2019 Vol. 36, No. 3

Display Method:
2019, 36(3)
Outlook on the Research on Intelligent LCM with Temperature Sensitive Shape Memory Property
BAO Dan, QIU Zhengsong, ZHAO Xin, YE Lian, ZHONG Hanyi
2019, 36(3): 265-272. doi: 10.3969/j.issn.1001-5620.2019.03.001
Lost circulation has long been a worldwide problem that harasses oil and gas drilling and exploration operations. Development of new lost circulation materials (LCM) of high efficiency is the key in controlling and preventing lost circulation. Based on the advanced idea and methods of intelligent material science, the type, characteristics and working mechanisms of shape memory intelligent LCM are discussed and analyzed. Status quo of studying on the intelligent LCM with temperature sensitive shape memory both in China and abroad is introduced. This paper also discusses the self-adaptive fracture sizes which the intelligent LCM with temperature sensitive shape memory LCM can be used, and the lost circulation control property and working mechanism of temperature sensitive intelligent LCM with high pressure bearing capacity. Suggestion and outlook are presented to the preparation, evaluation methods and field application techniques of temperature sensitive shape memory LCM which may lead to the innovation of lost circulation control and prevention technologies.
Effect of Density on the Performance of Oil Base Drilling Fluids
PAN Yidang, YU Peizhi
2019, 36(3): 273-279. doi: 10.3969/j.issn.1001-5620.2019.03.002
In field use of high density oil base drilling fluids, it was found that the properties of the oil base drilling fluids become unstable with increase in mud density. Laboratory study shows that addition of barite increases the viscosity and gel strength, and enhances the emulsion stability of oil base drilling fluids. There is a linear relationship between the electric stability potential and the concentration of barite. An oil base drilling fluid, when at higher densities, has an apparent viscosity that is affected by temperature, oil/water ratio, concentrations of organophilic clay and poor quality solids to a larger extent than when it is at lower densities. Also, an oil base drilling fluid, when at higher densities, has an electric stability potential that is affected by oil/water ratio, concentrations of CaCl2 and organophilic clay to a larger extent than when it is at lower densities. Summarization of laboratory studies shows that increase in the density of an oil base drilling fluid not only affects the properties of the drilling fluid, it also increases the sensibility of the fluid to other factors. Thus, when using high density oil base drilling fluids, the monitoring and adjustment of the properties of the drilling fluids should be strengthened.
An Ultra-high Density Diesel Oil Base Drilling Fluid for Use at 160℃
YIN Da, WU Xiaohua, LIU Fengbao, XU Tongtai, YAN Zhihang, ZHAO Xurong
2019, 36(3): 280-286. doi: 10.3969/j.issn.1001-5620.2019.03.003
Increasing demands of oil worldwide is driving oil and gas exploration and development to deeper and unconventional petroleum reservoirs, and high temperature ultra-high density oil base drilling fluids are required to drill the wells. The high temperature ultra-high density oil base drilling fluids should have good rheology, low HTHP filtration rate, good plugging performance and good dynamic/static settling stability. An ultra-high density oil base drilling fluid used at 160℃ has been developed in laboratory. large amount of experiments show that, using barite, an ultra-high density diesel oil base mud with good rheology and good dynamic settling stability cannot be obtained. The composition of the ultra-high density diesel oil base drilling fluid, with its density changing from 2.4 g/cm3 to 3.0 g/cm3, is as follows:0# diesel oil and 25% CaCl2 water solution in a ratio of 90:10 as the base fluid, organophilic clay, 0.8% primary emulsifier, 1% secondary emulsifier, 1% wetting agent, 5% filter loss reducer, 3% CaO and weighting agent (Barite:Micromax=6:4). The concentration of the organophilic clay decreases with density; density of 2.4 g/cm3, 2.6 g/cm3, 2.8 g/cm3 and 3.0 g/cm3 corresponds to the optimum organophilic clay concentration of 1%, 0.5%, 0.3% and 0%, respectively.
Simulation Study on the Effects of Drilling Fluid on Gas Cut from Fractured Formations
FANG Junwei, ZHU Lixin, LUO Faqiang, ZHANG Jun, WANG Yong, HUANG Weian, NIU Xiao
2019, 36(3): 287-292. doi: 10.3969/j.issn.1001-5620.2019.03.004
Gas cut caused by gravity displacement is frequently encountered when drilling fractured formations. Well kick, mud loss and well blowout will happen if gas entering the wellbore from fractured formations is not correctly handled. When gas kick is happening, pressure fluctuation around the fractures will result in borehole wall instability. In laboratory studies, based on the analyses of the characteristic parameters of the fractures in Block Shunnan located in the north slope of Tazhong, the early stage modeling and meshing were done using the modelling software Gambit, and 3D models for wellbore and fractures were established. Using ANSYS Fluent hydromechanical software, a multiphase flow model was established with which the effects of the dynamic pressure at the mouth of a fracture on the stability of the borehole wall at the same place during gravity displacement were analyzed. Drilling data of a well, such as the density, viscosity and flow rate of the drilling fluid were used to analyze their effects on gas cut caused by gravity displacement. It was found that when gravity displacement took place, high pressure differential resulted in high instant flow rate of gas, which was then reduced to a low level in just 0.1 sec. The maximum dynamic pressure was found at the upper and lower ends of the fracture, while the minimum dynamic pressure was found at the middle-upper position of the fracture. The widths of the fracture at these three points were easy to increase, causing the wellbore to destabilize. Changes in the density and viscosity of the drilling fluid caused change in the dynamic pressure at the mouth of the fracture by only 6%. The steady rate of gas cut was also less affected by the changes in the density and viscosity of the drilling fluid. On the other hand, flow rate of the drilling fluid during gas cut greatly affected the dynamic pressure at the mouth of the fracture, causing the dynamic pressure to change by 66.9%, indicating that reduced flow rate of drilling fluid during gas cut is beneficial to bringing gas cut under control.
Development and Evaluation of a High Temperature Gelling and Degradable Polymer Lost Circulation Material
GUO Yongbin, YAN Bangchuan, HUANG Yi, LI Lei, JIANG Guancheng, DENG Zhengqiang
2019, 36(3): 293-297. doi: 10.3969/j.issn.1001-5620.2019.03.005
A polymerized modified gelatin crosslinking agent DGCL is developed through quaternization of gelatin with methacrylic anhydride. An initiator is successfully wrapped in ethylene vinyl acetate (EVA) particles based on the thermoplasticity of EVA to realize slow release of initiator at elevated temperatures. A high temperature degradable polymer gelling lost circulation material (LCM) P(AM-DGCL) was developed using acrylamide and a self-made crosslinking agent DGCL. The initiator DGCL was characterized with NMR and the mechanical behavior, plugging capacity and gel-breaking property of the gelling LCM tested. It was found that the gelation time of P(AM-DGCL) decreases with increase in the concentration of the initiator capsules and increase in temperature. The gelation time can be controlled within 2 - 13 h at temperature of 150℃. P(AM-DGCL) has excellent mechanical property; the percent elongation at break is 1,279% and the tensile strength is 0.0425 MPa. Since the crosslinking agent DGCL itself has gel-breaking property, the 16 h percent gel-breaking of P(AM-DGCL) is at least 95% at the action of high temperature and gel breaker, ensuring the flowback of a plugged reservoir because of lost circulation.
Application of an Ultra-high Temperature Drilling Fluid in Deep Well Drilling in Yangshuiwu Buried Hill
YANG Wenquan, ZHANG Yu, CHENG Zhi, LUO Renwen, HE Yongbo, WANG Dongming, XIAO Fei, XUE Li
2019, 36(3): 298-302,307. doi: 10.3969/j.issn.1001-5620.2019.03.006
The Ordovician reservoir in the Yangshuiwu block in Huabei Oilfield is buried below 6,000 m, and lithology of the formations drilled are generally limestone and mudstone. The forecast highest bottom hole temperatures are in a range of 210-230℃. A low solids ultra-high temperature drilling fluid has been successfully used in drilling the well Antan-4X. Since many additives in this drilling fluid were imported from foreign countries, high temperature additives and high temperature protection agents were studied and selected from domestically produced drilling fluid additives, and as a result of the study and optimization, a low solids drilling fluid resistant to high temperature of up to 230℃ was formulated. Rolling test and rheology measurement at high temperatures show that this drilling fluid has excellent high temperature property, the rheology of the drilling fluid at elevated temperatures still satisfies the needs of cuttings carrying. This drilling fluid has been successfully used in 7 wells in the Yangshuiwu block, providing an ultra-high temperature drilling fluid technology for use in deep well drilling in buried hill structure in Jizhong block of Huabei Oilfield.
A High Temperature Calcium Resistant Amphoteric Polymer Dispersant
LI Bin, JIANG Guancheng, HE Yinbo
2019, 36(3): 303-307. doi: 10.3969/j.issn.1001-5620.2019.03.007
Calcium contamination presents threats to many polymers used in drilling fluids. Dispersion and deflocculation are generally used to eliminate the detrimental effects of calcium contamination. A high temperature calcium resistant amphoteric polymer dispersant has been developed with 2-acrylamido-2-methylpropane sulfonic acid (AMPS), sodium 4-styrenesulfonate (SSS) and dimethyldiallyl ammonium chloride (DMDAAC). The key factors affecting the polymerization, through optimization, are as follows:molar ratio of the monomers AMPS:SSS:DMDAAC=7.5:0.5:2, percent mass concentration of the initiator K2S2O8 is 0.4%. Laboratory evaluation results show that this dispersant can be used to disperse bentonite in high temperature high calcium water base drilling fluids, and is able to reduce filtration rate and low-shear-rate viscosity. The mechanism of the dispersant was studied by analyzing its molecular structure. A drilling fluid resistant to contamination of high concentration calcium was formulated with the dispersant as the main additive, combined with other additives such as defoamer and inert plugging agents.
Drilling Fluid Technology for Borehole Wall Stabilization and Mud Loss Control in Block Hangjinqi
LI Jianshan
2019, 36(3): 308-314. doi: 10.3969/j.issn.1001-5620.2019.03.008
The Block Hangjinqi has abundant natural gas reserves, the drilling of which was seriously affected by borehole wall instability and mud losses. Studies have been conducted on the prevention and control of these problems with drilling fluids based on the understanding of the geological nature of the area. Analyses of the physical properties of the formation showed that faults were developed in this area. Existence of mudstones with low cementing strength and developed microfractures leads to borehole wall instability and mud losses. To resolve these problems, a temperature sensitive deformable plugging agent SMSHIELD-2, a high efficiency lubricant SMLUB-E and a lost circulation material SMGF-1 were developed to formulate a drilling fluid that can maintain borehole wall stable and to control mud losses. Laboratory experimental results showed that a drilling fluid containing 1% SMSHIELD-2 had its HTHP filtration rate reduced to 15 mL, and the toughness of the mud cake was enhanced. Addition of SMLUB-E into the drilling fluid reduced its extreme-pressure coefficient of friction to 0.033. SMGF-1 is made of particulate materials of different sizes and can remarkably increase the pressure bearing capacity of the formation and reduce the amount of lost mud. By carefully selecting drilling fluid additives an anti-sloughing drilling fluid and a mud loss control fluid were formulated. The drilling fluids were tested on two wells in Block Hangjinqi, and the fragile formations were drilled through successfully with no delay. No borehole wall instability has ever been encountered in drilling the mud stone formation, and the percent hole enlargement was less than 5%.
Inhibition of Mud Balls Formed in Drilling the Shallow Soft Mudstone Formation in an Dongfand Gas Field
YANG Yuhao, ZHANG Wandong, WANG Chenglong, HAN Cheng, WU Jiang, ZHANG Chao
2019, 36(3): 315-320. doi: 10.3969/j.issn.1001-5620.2019.03.009
The shallow gas reservoirs in the 2nd Segment of the Yinggehai formation is developed using the Z platform in offshore western South China Sea. The non-reservoir formations such as the Ledong formation, the 1st and the 2nd segments of the Yinggehai formation above the reservoir are soft and have high argillaceous contents. In the early development stage of the reservoir a strongly encapsulating PLUS/KCl or PEM polymer mud was used to inhibit the long section of mudstone formations encountered, but this drilling fluid behaved poorly in cleaning the hole and many mud balls were formed during drilling, resulting in high torque, high pump pressure, difficulties in tripping operation and reduced operational time efficiency. By analyzing the cause of mud ball formation, inhibitive drilling fluids were abandoned and a whole dispersed drilling fluid was adopted to drill the non-reservoir formations. During drilling with the whole dispersed drilling fluids, special high viscosity pills were used to clean the hole and the mud was converted to a drilling fluid with excellent lubricity. With these measures, mud ball formation and hole cleaning problems in drilling the top section were successfully resolved Five wells drilled on the Z platform had obviously elevated rate of penetration (ROP); the average ROP of the φ311.2 mm was 141.32 m/h, 62.69% higher than the fastest well drilled previously, creating a record in extended reach horizontal drilling of shallow gas reservoir in the eastern area of west South China Sea.
Optimization and Field Application of Drilling Fluid Technology for Well Yudong-7-4-2
XIAO Jinyu, ZHOU Hua'an, SUN Jun, LIU Yi, CHEN Fuquan, WANG Kai
2019, 36(3): 321-324. doi: 10.3969/j.issn.1001-5620.2019.03.010
Drilling operations in the Block Yudong in north Tarim Basin have long been faced with a series of problems, such as tight hole in the upper formations which results in drag and overpull, creeping of salt/gypsum sections which results in tight spots, sloughing and pipe sticking, and difficulties in controlling rheology and filtration of the drilling fluid because of high mud weight. By optimizing the drilling fluid technology on the well Yudong-7-4-2, drag, overpull and borehole wall instability have all been resolved. Percent hole washout in easy-to-collapse sections was only 7.5%. Drilling time was 20 days less than wells drilled nearby, indicating the ROP was greatly increased.
A Method of Predicting High Temperature High Pressure Rheological Property Based on Viscometer Readings
ZHOU Haobo
2019, 36(3): 325-332. doi: 10.3969/j.issn.1001-5620.2019.03.011
Prediction and analysis of high temperature high pressure (HTHP) mud rheological property together form the basis on which drilling fluid property control and hydraulic parameter calculation for deep and ultra-deep wells are performed. This paper introduces a method of analyzing HTHP drilling fluid rheological property using viscometer readings. In developing the new method, the pattern of the rotational viscometer readings changing with temperature and pressure is analyzed using data from laboratory HTHP experiments. The readings at different rotational speeds are then normalized using factors of proportionality. Using numerical method, the relationship among the factor of proportionality, temperature and pressure at constant pressure changing temperature and constant temperature changing pressure is analyzed. A model for predicting HTHP factor of proportionality and a general model for predicting HTHP viscometer readings are established based on the analyses. Methods of selecting HTHP rheological model and calculating rheological parameters are also developed. The calculated rheological parameters and the measured ones fit very well, as shown by comparing two sets of parameters. Using the method, a set of rheological data of a drilling fluid taken from a wellbore is analyzed. Compared with conventional methods, this new method can be use to predict not only normal rheological properties (plastic viscosity, apparent viscosity etc.), but also HTHP parameters of all rheological models.
Development and Application of an Ultra-High Temperature Ultra-High Pressure Rheometer
ZHAO Jiangang, ZHAO Kai, HAN Tianfu, SHI Kai, WANG Qi, LI Meinan, HU Wei
2019, 36(3): 333-337. doi: 10.3969/j.issn.1001-5620.2019.03.012
Rheometers presently available cannot satisfy the needs of rheology measurement at ultra-high temperatures and ultra-high pressures. To resolve this problem, a rheometer for use at ultra-high temperatures and ultra-high pressures has been developed, which is composed of four subsystems:an industrial computer, a viscosity measuring unit, a temperature control unit and a pressure control unit. This rheometer can be used to measure the viscosity of a sample at simulated downhole temperature, pressure and rotational speed of drill bit, the maximum pressure for the measurement is 220 MPa, and the temperature for the measurement is in a range of -20℃-320℃. The sealing of the measuring chamber is resolved using non-contact viscosity measuring method. Using a unique temperature control algorithm and media switching cooling technique, the viscosity can be measured in a very wider temperature range and efficient cooling can be realized during viscosity measurement. Some drilling fluid samples have been tested on this rheometer at constant pressure changing temperatures and constant temperature changing pressures. The test results showed that this rheometer can be used to measure the rheology of water base drilling fluids and oil base drilling fluids at ultra-high temperatures and ultra-high pressures, the measured data can be used in optimizing drilling fluid properties.
Study and Application of High Temperature Settling Stability of Cementing Slurry Used in Cementing Well Chuanshen-1
LI Zaoyuan, ZHAO Jun, WANG Xiyong, ZHENG Guanyi, LUO Deming, FU Tiesong
2019, 36(3): 338-343,348. doi: 10.3969/j.issn.1001-5620.2019.03.013
The well Chuanshen-1 is an ultra-deep exploratory well with completion depth of 8,420 m and bottom hole temperature of 178℃. The high temperature settling stability of the cement slurry is critical to the success of the cementing job. In laboratory experiment, the high temperature settling stability of a cement slurry was evaluated through HTHP thickening shutdown and measuring of the thickness of the settled particles on the bottom of the cement slurry cup. A technology of evaluating the high temperature stability of liquid organic polymer additive was developed using IR spectroscopy analysis and high temperature stability analysis of cement slurry. Using environmental scanning electron microscopy, the microstructure of cement slurry was studied, and the sizing of silica sands as well as the effects and mechanisms of ultra-fine micro sand, liquid silicon, nanophase SiO2 and latex on the high temperature stability of cement slurry was investigated. The settling of cement slurries with densities between 1.90 g/cm3 and 2.30 g/cm3 at 150℃- 180℃ can be controlled using the technology studied. The technology has been applied in designing the cement slurry for cementing the 5th interval tubing string of the well Chuanshen-1. The high temperature stability of the cement slurry was excellent and the rate of excellence of the cement job was 88.1%.
Cementing Low-rank Coal Bed with Ultra-low Density Cement Slurry in Erlian Basin
LIU Jingli, PENG Song, WANG Ye, HE Jingchao, YAO Xiaojun, BI Yi, ZHANG Xin, HE Xingwei
2019, 36(3): 344-348. doi: 10.3969/j.issn.1001-5620.2019.03.014
Wells drilled in the Erlian Basin penetrate coal beds with developed fractures, and some of the formations have low strength, resulting in severe lost circulation during well cementing with low density cement slurries, and the cement slurries generally didn't return to the designed heights. An ultra-low density cement slurry was developed to address these problems. A stability enhancement additive was used in the cement to prevent the separation of micro beads and cement. The minimum density of this cement slurry obtained in field application was 1.06 g/cm3. Other properties of the cement slurry were as follows:mobility controlled within 19-20 cm, free water 0 mL, 30℃ thickening time controlled within 1.5-4.5 h, API filter loss less than 50 mL, 24 h compressive strength greater than 3.5 MPa, 72 h compressive strength greater than 6.0 MPa. The overall performance of the cement slurry is exchis cement slurry has been used 5 times in Erlian Basin (Huabei Oilfield), with all cement slurry returned to the surface in single-stage well cementing, and the pass rate of cementing job quality was 100%.
A Cement Slurry Used at Ultra-high Circulation Temperature of 210℃
YU Yongjin, DING Zhiwei, ZHANG Chi, ZHANG Hua, GUO Jintang
2019, 36(3): 349-354. doi: 10.3969/j.issn.1001-5620.2019.03.015
To develop deep buried hydrocarbons, more and more ultra-deep and ultra-high temperature wells are drilled, imposing greater challenges to the thermal stability of cement slurry. To improve the high temperature stability of the cement slurries presently in use, a high temperature filter loss reducer DRF-1S, a high temperature retarder DRH-2L and other high temperature cement additives have been developed. A high temperature cement slurry with normal densities was formulated with these additives and was evaluated in laboratory. The laboratory evaluation results show that this cement slurry can be used at bottom hole circulation temperature of 210℃ and static bottom hole temperature of 230℃. The API filter loss of the cement slurry can be controlled to below 100 mL. The thickening time is adjustable. Differential density of the cement slurry at bottom and top is less than 0.04 g/cm3 at elevated temperatures. At ultra-high temperatures of 230℃-250℃, the set cement has a high strength that does not deteriorate with time. This cement slurry has been successfully used in cementing the φ127 mm liner string of the high temperature deep well Antan-4X drilled in the Block Yangshuiwu, Huabei Oilfield, and the excellent job quality of well cementing has provided a technical support for cementing exploratory wells in this area.
Difficulties in Cementing Salt Formation in Well Keshen-Y: Analyses and Technical Measures
XIONG Yudan, LI Lihua, HE Silong, DENG Qiang, SHI Yongzhe, CHEN Yongheng, QU Lingxiao
2019, 36(3): 355-359. doi: 10.3969/j.issn.1001-5620.2019.03.016
The fourth interval of the well Keshen-Y penetrated several salt zones, mud loss zones and high pressure formation water zones. High creeping tendency of salt may cause resistance to casing running. A narrow safe drilling window of only 0.03 g/cm3 in a hole section where high pressure formation water and mud loss zone coexist may cause mud loss and overflow. In well cementing operation, low leak-off pressure and eccentricity of casing string result in poor displacement of mud and hence difficulties in cementing the high pressure water zones. Several measures have been developed to address these problems. First, based on the analyses of the geological and engineering conditions, it was decided to ream the salt sections and to perform wiper trip with a simulation string. The well cementing techniques were reviewed based on the evaluation of leak-off pressure and overflow pressure, and a "normal injection reverse squeezing plus timely pressurizing" cementing program was established. Using software simulation, the placement of centralizer and the rheology of spacer were optimized, and high flow rate and multiple displacement were used to increase the displacing efficiency. Field application of these technical measures showed that the casing string were run smoothly to the designed depth. No lost circulation and overflow have ever occurred during normal injection cementing. High flow rate was obtained and the top of cement was controllable during reverse squeezing cementing. Channeling test at the bell nipple at negative pressure was certified, indicating that the water zones were successfully cemented.
Synthesis and Performance Evaluation of a New Amphoteric Well Cement Retarder
CHEN Xintong, HAN Liang, TANG Xin, LU Hao, LI Xiaolong, YANG Zengmin, YANG Yuhang, CHEN Yan
2019, 36(3): 360-365. doi: 10.3969/j.issn.1001-5620.2019.03.017
In cementing long openholes, cement retarders sometimes lose their effectiveness because of high temperatures. Slow development of the strength of the top cement slurry, sensitivity of cement slurry to temperature and to the dosage of cement additives are problems encountered during well cementing. To address these problems, a high temperature retarder CXT-1 has been developed with acrylic acid (AA), itaconic acid (IA), 2-acrylamide-2-methylpropane sulfonic acid (AMPS) and a new cationic monomer (X). The optimum synthetic conditions obtained through orthogonal experiment are as follows:molar ratio of the monomers is 37:8:8:6, reaction temperature is 60℃, pH of the reaction solution is 4, time of reaction is 4 h, and the concentration of initiator is 0.3%. CXT-1 was characterized with IR spectroscopy, NMR and thermogravimetric analysis, and evaluated in laboratory. It was found that the molecules of CXT-1 contains the characteristic functional groups of the four monomers. CXT-1 has good thermal stability, and no obvious mass lose of CXT-1 was found when temperature is less than 330℃. Using CXT-1, the thickening time of a cement slurry can be prolonged at temperatures between 90℃ and 180℃. At 180℃, the thickening time is 368 min. The concentration sensitivity coefficient of CXT-1 is in a range of 0.48 - 1.73, and the maximum temperature sensitivity coefficient of CXT-1 is 6.2%, all satisfying the needs of the relevant industrial standards. The 24 h compressive strength of the top cement slurry at temperatures between 60℃ and 100℃ is at least 10.6 MPa, satisfying the needs of field operations. Analyses of conductivity, XRD and SEM show that the working mechanisms of the retarder are the combined action of multipoint adsorption which controls the hydration of cement, inhibition of the growth of Ca(OH)2 crystals and complexation.
Development and Application of a Foam Control Agent for Acidification Operation
WANG Yunyun, YANG Bin, ZHANG Zhen, LI Wenjie, XU Xingjuan, LIU Rongqing, GU Qingjiang, YANG Jinling
2019, 36(3): 366-370. doi: 10.3969/j.issn.1001-5620.2019.03.018
In preparing acidizing fluid, large amount of foam is generated in the fluid and is very difficult to defoam, thus affecting the normal process of acidizing operation. In acidizing carbonate reservoirs, reaction between the carbonate rocks and the acid also generates plenty of gas which generates foams in the flowback fluid and is very difficult to collect and dispose. Defoamers are used to defoam the fluid, but the effectiveness is not satisfactory. A defoamer BH-SPK used in acidizing fluids has been developed to address these problems. BH-SPK is formulated with several chemical compounds, such as amino polyether silicone made from end epoxy silicone oil and polyamine ether M-1000, and silicone paste made from dimethyl silicone oil and white carbon black. These two compounds are the main components of the defoamer. Other components include SPAN-60 and TWEEN-60 as emulsifier, and sodium carboxymethylcellulose as viscosifier. BH-SPK is produced by mixing these components at high shear rates. BH-SPK is well compatible with the acids used for acidizing job and has excellent properties. At a concentration of 0.5% BH-SPK, time for defoaming is only 36 s, and time for inhibiting the generation of foam is 3,521 s. BH-SPK has been used in making converting acid in the Al-Ahdab oilfield, effectively resolved the serious foaming problem in formulating acid solution.
Rheology of Triisopropanolamine Modified Xanthan Water Solution
LAN Chengcheng, FANG Bo, LU Yongjun, QIU Xiaohui
2019, 36(3): 371-377. doi: 10.3969/j.issn.1001-5620.2019.03.019
To improve the rheology of xanthan solution, a high viscosity polyhydroxy amphoteric xanthan (TIPA-XG) was developed through the etherization of xanthan polymer (XG). The etherizing agent used was a cationic polyhydroxy agent developed with triisopropanolamine and epichlorohydrin. The XG and TIPA-XG were characterized with IR spectroscopy, element analysis and XRD spectroscopy. The rheological characteristics of the TIPA-XG solution and the XG solution, including steady state viscosity, flow curve,thixotropy, viscoelasticity as well as the high temperature tolerance and shear resistance of the two solutions were studied and compared. It was found that TIPA-XG has higher viscosity than XG; the viscosity of a 0.6% TIPA-XG solution was 320.45 mPa·s, 332% higher than that of the XG solution, which was 74.12 mPa·s. The flow curves of the XG and the TIPA-XG solutions can all be described by the non-linear co-rotational Jeffreys constitutive equation. The viscoelasticity and thixotropy of the TIPA-XG solution were all greater than those of the XG solution. When sheared at 80℃ for 90 min, 0.6% TIPA-XG solution had a remaining viscosity of 142.88 mPa·s, which was 2.26 times of the remaining viscosity of the 0.6% XG solution (63.27 mPa·s) under the same conditions, indicating that TIPA-XG has better high temperature stability that XG.
Experiment Study on the Mechanisms of Sand Suspension and Settling of Proppant in Fracturing Fluids
LIU Jiankun, WU Zhiying, WU Chunfang, JIANG Tingxue, SUI Shiyuan
2019, 36(3): 378-383. doi: 10.3969/j.issn.1001-5620.2019.03.020
The sand carrying performance of a fracturing fluid directly affects the transport and placement of proppant in formation fractures and the effective flow conductance of the fractures after fracturing. A model "XS-I" instrument for simulation experiment on sand suspension and proppant settling has been developed to study the suspension of three ceramsite proppants (particle sizes of 70/140 mesh, 40/70 mesh and 30/50 mesh) in a SRFP-1 fracturing fluid. Using XS-I, the amount of settled proppants, settling rate and the changing pattern of the amount and settling rate with time in suspension fluid were studied and the main factor affecting the sand carrying capacity of a fracturing fluid was obtained. Laboratory experimental results show that the settling of proppants in suspension fluid can be divided into three stages:fast settling, slow settling and stabilized equilibrium. The main factor affecting the suspension capacity of a fracturing fluid is the viscosity of the fracturing fluid, with particle sizes and sand/fluid ratio being the minor affecting factors. Fracturing fluids of low viscosity can only suspend the 70/140 mesh proppant (time for the proppant to completely settle is 10-20 min), but the suspension of the 40/70 mesh and 30/50 mesh proppants in low-viscosity fracturing fluids is poor (time for the proppants to completely settle is only 1.0-5.5 min), and generally speaking the low-viscosity fracturing fluids have poor suspension capacity. Fracturing fluids of medium viscosity have good suspension to the 70/140 mesh proppant (only 9.9%-11.1% of the proppant was settling). When sand concentration is less than 15%, fracturing fluids of medium viscosity have good suspension to the 40/70 mesh and 30/50 mesh proppants (time for the proppants to completely settle is 80 min-240 min). Fracturing fluids of high viscosity have good suspension to large particle size proppants (30/50 mesh) with high concentrations (25%-30%); only 12%-13.1% of the proppant settles down. This means that a high-viscosity fracturing fluid can be used as a sand carrying fluid at the major sand mixing stage. The results of this study provide a new evaluation method for testing the sand carrying capacity of a fracturing fluid and for evaluating and optimizing proppants, and can be used in optimizing fracturing job parameters and selecting proppants.
Development of a Double Crosslinked Foam Gel and its Mechanisms of Temporary Plugging, Well Killing and Mud Loss Controlling
JIA Hu, YANG Xinyu, LI Sanxi, HUANG Fada
2019, 36(3): 384-390. doi: 10.3969/j.issn.1001-5620.2019.03.021
When working over wells with low pressure reservoirs, loss of workover fluids into the reservoirs has long been a problem that needs to be resolved. A double crosslinked foam gel well killing fluid has been developed for the resolution of this problem. The basic composition of the killing fluid is:3% polyacrylamide + 2% foaming agent + 1.5% crosslinking agent A + 0.1% crosslinking agent B. It was found under microscope that single crosslinked foam gel and double crosslinked foam gel all had obvious dualmembrane structure, the double crosslinked foam gel had thick and tough membrane. The thickness of the membrane surrounding the gas core of the foam was 77.35 μm (max.) and the total thickness of the membranes surrounding the gas core was 188.48 μm (max.). The thick membranes render the foam gel high compressive strength and good stability. The foam gel can stay stable for at least 10 d, far longer than single crosslinked foam gel. Rheology and viscoelasticity test of the foam gel showed that the double crosslinked foam gel had high elasticity and low viscosity, making it easy to be pumped and flowed back. Simulated temporary plugging well killing experiments showed that for cores with porosity between 90 mD and 208 mD, pressure drawdown across the cores under 2 MPa positive pressure differential was less than 0.05 MPain 60 min, and the rate of filtration of fluid through the cores was almost zero. These data showed that the double crosslinked foam gel well killing fluid has a certain compressive capacity and low filtration rate, and can effectively plug reservoir rocks temporarily, rendering it good application prospects in preventing loss of workover fluids in low pressure reservoirs.
Analysis of Oil Well Blockage in K Oilfield in Kazakhstan and Blockage Removal Techniques
LI Yan, DOU Ninghui, YAO Erdong
2019, 36(3): 391-396. doi: 10.3969/j.issn.1001-5620.2019.03.022
Blockage of tubing and casing was found in thedown hole of K oilfield, which seriously affected the production job. The type of the blockage was identified and a high efficiency chelating blockage removing agent was developed to addressthe problem. After identifying the composition of the blockage, the reservoir characteristics of the K oilfield were first analyzed toascertain the potential reasons of well blocking. It was found that scales and the peeling iron rust by CO2 corrosion were the possiblereasons of well blocking. Then, using XRF and XRD instrument, the main components of the blockage was determined, and they are ferricoxide and small amount of rock salts. Finally, by dissolving the blockage in various acid solutions, the type of the blockage wasfurther confirmed. A blockage removing fluid, made up of an optimized chelating agent, hydrofluoric acid and a corrosion inhibitorfluid, were then developed. It was found that theblockage removing fluid works well at 120℃ and has no harm to the N80 coupon. The dissolved ratio of the blockageis 82% in 2 h.This blockage fluid cannot only protect tubing/casing strings but also dissolve the blockage, and it show excellent blockage removing abilities. After adding a corrosion inhibitor KMS-Z, its corrosion rate reduces to 8.91 g/(m2·s), which exceeding the Class 1 of corrosionindustrial standard requirement. On the other hand, although mud acid have good dissolving ability to the blockage, it is unable to control corrosion rate. Failure of corrosion protection in mud acid maybe come from the strong oxidizing ability of the ferric ions.