Current Articles

2022, Volume 39,  Issue 3

Display Method:
The Synthesis and Evaluation of a High Temperature Organosilicate Polymer with High Inhibitive Capacity
ZHANG Fan, DU Weichao, SUN Jinsheng, LYU Kaihe, LIU Jingping
2022, 39(3): 265-272. doi: 10.12358/j.issn.1001-5620.2022.03.001
Hydrolysis and polycondensation (and hence crosslinking) of the organosilicon functional group in synthesis reactions is a technical problem that is often encountered. To solve this problem, a new organolsilicate polymer (ADMOS) was developed through emulsion polymerization with monomers such as acrylic acid (AA), vinylmethyldimethoxysilane (VMDS) and methacryloxy ethyl trimethyl ammonium chloride (DMC). 2,2'-azobis(isobutyronitrile) (ABIN) was used as initiator in the polymerization reaction. The optimum synthesis conditions are: molar ratio of the monomers AA∶DMC = 3∶1, the concentration of VMDS id 5.0% of the total mass of the monomers, the concentration of ABIN = 0.3%, the reaction temperature = 70 ℃, the total concentration of the monomers = 25%. and pH = 5. Using 1H-NMR, TGA and GPC, the molecular structure of ADMOS was determined. TGA measurement showed that ADMOS has excellent thermal stability. The inhibitive capacity of ADMOS was tested using linear expansion test, hot rolling test and mud ball immersion test. Liner expansion test results showed that the linear rate of expansion of clay cores was reduced from 83.37% measured by immersing the cores in water to 16.57% measured by immersing the clay cores in 3% ADMOS solution. Hot rolling test with water and 3% ADMOS solution showed that the percent recovery of shale cuttings was increased from 11.82% to 92.85%. Mud ball test showed that ADMOS can effectively hinders the invasion of water molecules into the interior of the mud balls, thereby inhibiting the hydration and dispersion of the clays. The inhibition mechanisms of ADMOS were revealed from a microscopic perspective through Zeta potential measurement, XRD, EDS, AFM and combined IR-TGA analyses.
Laboratory Study on Low Temperature Synthetic Based Drilling Fluid
LIU Gang
2022, 39(3): 273-278. doi: 10.12358/j.issn.1001-5620.2022.03.002
Oil based drilling fluid as the first choice of drilling complex formations has unwanted high viscosity and high gel strengths at low temperatures below zero degree Celsius. To solve this problem, a low temperature synthetic based drilling fluid was developed with low temperature emulsifiers, low freezing point gas-to-oil as oil phase, 30% CaCl2 solution as the water phase, and other optimized flow pattern modifiers. This synthetic based drilling fluid has properties that can be as good as those of oil based drilling fluids. At density of 2.0 g/cm3, the synthetic based drilling fluid, after aging at 180 ℃ for 16 hours, still had viscosity, gel strengths, electrical stability and flow property perfectly suitable for normal operation at -10 ℃. The HTHP filtration rate of this drilling fluid was less than 2 mL. This drilling fluid can effectively prevent downhole troubles arising from high equivalent circulating densities (ECD) and pipeline blocking caused by low temperatures.
The Development and Application of High-Temperature and High-Performance Water Base Drilling Fluid on the well Shunbei 801X
LI Ke, ZHAO Huaizhen, LI Xiuling, ZHOU Fei
2022, 39(3): 279-284. doi: 10.12358/j.issn.1001-5620.2022.03.003
The well 801X in Shunbei area is a key exploratory well located in the Shuntuoguole block in Tarim Basin. This well has total depth of 9,145 m, maximum well angle of 71° and horizontal displacement of 1,075.77 m. To deal with the high temperature high pressure problems encountered during drilling, a high performance water based drilling fluid with density of 2.0 g/cm3 was developed by high temperature additive selection and drilling fluid parameter optimization. Laboratory experimental results have shown that this drilling fluid can function normally at temperatures up to 200 ℃. It has good rheology at high temperatures and can effectively plug the microfractures developed in the shale formations. Filtration rate of this drilling fluid at 180 ℃ was 13.8 mL, and the mud cake was thin and tough. This drilling fluid can also stand the contamination from CO32-, HCO3- and salt water. Field application has shown that this drilling fluid had stable properties in drilling the high temperature formations, and its properties were easy to maintain. Tripping of drilling tools was done smoothly, and no downhole troubles were encountered. The well was safely drilled in high rate of penetration. In well testing, the converted oil and gas equivalent was 1,007.6 t. The development of this drilling fluid has provided a useful reference for the optimization of drilling fluids for subsequent drilling operations in the Shunbei block.
Research on On-line Detection Method of Marsh Funnel Viscosity Based on Pressure
CHEN Hui, MA Shaohua, HUANG Jinyun, WANG Hanxiang, ZHAO Yuming, GONG Zhaoyang, YANG Jinsong
2022, 39(3): 285-293. doi: 10.12358/j.issn.1001-5620.2022.03.004
An online method of measuring Marsh funnel viscosity was presented and a set of online measurement device developed to overcome the problems existed in field manual measurement of Marsh funnel viscosity, such as heavy workload, low measuring precision and measuring discontinuity. In developing the online measuring method, the online measurement process was studied from several aspects, such as the principle of the Marsh funnel viscosity measurement, the structure of the Marsh funnel and algorithm of calculating of viscosity measured with the new instrument. The relationship between the height of the liquid level in the funnel and the pressure of the liquid column is used to calculate the funnel viscosity. The accuracy of the new instrument was verified through analog and emulation, and field experiment in Zhongyuan Oilfield, the precision of the instrument was determined to be ±1 s. By comprehensive analyses of the factors affecting the measurement of funnel viscosity of drilling fluids, the online measurement method was optimized in several aspects, such as the shape of the outlet, the modification technique of the funnel and detection of the liquid level. Measurement error caused by density of the drilling fluid is less than 3%, and the error by viscosity of the drilling fluid is less than 2%. This method and the instrument can be used to realize online measurement of the viscosity of the liquid drilling fluids, and have good applicability and high degree of automation. Satisfying the need of precise measurement of the funnel viscosity of drilling fluids, the online measurement method and the instrument can be used to replace the manual measurement presently in use, improving the intelligence level of oilfield operations.
A High Temperature Gel Plugging Agent
ZHOU Xinyu, LIU Jingping, LYU Kaihe, SUN Jinsheng, ZHANG Wenchao, TENG Yuxiang
2022, 39(3): 294-300. doi: 10.12358/j.issn.1001-5620.2022.03.005
Gel plugging agents have the characteristics of strong self-adaptation, their use in drilling fluids, on the other hand, has the shortage of poor thermal stability. To overcome this shortage, a new gel plugging agent, PPAA, was developed with poly vinyl alcohol (PVA), acrylic acid (AA) and acrylamide (AM) as the reaction monomers, N, N-dimethyl bisacrylamide (MBA) as the crosslinking agent and ammonium persulphate as the initiator. PPAA functions normally at temperatures as high as 180 ℃. PPAA has low expansion factor, minor effect on the rheology of mud, and is able to control the filtration rate of the mud. A drilling fluid containing 2% PPAA, after aging at 180 ℃, can invade into a 80 – 100 mesh sand-bed by 2.6 cm, and the plugging efficiency of the mud is 60.6% higher than that of a mud treated with conventional plugging agents. Compared with conventional plugging agents, 6% NaCl solution treated with PPAA has efficiency of plugging increased by 48.6%, and the HTHP filter loss through sand plate reduced by 69.7%.
Synthesis and Application of an Environmentally Friendly Modified Bio-Peptide Shale Inhibitor for Water Based Drilling Fluids
XU Yi, XU Guili, JIANG Guancheng
2022, 39(3): 301-306. doi: 10.12358/j.issn.1001-5620.2022.03.006
As more and more attentions have been paid to environment protection, the conventional polymer-sulfonate drilling fluid additives are gradually inevitably replaced by environmentally friendly additives. An environmentally friendly modified bio-peptide shale inhibitor, WNGT, has been developed based on molecular structure design of the bio-peptide gelatin. NMR spectrum of the modified gelatin has shown that two distinct new characteristic peaks appeared at the chemical shifts of 3.19 ppm and 4.12 ppm, respectively, indicating that the target product was successfully prepared. Results of the linear expansion test showed that the expansion length of the core tested with WNGT was shorter than two other additives, which were KCl and polyetheramine (PEA), at the same concentration, indicating that WNGT had the best inhibitive capacity in the three shale inhibitors. WNGT has the excellent clay hydration suppressing ability; at a concentration of 2%, the expansion length of the clay core in 24 hours was only 1.60 mm. Percent shale cuttings recovery of the modified gelatin was at least 95%, 46.05% higher than that of the non-modified gelatin. A bentonite slurry treated with 2% WNGT had its Zeta-potential decreased to −11.7 mV, meaning that WNGT can effectively neutralize the negative charges of the clay, thereby compressing the electric double layer and reducing the Zeta-potential of the clay. This WNGT shale inhibitor has been used on a well located in Chuanyu area, where the well penetrated the Shaximiao sandy shale formation. When the drilling fluid was treated with WNGT, its viscosity and gel strengths were reduced to some extent, and this effect was maintained for a long time, ensuring the successful drilling of the sandy shale formation with the water based polymer drilling fluid and the reducing of drilling cost.
A Strongly Adsorptive Hydrophobically Modified Nano SiO2 Plugging Agent
TENG Chunming, ZHEN Jianwu, LUO Huiyi, JIANG Sichen
2022, 39(3): 307-312. doi: 10.12358/j.issn.1001-5620.2022.03.007
Downhole troubles such as borehole instability and mud losses are frequently encountered when drilling formations with poor stability and low pressure bearing capacity. Study and evaluation of new nano plugging agents have recently been performed to solve these problems. Study on these issues gave birth to a strongly adsorptive hydrophobic nano plugging agent. Measurement of the particle size distribution, adsorptive ability and wettability of the plugging agent, as well as plugging capacity test performed on sand-bed have shown that the particle sizes of the plugging agent was distributed in a range of 100-150 nm. The plugging agent has good adsorptive ability; it can increase the contact angle of water on the surfaces of shale to 80.7°. A mud sample treated with 2.5% of the plugging agent had its filtration rate through a sand-bed tester reduced to 5.0 mL. The plugging agent has little, if any, effect on the rheology of the drilling fluid. The API filtration rate of the drilling fluid was reduced by the plugging agent from 4.4 mL to 1.0 mL, and the HTHP filtration rate was reduced from 16.2 mL to 6.2 mL. At concentrations in a mud above 3.0%, the permeability of the mud cakes was reduced to 2.8 μD. PPA plugging efficiency test has shown that the plugging agent can form a plugging layer on a ceramic filter disk, the filtration rate was reduced to 0.45 mL/min1/2, and the spurt loss was reduced to 2.58 mL. The study has demonstrated that the strongly adsorptive hydrophobic nano plugging agent can enhance the plugging capacity of the drilling fluid, reduce the amount of filtrate invasion of the drilling fluid into the formation and effectively help stabilize the borehole wall.
Application of Ultra-low Friction Wwater-based Ddrilling Ffluid in Shale Gas Horizontal Wells
ZHOU Shanshan, ZHONG Chengbing, LIU Jie, DAI Yiqin, XU Mingbiao, HAN Yinfu, SONG Jianjian
2022, 39(3): 313-318. doi: 10.12358/j.issn.1001-5620.2022.03.008
Oil-based drilling fluid has excellent inhibition, blocking and lubrication properties, and it is currently the main type of drilling fluid for shale gas well operations. With the increasing pressure on environmental protection and waste mud disposal, shale gas drilling has put forward an urgent demand for water-based drilling fluid. Four horizontal wells are deployed in Fuling Jiao Shi, and the drilling target formation is Longmaxi Formation-Wufeng Formation. The target formation contains large sections of mud shale and fracture development, which is easy to hydrate and disperse, and has high risk of collapse and leakage. In response to the low friction requirement of the Fuling horizontal well and the vulnerability of the formation mud shale to well wall destabilization, an ultra-low friction water-based drilling fluid system was developed. The field application shows that the ultra-low friction water-based drilling fluid has achieved efficient and safe operation of the horizontal section of shale gas wells, with a 24.7% increase in mechanical drilling speed and a 6.2% reduction in drilling time per meter compared with oil-based drilling fluid in the same block. record. The successful application of this ultra-low friction water-based drilling fluid in Fuling shale gas is expected to realize the replacement of oil-based drilling fluid by water-based drilling fluid in shale gas.
Research and Application of Triassic Anti-collapse Drilling Fluid in Yueman Block on The South Bank of Tahe River
ZHU Jinzhi, YANG Xuewen, LIU Hongtao, YANG Chengxin, ZHANG Shaojun, LUO Chunzhi
2022, 39(3): 319-326. doi: 10.12358/j.issn.1001-5620.2022.03.009
Studies on the mechanisms of borehole wall collapse and the drilling fluid capable of controlling the borehole wall collapse were performed to solve the problem of bad borehole wall collapse happening in drilling the Triassic System in the Yueman block, south bank of Tarim river. The Triassic System is mainly composed of mudstones and sandy mudstones containing 28.6% clay minerals in which 45% is the mixed layer of illite and montmorillonite. When in contact with water the formation rocks absorb the water, and the compressive strength of the rocks decreases. On the other hand, the density of the drilling fluid used is less than the equivalent density calculated from the collapse pressure of the formations. These are the the immanent causes resulting in borehole wall collapse. In field operation, the drilling fluid used had high filtration rate, leaving a thick mud cake with poor toughness. Laboratory test with the drilling fluid showed that the percent recovery of shale cuttings is low, while the linear expansion rate is high. Other shortages of the drilling fluid include poor plugging capacity and bad particle size distribution. A new drilling fluid was formulated based on these findings using optimized filter loss reducers, compound inhibitive additives such as FTDA. This drilling fluid has low API and HTHP filtration rates, and the mud cake is thin and tough. The percent recovery of shale cuttings with this drilling fluid was increased by 15.7% compared with the old mud. Plugging test on sand-bed showed that the plugging capacity of the new drilling fluid was increased by at least 50%, indicating that the drilling fluid has reasonable particle size distribution. In field application, the new drilling fluid had stable rheology and low filtration rate, no pipe sticking and borehole sloughing were encountered. The average rate of hole enlargement was 10.35%, which is 50.24% lower than the average rate of hole enlargement of the wells drilled in the same block. The application of the new drilling fluid has provided a new technical clue for stabilizing the borehole wall of the wells penetrating the Triassic System in the Yueman block.
Response Surface Optimization of Biosafety Disposal of Waste Water Based Drilling Fluids for Deep Drilling
SUN Lulu, GENG Xiaoguang, SONG Tao, ZHANG Yang
2022, 39(3): 327-333. doi: 10.12358/j.issn.1001-5620.2022.03.010
Water based drilling fluids have been used to drill deep tight gas wells in Daqing Oilfield. In the treatment of the waste drilling fluids, it was found that the solids and the liquids were difficult to be separated from each other, the mud cakes had water-cut of greater than 80%, and secondary contamination existed in future operations. A study on the bio-safety disposal of waste water based drilling fluids was conducted to solve these problems. Based on the analyses of the characteristics of and difficulties in the treatment of the water drilling fluids, the Box-Behnken Central Composite Experiment and Response Surface Method were chosen as a means of study. By exploring the effects of the optimum ratio of gel breaker, coagulant aid and flocculant on the solid-liquid separation efficiency of the waste water based drilling fluids, a new mathematical model was established describing the relationship between the water-cut of mud cakes for solids-liquid separation and the treatment recipe parameters. A method for the biosafety disposal of waste water based drilling fluids was developed, with destabilization and flocculation as the core technique. Using the mathematical model and the biosafety disposal method, a destabilization-flocculation-solid-liquid separation technique was established. Field test results have shown that a waste water based drilling fluid, after treatment with the technique, formed a mud cake with water-cut of 47%, the suspension content in the mud cake leachate was 63 mg/L. Nine major pollution indices such as COD etc. of the waste drilling fluid conform to the requirements of the national standard GB 8978—1998 and the local standard DB23/T 693—2000, namely, “Waste Drilling Fluid Treatment Specification of Heilongjiang Province”. This technology provides an effective solution to the poor gel breaking and destabilization efficiency of the water based drilling fluids for deep hole drilling in Daqing Oilfield and has good promotion and application values.
Development and Evaluation of Sealant for Controlling Annular Pressure
LIU Haoya
2022, 39(3): 334-338. doi: 10.12358/j.issn.1001-5620.2022.03.011
Solid particles in conventional cement materials are unable to be squeezed into and seal the micro fractures developed in cement sheaths in annular spaces with sustained pressures. To solve this problem, a solids-free sealant that is curable at room temperature was developed, with a composite resin as the main component. In developing the sealant, the solidification time of the cement slurry was controlled by optimizing the amount of a curing initiator, and the mobility and permeability of the cement slurry were enhanced using an optimized thinner. The sealant was tested in laboratory for its performance in sealing the cement sheath-casing system. It was found that at different environment temperatures and different concentrations of the curing initiator, the curing time of the sealant can be adjusted between 1.25 hours and 20 hours. The sealant has good flow property; its viscosity is as low as 60 mPa∙s. The density of the sealant can be raised from 1.02 g/cm3 to 1.25 g/cm3. The sealant has good mechanical properties, its compressive strength in 24 hours is greater than 18 MPa, with maximum compressive strength of 53 MPa. Laboratory experimental results have shown that the sealant can be used to effectively solve the problem of sustained annular pressure. In dry environment, the sustained annular pressure less than or equal to 6 MPa can be eliminated after WOC for 24 hours. In wet environment, the sustained annular pressure less than or equal to 3 MPa can be eliminated after WOC for 24 hours. This sealant can be used to solve the sustained annular pressure problem in different conditions by improving the tightness of the cement sheath in annular spaces.
A Geopolymer Based Oil and Gas Well Cementing Material
SUN Gang, WANG Youwei, LIU Xinjun, YU Bin, ZHANG Guoliang, MA Chunfeng, LI Yi, TANG Donglin
2022, 39(3): 339-345. doi: 10.12358/j.issn.1001-5620.2022.03.012
Geopolymer is a kind of inorganic polymer made from alkali activator and gel material. It has a 3D network structure formed by SiO4 and AlO4 tetrahedra. Geopolymer has excellent mechanical performance, high bonding strength with inorganic substrate and good mobility. In oil and gas well cementing, the mud cakes remained on the borehole wall cause poor cementation of the cement sheath with the borehole wall. To solve this problem, metakaolin (MK) was added to form a geopolymer with the clays in the drilling fluid to improve the quality of well cementing operation. Using water glass and MK (at a concentration of 2.5%), a geopolymer based well cementing material with low viscosity and high porosity was developed. The glass modulus (M) of the geopolymer was 1.5, and it can effectively penetrate mud cakes at both normal and high pressures. After being solidified at 90 ℃ for 10 hours, the compressive strengths of the mud cake were 3.0 MPa and 1.0 MPa, respectively. Meanwhile, the solidified mud cakes can enhance the bonding strength of the cement sheath with the borehole wall, the bonding strengths of the “borehole wall – cement sheath” interface and the “casing – cement sheath” interface were 0.6 MPa and 1.0 MPa, respectively. XRD analysis revealed that although the addition of MK cannot change the crystallization property of the mud cakes after final solidification, it to some extent increases the concentrations of the gel materials in the mud cakes, which further increases the compressive strength and bonding strength of the solidified mud cakes.
Study on Selection of Weighting Agent for Hhigh-Ttemperature and High-Density Anticorrosive Cement Slurry
WU Zhongtao, SONG Jianjian, LIU Weihong, ZHAO Jun, XU Mingbiao, WANG Xiaoliang
2022, 39(3): 346-351. doi: 10.12358/j.issn.1001-5620.2022.03.013
High temperature high pressures wells rich in CO2 are often faced with the corrosion of cement sheaths. In this study, a suitable weighting agent for high temperature high density corrosion inhibitive cement slurries was selected, and the effects of three weighting agents on the properties of cement slurries were compared. These three weighting agents include manganese ore powder, hematite and barite, which have the same particle size distribution. The corrosion test was performed at 150 °C and CO2 partial pressure of 20 MPa. The study results showed that the cement slurry weighted with manganese powder requires the least amount of water, and thus has good rheology and lower filtration rate in the same conditions. The set cement of the manganese powder treated cement slurry has the lowest permeability and higher compressive strength after corrosion test. After 30 d of corrosion, the corrosion depth of the manganese set cement is the minimum among others, the corrosion depth of the barite set cement is 1.5 times of the corrosion depth of the manganese set cement. After corrosion, the manganese set cement has the densest structure, and the characteristic peak of the corrosion products is the lowest. Among the three cement slurries treated with 25%, 50% and 75% manganese ore powder respectively, the corrosion depth of the set cement from the cement slurry containing 50% manganese ore powder is the minimum after 27 d of corrosion. Compared with the other two weighting agents, the manganese ore powder is a better choice, only over treatment of the cement slurry with the manganese ore powder should be avoided to prevent negative effects on the corrosion property of the cement slurry.
Synthesis and Study of an Ultra-High Temperature Filtrate Reducer for Cement Slurries
YU Yongjin, ZHANG Hang, XIA Xiujian, LI Pengpeng, JIN Jianzhou, HU Miaomiao, GUO Jintang
2022, 39(3): 352-358. doi: 10.12358/j.issn.1001-5620.2022.03.014
An ultra-high temperature filtrate reducer, F-SHT, was developed for formulating cement slurries used in ultra-deep wells and complex wells with ultra-high well temperatures. The development of F-SHT has broken through the bottleneck of ultra-high temperature water loss control of conventional filter loss reducers for cement slurries. Characterization of the molecular structure and performance evaluation of F-SHT showed that F-SHT has a number average molecular weight of 21,475 Da and low apparent viscosity which is benefit to the formulation of cement slurries. Significant thermal weight loss occurred when the temperature reaches 294 ℃, indicating that the molecular chains of F-SHT has good thermal stability. F-SHT can effectively control the fluid loss of cement slurries at temperatures up to 240 ℃ and in salt-saturated cement slurries. In static filtration test, a salt-saturated cement slurry treated with F-SHT had API filtration rate of 38 mL at 240 ℃/6.9 MPa. In general performance testing, the performance of the cement slurry at starting and halting of the machine, the stability and API filtration rate of the cement slurry were all qualified. In cementing the Φ177.8 mm liner string of the well Heshen-1, F-SHT performed successfully; the cement slurry best suited the situation of the well condition, the quality of the well cementing job was good, and the well cementing job provided a strong support to the exploration of oil and gas resources buried in ultra-deep formations.
Effects of Drilling Fluid Encapsulators on Well Cement Slurries
ZHAO Shuxun, ZUO Tianpeng, CHEN Xu, ZHENG Yijie, CHENG Xiaowei
2022, 39(3): 359-364. doi: 10.12358/j.issn.1001-5620.2022.03.015
When a drilling fluid is mixed with a cement slurry, the flow of the mixture will become very poor. In a laboratory study, the effects of drilling fluid encapsulators on the thickening time, rheology and the compressive strength of cement slurries were investigated. Using IR, XRD and SEM, the mechanisms with which the cement slurries are contaminated by the drilling fluid encapsulators are studied. Electric conductivity method was also used to evaluate the changes of the electric conductivity of cement slurries before and after the cement slurries are mixed with drilling fluid encapsulators. The study results showed that the mobility of a cement slurry is reduced when an encapsulator is mixed with the cement slurry; a pure cement slurry contaminated with 0.6% encapsulator has its mobility reduced by 52%. Electric conductivity experiment showed that the hydration process of a cement slurry, which is contaminated with a drilling fluid encapsulator, begins accelerated only after 12 hours of hydration. The mixing of a drilling fluid encapsulator into a cement slurry will slow down the hydration process of the cement slurry, leading to a slow development of the compressive strength of the cement slurry. A cement slurry containing 0.2% drilling fluid encapsulator and cured at 90 ℃, has a 3 d strength that 12.8% lower than that of the pure cement slurry. The adsorption groups in the molecules of the encapsulator, such as —OH, —CONH2, —COO- etc., can be adsorbed onto the particles of the cement, and the hydrophilic groups of the encapsulator can form hydrogen bond with the Si—O bond in the cement molecules, thereby forming a solvent film on the surfaces of the cement particles, which in turn hinders the contact of water with the cement particles.
Study and Evaluation of Highly Permeable Retarded Acids
LIU Fanghui, ZHANG Shikun, CAO Nai
2022, 39(3): 365-372. doi: 10.12358/j.issn.1001-5620.2022.03.016
In acid fracturing carbonate reservoirs, the quality of the acid directly affects the quality of the stimulation. Problems with the acids presently used in fracturing operation include low permeability, high corrosion rate and poor retarding performance. To solve these problems, an acid used as the main component of a compound organic retarded acids, a drag reducer for acidizing operation, a corrosion inhibitor and an iron ion stabilizer were selected to formulate a new high permeability retarded acid suitable for use in acidizing carbonate reservoirs. Laboratory experimental results showed that this new retarded acid has good retarding performance, low corrosion rate and better permeating ability. This study is of theoretical guiding significance and practical application value for fully and efficiently developing carbonate reservoirs.
Research on Proppant Migration Law of Fractures in Ccontinental Shale Ggas Rreservoir
MA Chunxiao, XING Yun, LUO Pan, GAO Zhiliang, ZHANG Fengsan, CHENG Xin, WU Jinqiao
2022, 39(3): 373-382. doi: 10.12358/j.issn.1001-5620.2022.03.017
In order to study the proppant migration law of fractures in continental shale gas reservoirs, a visual fracture simulation system was used to carry out proppant migration and settlement experiments, which simulated the process of proppants migration and settlement under the conditions of different fracturing fluid viscosities, displacements, sand ratios, proppant particle sizes and proppant densities. At the same time, the PIV particle velocimetry technology was used to draw the velocity fields at the entrance and the front edge of the sand bank, aiming to further analyze the particles movement characteristics during the migration process. And the following research results were obtained. The migration process of proppants in artificial fractures is divided into four stages: the early stage, the middle-early stage, the middle-late stage and the equilibrium state. At the entrance of the fracture: the velocity of suspended particles is approximately horizontal, and the velocity of particles on the surface of the sand bank is upward along the slope. The propulsion of proppants mainly depends on the carrying effect of liquid viscous force; As the displacement increases, there will be obvious disturbances in the flow field. When the displacement is greater, the degree of disturbance is stronger. At the front edge of the sand bank: There is an obvious vortex phenomenon in the flow field at the top of the slope; The viscosity of the liquid increases, the strength of the vortex is weakened, and the viscous force increases. Under the impact and carrying effect of the liquid, the particles lay farther away; As the displacement increases, a larger vortex appears in the entire front edge area, and the vortex action becomes stronger. At this time, the impact of the liquid makes the proppants placement better; When the sand ratio increases, the number of vortices increases, the strength of vortices intensifies, the spread range enlarges, and the proppants migrate to the farther end of the fracture. When the proppants particle size in slippery water is smaller and the density is higher, the sand bank becomes more uniform, but to achieve the required effect, the sand-carrying liquid is needed.
The Development and Application of an Integrated Multifunctional Salt-Resistant Thickening Agent
LUO Lei, WANG Yuan, QU Gang, YANG Yuheng, JIA Fei
2022, 39(3): 383-389. doi: 10.12358/j.issn.1001-5620.2022.03.018
An integrated multifunctional salt-resistant thickening agent was synthesized with acrylamide and sodium acrylate as the main raw materials to satisfy the needs of fracturing fluids, which are formulated in blocks where only high salinity salt waters are available, for integrated requirements such as instant capacity, salt-resistance, friction reducing, high temperature and shearing tolerance, as well as cleanup. In the inverse emulsion polymerization of the thickening agent, salt-resistant monomers were used to render the thickening agent salt-resistance. Laboratory test on a fracturing fluid treated with the synthesized thickening agent has shown that the viscosity developing rate of the thickening agent in waters of salinity between 50,000 mg/L and 60,000 mg/L in 30 s was at least 85%. The fracturing fluid formulated with this thickening agent had rate of friction reduction of at least 75% at a simulated flow rate of 10 m3/min generally used in field operations. After shearing at 170 s-1 and 90 ℃ for 90 min, the fracturing fluid still had viscosity of more than 30 mPa∙s. Without using cleanup additives, after complete gel breaking, the fracturing fluid had surface tension of at least 24.65 mN/m, interfacial tension of at least 1.06 mN/m, and residue content of less than 30 mg/L. This thickening agent has been tried on a well in block MH in Xinjiang Oilfield, the fracturing fluid was formulated with diluted saltwater from a salt lake. The different jobs can be easily switched between each other, no cleanup additives were required, and the fluid had stable properties, satisfying the needs of the field operation.
Study on Fracturing Fluid Formulated with Ultra-High Temperature Retarded Crosslinking Polymers
WANG Chao, CUI Mingyue, ZHANG Xu, ZHAO Zhongcong, ZHANG Xiwen
2022, 39(3): 390-396. doi: 10.12358/j.issn.1001-5620.2022.03.019
Plant gum thickening agents and their derivatives used in water based fracturing fluids have some shortages such as high residue content, poor thermal stability and easy spoilage. To solve these problems, a new thickening agent was developed with acrylamide (AM), a functional monomer SP and 2-Acrylamido-2-methylpropane sulfonic acid (AMPS) as the reaction monomers. In laboratory synthesis of this new thickening agent, based on the free radical polymerization of water-soluble polymer theory, the effects of the various synthesis conditions (such as concentration of the initiator, reaction temperature, pH of the reaction system, polymer concentration, content of the chain transfer agent and the degree of hydrolysis) on the performance of the final thickening agent were studied. Using the method of control variates, the reaction conditions are as follows: Polymer concentration = 25%, ratio of monomers (AMPS∶SP∶AM) = 30%∶25%∶45%, reaction temperature = 20 ℃, concentration of initiator = 0.3%, pH = 7, mass fraction of sodium formate = 0.2%, reaction time = 4 h. The thickening agent synthesized has good high temperature resistance, low water insoluble and high thickening capacity. It is instantly soluble and can be easily crosslinked with the organozirconium crosslinking agent. This thickening agent can be used in formation temperatures as high as 200 ℃.