decreased by 50% when contaminated with 1% salt. The fracturing fluid containing 0.3% SHA/CMGG has excellent high temperature and shear resistance, its viscosity, after shearing at 140 ℃ and 170 s−1, is 120 mPa·s and remains almost unchanged for 60 min. After gel breaking, the viscosity of the SHA/CMGG treated fracturing fluid and the permeability damage of cores are all increased, only with small magnitudes. Observation of the change of the microstructure of the fracturing fluid under SEM showed that SHA/CMGG gel has dense network structure which is important to the suspension of proppants in the fracturing fluid.
AN Na, LUO Pandeng, LI Yongshou, et al.Preparation of and study on sulfonated humic acid/guar gum fracturing fluid[J]. Drilling Fluid & Completion Fluid，2021, 38（5）：657-662. doi: 10.12358/j.issn.1001-5620.2021.05.018.
Competent Authorities：China National Petroleum Corporation Ltd
Sponsored by：CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
Address： Editorial Department of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province