2020 Vol. 37, No. 2

2020, 37(2)
Micro Foam Drilling Fluid Technology Abroad: New Progress and Discussion
WANG Chaoqun, CHEN Yuanbo, ZHAO Zhiqiang, GUO Xiaoxuan, ZHANG Daoming
2020, 37(2): 133-139. doi: 10.3969/j.issn.1001-5620.2020.02.001
This paper summarizes progress made abroad on researches and application of micro foam drilling fluid in recent decade, including knowledge obtained about the micro mechanisms and rheology of micro foam drilling fluids. The authors present in the paper that, for the current technical status of the micro foam drilling fluids, the matching relationship between the sizes of foam and the sizes of pore throat is still not clearly understood; and there is a wide gap between laboratory evaluation on the blockage caused by micro foam and field application. Based on the problems presented above, the research direction of micro foam drilling fluid technology is discussed from three aspects, which are:the percolation flow pattern of micro foams in porous media and its affecting factors, chemical additives for micro foam drilling fluids, and the formulation method of micro foam drilling fluids. A mathematical model is needed to quantitatively describe the matching relationship between the sizes of micro foam and the sizes of pore throats in porous media, therefore to provide a theoretical reference for the application of micro foams in different reservoirs. The effects of "Jamin Effect" by the micro foams on the percolation flow capacity of reservoir fluids was studied to avoid the reduction of fluid production rate after operation with micro foam. Finally, the corresponding relation between laboratory experiment and field formulation conditions needs to be built up to unify the formulation criteria of micro foam drilling fluids.
Experimental Study on Shale Borehole Wall Stability of Tight Oil Wells in Daqing Oilfield
YAN Songbing, LIU Fuchen, YANG Zhenzhou, LIU Yonggui, LYU Meng, SONG Tao, ZHOU Chun
2020, 37(2): 140-147. doi: 10.3969/j.issn.1001-5620.2020.02.002
Borehole wall instability has long been a problem in drilling the Qingshankou Formation and the Quantou Formation in the tight oil blocks in Daqing. Common methods of evaluating the stability of shale formations presently in use are hot rolling test and linear expansion test. These methods however, have defects caused by those who do the experiments, and the experimental results are therefore misleading in the understanding of the activity of the swelling shales and the selection of compatible drilling fluid. Multistage triaxial stress experiment, pressure transfer test (PTT) and thick-walled cylinder test (TWC), which can simulate more closely the downhole conditions, were used to study the stability of shale formations in tight oil wells in Daqing. Using the multi-stage triaxial stress test, the Mohr-Coulomb failure envelop of the formation rocks was drawn to determine the mud density enough to stabilize the borehole wall. PTT was conducted to understand the anticipated invasion rate of pressure caused by drilling fluid column in the hole and the delay in pore pressure increase for a specific fluid system. TWC experiment was used to study the failure characteristics of core samples exposed to drilling fluid under overbalanced pressure. These three test methods simulate the effects of drilling fluid on the stresses of downhole shale formation, and are instructive to the study on the factors affecting borehole wall stabilization.
Development and Working Mechanism of Flow Pattern Enhancer for Synthetic Base Drilling Fluids
HAN Zixuan
2020, 37(2): 148-152. doi: 10.3969/j.issn.1001-5620.2020.02.003
A flow pattern enhancer has been developed to deal with the rheology problem of synthetic base drilling fluids at low temperatures. In laboratory experiment, the effects of the flow pattern enhancer on the rheology of water-in-oil emulsion were measured, the IR and XRD characteristics of the flow pattern enhancer and organophilic clays were compared and analyzed. Using Cryo-SEM and TEM, the effects of the flow pattern enhancer on the micro-structure of the emulsion were observed and the working mechanisms of the flow pattern enhancer analyzed. The laboratory experimental results were then used to evaluate the applicability of the flow pattern enhancer in high density synthetic base drilling fluids. It was found that the flow pattern enhancer was able to remarkably improve the low-temperature rheology of synthetic base drilling fluids and was beneficial to the stability of emulsion. The molecules of the flow pattern enhancer are adsorbed on the interface of oil and water in the emulsion, thereby reducing the structural force between the drops of the emulsion and the particles of the organophilic clay, and improving the interaction between the clay particles and emulsion drops. All these are helpful to the stability of the gel strength of the water-in-oil emulsion. Compared with conventional synthetic base drilling fluids, the constant-rheology synthetic base drilling fluids have more stable low-temperature rheology which is critical to the safety of downhole operation.
Rheology Control and Application of Ultra-High-Density Compound Brine Drilling Fluid
HUANG Tao, FAN Xiangsheng, TAO Weidong, XIE Gangjin
2020, 37(2): 153-159. doi: 10.3969/j.issn.1001-5620.2020.02.004
Well Lu-206 is an appraisal well drilled in the oil/gas and shale gas exploration block in Changning, Lu County, south of Sichuan Basin. The target zone of this well is the Baota Formation. The vertical pilot hole of this well is 4082 m in depth. During drilling operation, high pressure fracture gas was encountered, caused the hole to overflow, and the well was finally killed with a high density (2.42 g/cm3) water base mud. To control the formations wit active gas, ultra-high density had to be used, this in turn resulted in difficulties in solids control of the drilling fluids. Furthermore, the top formations are very water sensitive, making control of mud rheology is very difficult. Based on the past drilling experiences gained and comprehensive laboratory experiment, the sulfonate polymer drilling fluid previously used to drill the top section of the well was replaced with an ultra-high-density compound brine drilling fluid with excellent contamination resistance and inhibitive capacity. A lignite resin KJ-4, a high-density dispersant and a sulfonated tannin were mixed together to control the rheology of the compound brine drilling fluid, which was also a problem needed to be resolved. Application of this ultra-high-density compound brine drilling fluid in drilling the fourth interval of the vertical pilot hole of the well Lu-206 showed that the rheology of the drilling fluid was under control during the whole drilling process. The success of the field practice has provided a clue for controlling the rheology of high-density drilling fluids.
The Effect of Temperature on Stability of Borehole Wall in Ultra-Deep Fractured Formation
LU Yunhu, XIAO Xianheng, ZHAO Lin, JIN Yan, CHEN Mian
2020, 37(2): 160-167. doi: 10.3969/j.issn.1001-5620.2020.02.005
Formation temperature plays a significant role in stability of the surrounding rock around the borehole wall, especially for the ultra-deep (> 6000 m) fractured reservoirs. Traditional prediction model on collapse pressure that considers temperature effect mainly applies to intact formation, whereas few works have been done to investigate the effect of temperature on collapse pressure of fractured formation. To address this problem, in this study, we first determined the induced stress field generated by temperature variation through Duhame's principle. Second, stress distribution on fracture surface was obtained with consideration of coordinate transformation and the coupling of fracture-seepage field and temperature field. Third, we characterized the effect of temperature on wellbore stability by incorporating the established stress field on fracture surface into the rock failure criterion. The results show that under the same stress and fracture incidence conditions, increasing temperature aggrandizes the extent of formation collapse. This result is contrary to the traditional conclusion that the temperature-reduction-induced collapse pressure drop may strengthen wellbore stability. Moreover, wellbore stability is sensitive to the variation of fracture incidence when wellbore pressure is constant. Furthermore, for the ultra-deep fractured formation, the risk of instability may increase when surrounding rock temperature decreases as a result of mud circulation. Our works highlight the importance of temperature on well stability, and shed light on the design of appropriate drilling mud to prevent well from collapsing.
Study on Temperature and Pressure Correction Model for Predicting Liquid Phase Density of Drilling Fluids
LI Xu, REN Shengli, LIU Wencheng, ZHAO Danhui, LIAO Maolin, LIN Liming
2020, 37(2): 168-173. doi: 10.3969/j.issn.1001-5620.2020.02.006
The density of a drilling fluid is the main factor affecting the pressure distribution along the wellbore. An accurate calculation of the density of a drilling fluid is the key to the avoidance of well kick, blowout and mud losses. Since liquid phase in drilling fluid has densities changing with pressure and temperature, the density of the drilling fluid measured at the surface disagrees with the real density of the drilling fluid downhole. This density disagreement of the liquid phase has to be corrected taking into account the temperature and pressure in the hole. This paper presents a modified temperature and pressure correction model for calculating the real downhole density by introducing a quadratic term of temperature into the API temperature-pressure correction model based on laboratory experiments. Comparing the calculation results with the new model with the experimental data, it was found the new model is superior to the API model. For a drilling fluid whose density is sensitive to high temperature, the new model predicts downhole drilling fluid density with much higher accuracy.
Drilling Fluid Technology for Exploration and Development of Shale Oil in South of Dagang Oilfield
LI Guanghuan, LONG Tao, ZHOU Tao, SONG Jianming, HUO Baoyu, LI Yanqiao
2020, 37(2): 174-179. doi: 10.3969/j.issn.1001-5620.2020.02.007
Wellbore instability is a problem encountered in shale oil horizontal drilling in Cangdong block in the south of Dagang oilfield. To address this problem, the geological features of the Cangdong block, the operation difficulties and the mechanisms of borehole wall collapse were analyzed, and three key drilling fluid additives (shale inhibitor, plugging agent and lubricant) were selected to formulate a BH-KSMShale drilling fluid for shale oil development. Laboratory evaluation of this drilling fluid showed that the drilling fluid had good properties; it functioned properly 150℃, and the HTHP filtration rate was less than 10 mL. Four wells, well **701H, well **702H, well **1-2H and well **2H, in the south of Dagang oilfield were drilled using the BH-KSMShale drilling fluid. The drilling operation was performed smoothly, and there was no downhole trouble occurred during drilling. The maximum percent hole enlargement was only 8.67%. The BH-KSMShale drilling fluid is very suitable for the shale oil drilling in the south of Dagang oilfield; with this drilling fluid, the borehole wall collapse in horizontal drilling is avoided and it will find wide application in the future in shale oil development in Dagang.
Study on Environmentally Friendly Easy-to-destabilize Drilling Fluid Technology
JIANG Zhuo, CAO Yanfeng, WANG Jian, XING Xijin, SHU Fuchang, XIANG Xingjin
2020, 37(2): 180-184. doi: 10.3969/j.issn.1001-5620.2020.02.008
The discharge of waste drilling fluids in offshore drilling operations has in recent years gradually become "zero discharge" from "limited discharge" implemented originally because of the stricter requirement of environment protection. This has resulted in sharp increase in the amount of waste drilling fluids recycled, which in turn badly affect reduced the cost efficiency of offshore petroleum development. A laboratory study was performed on the colloidal stability of the waste drilling fluids, and by combining the source control and terminal treatment, an environmentally friendly easy-to-destabilize drilling fluid and a biochemical treatment technology were developed. "Zero discharge" of waste drilling fluids in offshore drilling can be realized by decreasing the amount of waste drilling fluids to be treated through increasing the efficiency of solids-liquids separation of the waste drilling fluids.
Patterns of Stress Sensitivity of the Shale Oil Reservoirs in Raoyang Depression
WANG Xiuying, WU Tong, CAI Jun, XIONG Zhan, GUO Guangfeng, ZHANG Ming
2020, 37(2): 185-191. doi: 10.3969/j.issn.1001-5620.2020.02.009
The Raoyang depression is enriched with abundant shale oil. It is well known that shale formations are generally developed with stress sensitivity, therefore the degree of stress sensitivity in this area should be measured and patterns of stress sensitivity be found to provide basic data for field production. Eleven sets of experiments on the mineral composition, microstructure and connectivity of the reservoir formations, and three sets of flow experiments on reservoir stress sensitivity were conducted using XRD whole mineral analyses, fluorescent thin layer analyses and SEM. At permeability loss of 20%, the stress sensitivity patterns of the Raoyang depression was obtained with data fitting. The relationship between net stress, clay content and brittle mineral content is this:-0.09796mc+0.2385mb-7.8145. The relationship between irreversible permeability loss, clay content and brittle mineral content is this:93.24+0.2797mc-0.6809mb. The percent irreversible permeability loss is 52.09% and the net stress corresponding to permeability loss of 20% is within 3 MPa. Further analyses showed that different opening sizes of the micro fractures resulted from different clay contents are responsible for the relationships, the content of brittle minerals decides the irreversible permeability impairment and the net stress corresponding to 20% of permeability loss. The experimental results showed that stress sensitivity in the shale oil reservoirs in Raoyang depression is negatively correlated to the content of clay content, and is positively corelated to the content of brittle minerals. When the amount of reservoir rock samples is not enough to characterize the patterns of the whole formation, the data fitting method described in this study provides a way of using limited core plugs to realize the goal of whole formation characterization.
Treatment of Aluminum Sulphate Contamination to Water Base Drilling Fluids
ZHU Xuefei, XI Yunfei, YOU Wei
2020, 37(2): 192-195. doi: 10.3969/j.issn.1001-5620.2020.02.010
A high density KCl-polymer sulfonate drilling fluid was used to drill the third interval (φ311.2 mm) of the well KS-19. When drilling between 6243 m and 6387 m, the drilling fluid was contaminated by industrial waste water containing aluminum sulphate. The drilling fluid was experiencing rheology increase every day, or abrupt change sometimes. Several changes can be seen of the drilling fluid after being contaminated. First, the φ6 and φ3 readings, 10s gel strength and yield of the drilling fluid were increased to higher values, other drilling fluid parameters remained normal. Second, the mud in the suction pit and mud ditches had coarse surface and plenty of pinhole bubbles were trapped in the mud, making the mud flow very slowly. Third, the mud became difficult to pump, the mud pump trembled seriously, and the pump strokes per minute and pump pressure were unstable, changing in wide ranges. Charging pumps had to be used during drilling to pump the mud. To resolve these problems, the mud was circulated when the drill bit was at the casing shoe and the bottom of the hole to adjust its properties. Several measures, such as dilution and displacement, changing of the surface tension of the bubbles, neutralization with high pH value, changing rheology and increasing oil content of the mud, were taken to improve the properties of the mud. Drilling was then resumed and there were only small amount of bubbles found in the suction pit and ditches. Circulation was resumed to normal condition.
Optimization of Drilling Fluid Density for Shale Gas Drilling in Block Wei-202 and Block Wei-204
BAI Guobin
2020, 37(2): 196-201. doi: 10.3969/j.issn.1001-5620.2020.02.011
With the extensive growth of shale gas development in the south of Sichuan Province, downhole problems and reservoir damage are becoming more and more frequent. Optimization of the density of the drilling fluids, which is too high for reservoir protection, is a problem that needs to be urgently resolved presently. To have the mud density better suitable for shale gas drilling, a rock mechanical evaluation result based on array sound wave is selected to characterize the three-pressure profile of shale reservoirs. Using regional pressure measurement data, a vertical depth-pore pressure plate constraint Eaton model was developed to improve the precision of the three-pressure model. Safe drilling windows for 11 horizontal wells have been designed using this model, and the bases for selecting the safe drilling window were presented. Optimization of drilling fluid density is of great importance to the safe and efficient development of shale gas.
Ultra-high Temperature Cement Slurry for Cementing Well GR1 Penetrating Hot Dry Rock Formations in Gonghe Basin, Qinghai
LIU Huibin, LI Jianhua, PANG Heshan, ZHENG Huikai, LIU Dongqing, SUN Xinghua, SONG Weibin
2020, 37(2): 202-208. doi: 10.3969/j.issn.1001-5620.2020.02.012
The job quality of well cementing is the key factor affecting the borehole quality of a well penetrating hot dry rock formations. The major technical difficulties in cementing the wells penetrating hot dry rock formations in the Gonghe Basin in Qinghai were determined by studying the geological characteristics and the conditions for the hot dry rock to exist. An ultra-high temperature cement slurry for cementing the wells was formulated with a high temperature retarder BCR-320L and a high temperature filter loss reducer BXF-200L (AF), based on the investigation of strength decline mechanisms of the set cement with different concentrations of silica powder. Laboratory experimental results showed that the cement slurry can be used to cement wells at circulation temperature of 200℃. The cement slurry has good rheology and adjustable thickening time. The strength of the set cement does not decline at 200℃, and the compressive strength of the cement slurry after aging 72 h is 44.1 MPa. This cement slurry has been successfully used in cementing the well GR1 which penetrated hot dry rock formations in the Gonghe Basin in Qinghai. The quality of the cementing job was excellent. This cementing technology has provided a reference for subsequent hot dry rock well cementing.
Synthesis and Performance of High Temperature Filter Loss Reducer ZFA-1 for Oil Well Cement Slurries
LI Xiaolan, ZHENG Zhijun, GUO Peng
2020, 37(2): 209-213,220. doi: 10.3969/j.issn.1001-5620.2020.02.013
Water-soluble polymers have limited temperature resistance in high pH environment. To improve the high temperature performance of filter loss reducers, a new high temperature filter loss reducer, ZFA-1, was developed using a quite different way of synthesis than conventional way of synthesizing water-soluble copolymers. ZFA-1 is an inorganic non-metallic material compounded with organic polymer. The optimum synthesis conditions was determined as follow through experiment:molar ratio of AM:IA:AMPS=6.0:2.5:1.5, the concentration of molecular weight modifier=0.005%, concentration of coupling agent=0.5%, concentration of inorganic material=5%, concentration of initiator=0.5%, mass fraction of monomers=25%, pH of the reaction system=6, initiation temperature=55℃, and the reaction time=6 h. Characterization of the synthesis product with FT-IR and DSC/DTG showed that the product obtained had the molecular structure as expected. The ratio of weight loss of ZFA-1 at 326℃ was only 7.81%, which can be credited to the introduction of coupling agent and inorganic material that improve the high temperature stability of the final product ZFA-1. Laboratory evaluation of ZFA-1 showed that at concentrations of 1.0% -1.5%, the filtration rate of cement slurries can be controlled within 50 mL at 93-200℃ and 6.9 MPa. ZFA-1 has excellent salt-resistance and no negative effect on the compressive strength of set cement.
Managed Pressure Well Cementing Techniques for Wells with Narrow Safe Drilling Windows in Sichuan Basin
LIU Yang, CHEN Min, WU Lang, XIAN Ming, YANG Xiangyu
2020, 37(2): 214-220. doi: 10.3969/j.issn.1001-5620.2020.02.014
The Sichuan Basin is characterized by complex geological structures. Take the Chuanxi area (West Sichuan) as an example, wells drilled in this area have depth of at least 7000 m, and the safe drilling windows are only 0.05-0.08 g/cm3. Losses of cementing slurry have been frequently encountered, reverse squeezing of cement slurry has to be performed for the well cementing to be certified. Percent qualified cementing job was only 39.6% (calculated by cemented length). Laboratory study has been performed on managed pressure well cementing technology to improve the quality of the well cementing job. Effects of the wellbore fluid density, drilling fluid rheology, displacement flow rate and the magnitude of managed annular pressures on the losses of cement slurry and displacement efficiency were analyzed. It was found that prior to managed pressure well cementing job, the density of the wellbore fluid should be decreased by 0.05-0.08 g/cm3, the yield point of the drilling fluid should be less than 6 Pa, the displacement rate should be at least 22 L/s, that is, the annular velocity should be 0.9 m/L or higher. Also, the displacement rate at the last stage of displacement should be varying based on the equivalent density of the weak zones along the wellbore. To overcome the shortage of conventional casing running operation and WOC techniques, managed pressure casing running technique and staged pressurizing/cementing techniques were used in the field operations. Managed pressure well cementing technology has been used 26 times on wells with narrow safe drilling windows in the Sichuan Basin, and many operation records were set; the deepest well cemented with this technology was 7793 m in depth, the narrowest safe drilling window was 0.05 g/cm3, rate of one-time return of cement slurry was 100%, rate of certified well cementing job was 100%, percent length of excellent well cementing job quality was increased from 21.45% to 44.58%. The managed pressure well cementing technology helped resolve the problems of cement slurry lossed and low return rate encountered in well cementing operations in the past.
Explore and Study on Well Cementing Anti-Water-Channeling Self-Healing Agent
XIN Haipeng, WU Dahua, ZHANG Minghui, DENG Qiang, WANG Jianyao, ZENG Jianguo
2020, 37(2): 221-225. doi: 10.3969/j.issn.1001-5620.2020.02.015
An anti-water-channeling self-healing agent has been developed to deal with channeling in annular spaces after well cementing. This anti-water-channeling self-healing agent has a core-shell structure, it uses highly water absorbent resin as the core material and the size of the core (a sample passing 140 mesh screen) increases exponentially from original 100 μm to 1898 times of the original size in 30 s after absorbing water, and stabilizes at 2200 times of the original size in 120 s. Another 120-mesh sample absorbs water of 892 times of its original size in 30 s and stabilizes at 1950 times of the original size in 120 s. The core, after wrapped on its surface, does not absorb water for 3 h at 90℃. The anti-water-channeling self-healing agent can effectively plug fractures. When the cement is hydrated, the shell is broken and the anti-water-channeling self-healing agent then acquires water absorbency and self-healing ability. Core experiment showed that the anti-water-channeling self-healing agent can plug fractures in 40 min at 90℃and 2 MPa. Cement slurry test showed that normal density cement slurries containing 4% anti-water-channeling self-healing agent have good rheological property and controllable filtration rate, the thickening time of the cement slurries is linear and normal, and the set cement has high compressive strength, satisfying the needs of shallow well cementing.
Laboratory Study on Leak-Proof Early Strength Tough Cement Surry
LYU Bin, ZHOU Chenyang, QIU Aimin, LI Bo, ZHANG Ye, YANG Xuesong
2020, 37(2): 226-231. doi: 10.3969/j.issn.1001-5620.2020.02.016
In some old oilfields such as Daqing, Changqing and Kelamayi, shallow burial of oil and gas, low bottom hole temperature, long-term wide use of stimulation measures such as water injection, complex geological structure of the reservoirs, as well as mutual interference of different pressure systems, are all factors contributing to the coexistence of leaking and overflow (or blowout) during high angle and horizontal well drilling as well as well cementing. Well cementing in these oilfields imposes higher demands on cement slurries. A new surface-pretreated oil well cement strengthening agent DRB-3S, having the characteristics of low-temperature strength, stable self-suspending ability and good mixing performance, was compounded with expansion material and anti-channeling toughness enhancing material to form a leak-proof tough early strength cement slurry. This cement slurry has good operational performance; the transition time of the thickening process is short, the API filtration rate is low and has zero free water. The 4 h compressive strength at 55℃ is between 7.2 MPa and 11.5 MPa. It is able to stop cement slurry loss into permeable and fractured formations with millimeter-sized flow channels. The cement slurry has provided a powerful technical support to the improvement of the quality of well cementing.
Technology for Cementing Shale Oil Reservoirs in Dagang Oilfield: Study and Application
LI Xiaolin, WU Chaoming, ZHAO Shuxun, LIN Zhihui, WANG Guifu, LING Yong, WANG Lang
2020, 37(2): 232-238. doi: 10.3969/j.issn.1001-5620.2020.02.017
Cementing of the shale oil reservoir section in Dagang oilfield has encountered several difficulties such as complex formation pressure system, active oil and gas, poor compatibility between the potassium salt drilling fluid and the cement slurry, difficulty in displacing drilling fluid mixed with oil, as well as rigorous requirement on the mechanical property of the set cement. Laboratory study was conducted on the cement slurry to be sued and the techniques for performing the well cementing job. A functional pre-pad fluid with oil washing ability was selected for the cementing operation, more than 90% of the potassium salt drilling fluid can be washed off the borehole wall. According to the "four low one high" requirement by Dagang oilfield on cementing the shale oil reservoirs, a tough high strength anti-channeling cement slurry was selected. This cement slurry has transition time for static gelling of 5 min, high compressive strength, low elastic modulus, excellent anti-channeling performance and set cement with outstanding mechanical property. Prior to well cementing, wiper trip with "two centralizers" and "three centralizers" was implemented, the hole was cleaned with high-vis pill containing fibers, and pseudo mud cakes were removed. A set of techniques suitable for shale oil reservoir cementing in Dagang oilfield was established and successfully used in field operation.
Technology for Cementing Directional Wells Drilled for Salt Cavern Gas Storages in Jintan
JIA Jianchao, SHAN Baodong, AN Guoyin, YU Wanbao, WANG Yuanqing, LI Xiaoming, LIAO Hualin
2020, 37(2): 239-243. doi: 10.3969/j.issn.1001-5620.2020.02.018
To improve the utilization of salt rock resources, the second stage of the Phase 2 gas storage construction in Jintan used directional cluster well instead of vertical well previously used to build the gas storages. Cluster well gas storage helps maximize the storage capacity and gas production rate. Problems associated with directional well drilling are hole size of irregularity and eccentricity of casing string. As to well cementing, since the salt is buried in shallow depth with low temperature, cement slurry formulated with saltwater has poor stability at low temperatures, the filtration rate of the cement slurry is difficult to control, and the compressive strength of the cement slurry develops slowly. Losses of cement slurry in the second interval result in cement slurry that is unable to return to the surface. Based on the requirements of salt cavern gas storage on well cementing job, study was conducted on low temperature high strength cement slurry, viscosified saltwater spacer and well cementing operation techniques. The study results showed that the low temperature high strength saltwater cement slurry developed had good stability, fast developed compressive strength, and high later strength, satisfying the needs of cement slurry for cementing directional well for salt cavern gas storages. Viscosified saltwater spacer in combination with techniques for improving the centralization of casing string increased the displacing efficiency of fluid in washout sections and hole sections of irregular sizes, preventing choke and block during well cementing. Use of low flowrate displacement ensured the cement slurry to return to the surface, making the salt section effectively cemented. This well cement technology has been used for 11 times in the second stage of the Phase 2 gas storage construction, the quality of well cementing operation was significantly improved. This technology has provided a reference for other salt cavern gas storage construction.
Optimization of a High Temperature Low Corrosivity Acid Fluid for Application at 180℃ High Temperature
HE Shiyun
2020, 37(2): 244-249. doi: 10.3969/j.issn.1001-5620.2020.02.019
A new high temperature corrosion inhibitor has been developed though molecular structure design and synthesis to deal with problems encountered in high temperature deep well acidification, such as high bottom hole temperature and corrosion of downhole string and downhole tools. The corrosion inhibitor, which can be used at 180℃, was used with other optimized additives to formulate 2 sets of low corrosivity acid fluids for operation at 180℃. Laboratory experimental results showed that:1) the corrosion rate N80 steel in the presence of the corrosion inhibitor at 180℃ was 70 g/m2·h, indicating that the corrosion inhibitor developed has very good corrosion inhibiting capacity. 2) precipitation and stratification were not observed in the acid fluids formulated with the corrosion inhibitor, meaning that the additives used to formulate the acid fluids have good compatibility and filtration control capacity. 3) at 180℃, the average corrosion rates of N80 steel plate in 0.4% and 0.8% gel acids were 87.3 g/(m2·h) and 95.8 g/(m2·h), respectively. In high temperature deep well acid fracturing operation, the high temperature low corrosivity acid fluids had almost no negative effect on downhole strings and downhole tools; tubing strings pulled out of hole after operation had smooth inner walls. The acid fluids had good properties before and after acid fracturing operation, and the well was in safe conditions throughout the operation.
A New Supercritical CO2 Fracturing Fluid Containing Silicon Thickener: It's Rheological Property and Core Damage Evaluation
XU Liu, FU Meilong, HUANG Qian, WANG Jie, ZHAO Zhongcong
2020, 37(2): 250-256. doi: 10.3969/j.issn.1001-5620.2020.02.020
A silicon thickener has been developed to deal with the problems that supercritical CO2 fracturing fluid is faced with, such as low viscosity and poor sand carrying capacity. The rheological properties and core damage of supercritical CO2 fracturing fluid were studied to provide a reference for the selection of thickeners and field fracturing operation. Two thickeners have been developed through solution polymerization; one is polymethylsilsesquioxane (PMSQ) and the other, a copolymer of polymethylsilsesquioxane and vinyl acetate (PMSQ-VAc). The main functional groups of the two thickeners were characterized with IR spectroscopy. The viscosifying effect of the two thickeners in supercritical CO2 fracturing fluids and the rheological property of the fracturing fluids treated with the thickeners were measured with high pressure pipe flow experiment through long pipe. The filtration property and damaging capacity of supercritical CO2 fracturing fluids flowing through long natural cores with artificial fractures were also valuated. It was found in these studies that the thickening effect of the PMSQ thickener and the PMSQ-VAc thickener first increased and then decreased with temperature and pressure. As the concentration of the thickeners increased, the viscosity of the two CO2 fracturing fluids first increased and then decreased. Compared with PMSQ, PMSQ-VAc has better thickening effect in supercritical CO2 fluid; the viscosity of supercritical CO2 fluid can be increased by PMSQ-VAc to 3.892 mPa·s. In cores with permeability of 0.551 mD, supercritical CO2 mixed with PMSQ-VAc had a low filtration coefficient of 1.435×10-2 m/min1/2, a low filtration rate of 0.010 m/min and percent core damage of 16.33%-25.36%, which is weak.
Application of Diversion through Broadband Temporary Plugging Multi-Fracture Fracturing Technology in Sulige Gas Field
HAN Fuyong, NI Pan, MENG Hailong
2020, 37(2): 257-263. doi: 10.3969/j.issn.1001-5620.2020.02.021
To improve the reliability of insulating multi fractures for staged fracturing job in horizontal well completion operation such as open-hole sliding sleeve-packer completion and casing cementing well completion as well as bridge plug segmented multi-cluster fracturing, temporary plugging agents were evaluated in laboratory experiment for their dispersibility, degradability and compression resistance. The diversion through broadband temporary plugging multi-fracture fracturing technology was used in Sulige gas field with good diverting effect. Field application showed that, using diversion through broadband temporary plugging multi-fracture fracturing technology, operation of bridge plug and packer was simplified, number of cable running reduced, operational risk mitigated and operation efficiency improved. Meanwhile, the long-term flow conductivity of fractures can be increased by the connection of multi fractures or fracture network produced by the fracturing operation to gas-rich zones. Compared with offset horizontal wells with similar horizontal lengths and downhole conditions, the open flow rate of gas during well test was increased by 21.1%. After one year of production, the average cumulative gas production of a single well was increased by 3.24×106 m3. The temporary plugging agents and fibers used can be completely degraded in 10 days at reservoir temperature of 90-120℃ in Sulige gas field, fully meeting the requirements of safe and environmentally friendly production.
Anti-Corrosion Behavior of TC4 Alloy In Organic Salt Completion Fluid
ZHAO Guoxian, GAO Fei
2020, 37(2): 264-268. doi: 10.3969/j.issn.1001-5620.2020.02.022
Aiming at applicability of titanium alloy in harsh oilfield environment, the corrosion resistance and electrochemical corrosion behavior of TC4 titanium alloy in high temperature and high pressure completion fluid were studied with simulated corrosion weightlessness test and electrochemical test analysis. The results show that TC4 titanium alloy has high corrosion rate and poor corrosion resistance after 360 h corrosion in potassium formate completion fluid with total pressure of 10 MPa and density of 1.4 g/cm3. The corrosion rate reaches 0.1361 mm/a at 210℃. The anodic polarization curves of TC4 titanium alloy all have passivation zones at different temperatures. With the increase of temperature, the self-corrosion current density and corrosion tendency increase. The electrochemical impedance spectroscopy (EIS) has obvious arc capacitance characteristics. The charge transfer resistance decreases rapidly with the increase of temperature, and the protectivity of passive film decreases. This indicates that the corrosion resistance of TC4 titanium alloy in high temperature and high pressure potassium formate completion fluid decreases gradually.