2017 Vol. 34, No. 2

Display Method:
2017, 34(2)
Numeric Simulation of Factors Affecting the Strengthening of Borehole Wall
LI Jia, QIU Zhengsong, SONG Dingding, LIU Junyi, ZHONG Hanyi, WANG Weiji
2017, 34(2): 1-8. doi: 10.3969/j.issn.1001-5620.2017.02.001
Borehole wall strengthening, as an early-stage borehole wall plugging technology, has been widely applied and developed in recent years, while the influencing factors and mechanism of the technology is still not revealed yet. In a study conducted to analyze the influencing factors and the mechanism of the borehole wall strengthening technology, a finite element model of porous media was established, and the anisotropic properties, location of bridging, rate of mud losses, and the pressure at the rear-end of the fracture were studied for their effects on the strengthening of borehole wall. It was shown in laboratory simulation that rigid plugging material, by mitigating the deformation caused by the pressure reduction at the rear-end of fractures, and transmitting the deformation to around the wellbore, increased the circumferential stress around the wellbore near the fractures after being bridged, thereby causing the fractures to close. It was found that the less the anisotropy of the formation stresses, the more remarkable the tendency of the fractures to close. Also found was that the higher the rate of mud loss, the more beneficial it was for the particles to bridge, and the better for the strengthening of borehole wall. In bridging, the nearer was the location of bridging to the mouth of the fractures, the closer was the pressure at the rear-end of the bridging location to the formation pore pressure, and it was more beneficial to the closure of fractures and to the inhibition of the development of the fracture tips.
Water Base Drilling Fluid Technology for Horizontal Shale Gas Drilling in Sichuan and Yunnan
LIU Jingping, SUN Jinsheng
2017, 34(2): 9-14. doi: 10.3969/j.issn.1001-5620.2017.02.002
Borehole wall instability has been a problem frequently encountered in horizontal shale gas drilling with water base drilling fluids. A new type of water base drilling fluid has been developed for use in shale gas drilling in Sichuan and Yunnan provinces. Higher alcohols and potassium salt of sulfonated asphalt were the main additives used in formulating the drilling fluid. The basic performances of the new drilling fluid were studied through laboratory experiments such as swelling test, hot rolling test, mechanical characteristics analysis, plugging test and contamination test. It was shown that the rates of swelling of the Longmaxi formation in Yunnan, Longmaxi formation and Wufeng formation in Sichuan were reduced to 1.23%, 0.95% and 0.98%, respectively, and the rates of shale cuttings recovery were 98.94%, 99.13% and 99.05%, respectively, indicating that the new drilling fluid had strong inhibitive capacity similar to that of oil base drilling fluids in inhibiting the shales drilled. Compared with conventional water base drilling fluids, the decreasing amplitude of the compressive strength of shales in contact with water base drilling fluids was greatly reduced. The new drilling fluid can plug shale fractures efficiently. Other advantages of the new drilling fluid included salt tolerance (5% NaCl), bentonite contamination tolerance (5%), drilled cutting contamination (20%).
Research and Application of FLAT-PRO Constant Rheology Synthetic Base Drilling Fluid in Deepwater Operation
HU Wenjun, XIANG Xiong, YANG Honglie
2017, 34(2): 15-20. doi: 10.3969/j.issn.1001-5620.2017.02.003
Technical problems encountered in deepwater drilling, such as low temperature, narrow drilling window, formation of gas hydrate by shallow natural gas and hole sloughing etc. have posed rigorous requirements to drilling fluids. Using GTL Saraline 185V as the base fluid, a deepwater synthetic base drilling fluid, FLAT-PRO, was developed based on optimizing the emulsifier, organo-clay, filter loss reducer and other additives. Laboratory evaluation results showed that FLAT-PRO had stable constant rheology at 4-65℃. In permeability test, a permeability recovery of higher than 90% was obtained. This performed very well even when was contaminated with 10% seawater and 10% drilled cuttings. FLAT-PRO was easy to degrade, satisfying the need of environmental protection. An offshore well, LS-A, drilled in South China Sea, with water depth of 1,699.3 m, had formation (main target) temperatures between 34.6℃and 36℃. The coefficient of formation pressure at the shoe of the φ508 mm casing string was lower than 1.14, indicating a narrow safe drilling window. How to control ECD and mud losses were the major concerns of the drilling operation. FLAT-PRO with a density of 1.03 g/cm3 was used in spudding the well, and FSVIS was chosen to maintain the rheology of the drilling fluid. During drilling, rheological parameters of the drilling fluid were maintained as follows:FV=50-70 s, YP=8-15 Pa, φ6 reading=7-15, and φ3 reading=6-12. 2% of HFR was used in filtration control. Drilling, tripping and wireline logging were all successful performed. Filed application showed that the deepwater constant rheology FLAT-PRO drilling fluid had stable rheology at different temperatures, good inhibitive capacity, and superior lubricity, thereby maintaining low ECD during drilling and satisfying the needs for deepwater drilling.
Development and Field Application of a New High Molecular Weight Hollow Micro Beads
LI Sheng, XIA Bairu, WANG Jianyu, SHI Bingzhong, CHEN Cheng, ZHAO Suli
2017, 34(2): 21-25. doi: 10.3969/j.issn.1001-5620.2017.02.004
Hollow plastic microbeads made of polystyrene previously developed are easy to agglomerate when used as a lightweight agent in field drilling fluids, and are thus easy to be bond with drilled cuttings, thereby being removed by solids control equipment and resulting in a gradual increase in mud weight. To solve these problems, efforts have been done on the modification of the body and surface of the microbeads, giving birth to high MW polymer hollow beads with a double-layer structure, SMHPS-2. WF monomer optimization and the determination of the concentrations of critical materials such as catalyst, foaming agent, surface modifier and antistat were performed in developing SMHPS-2, which were dried with spray drying. Laboratory study showed that the particles of SMHPS-2 were in round shape with smooth and dense surfaces. SMHPS-2 had particle sizes less than 100 μm, average density between 0.31 and 0.32 g/cm3, compressive strength of 50 MPa, and remained stable at 90℃. Particles of SMHPS-2 were resistant to abrading, stable in a dispersion, and did not agglomerate by themselves, and did not adhere to drilled cuttings. In field application in the well Jin-111, addition of 4% SMHPS-2 in a base fluid reduced the density of the base fluid by 0.04 g/cm3. SMHPS-2 showed good adaptability to use with the solids control equipment and superior resistance to shearing; no adhesion and agglomeration were observed during drilling.
Application of Aqueous Acrylic Resin in Invert Emulsion Drilling Fluids
HUANG Xianbin, JIANG Guancheng, DENG Zhengqiang
2017, 34(2): 26-32. doi: 10.3969/j.issn.1001-5620.2017.02.005
Asphaltene and humic acid products widely used in oil base muds (OBMs) have deficiencies such as seriously viscosifying the OBMs, high concentration requirement, limited filtration control performance and poor high temperature stability. An aqueous acrylic resin, WAR, was developed for use in OBMs to solve these deficiencies. WAR was synthesized with monomers such as styrene, butyl acrylate, and acrylic acid through emulsion polymerization, and was characterized with IR spectrometry. WAR remained stable at 237℃ (weight loss by 2%), as proved by thermogravimetric analysis. WAR was evaluated in laboratory for its emulsion stability, rheology, filtration control performance, plugging capacity and high temperature stability both in conventional OBMs and clay-free OBMs. It was shown that WAR performed positively in stabilizing the properties of emulsions. Emulsions treated with WAR remained their whole emulsibility after 24 h of standing. WAR had very slight effect on the rheology of OBMs, and appreciable filtration control ability, plugging capacity and high temperature stability. HTHP filter loss tested at 180℃ was less than 5 mL, with the mud cake being dense. After aging at 180° C for 16 h, the percentage of forward plugging was more than 75%, and that of backward plugging was moer than 70%. Compared with oxidized asphalt, the aqueous acrylic resin had better overall performance as an OBM additive. The working mechanism of the aqueous acrylic resin in invert emulsion drilling fluids is also analyzed in this paper.
Development and Evaluation of Drilling Detergent Lubricant CLSD as Fast-drilling Agent
YANG Qianyun, WANG Baotian, CAI Yong, LI Xiuling, YUAN Li
2017, 34(2): 33-38. doi: 10.3969/j.issn.1001-5620.2017.02.006
CLSD is a drilling detergent lubricant made from waste grease under predetermined synthesis process and technical parameters. Laboratory evaluation of CLSD showed that it had good compatibility with other additives, and rendered no bad effect on mud rheology. It moderately reduced API filter loss of the mud. Contact angle of 170.5℃ meant that CLSD was lipophilic. It had good cleaning and wetting performance, and was able to form oil films on the surface of metals. The surface tension of a 0.4% water solution of CLSD was 68.69% lower than that of fresh water, making it easier for the CLSD to go into the fractures formed by brill bit impacting the hole bottom, thus mitigating reservoir damage by water blocking. Using CLSD, the extreme pressure friction coefficient of a drilling fluid was reduced by 91.83%, and mud cake adhesion coefficient reduced by 62.67%. As temperature went up, the lubricity of the drilling fluid treated with CLSD was enhanced, thereby reducing the drilling torque and the friction coefficient of drilling fluids. CLSD had strong inhibitive capacity. It can be used in saturated drilling fluids. It functioned normally at 160℃ or higher. After hot rolling, drilling fluids treated with CLSD did not foam on the whole. The CLSD treated drilling fluids is suitable for use in deep wells and ultra-deep wells, because with an increase in well depth, the property of the drilling fluid becomes more stable. CLSD helped in reducing chip hold-down effect, thereby increasing ROP; in a laboratory simulation, the ROP was increased by 35.2%.
Synthesis and Evaluation of a High Temperature AMPS/AM/NVP Copolymer Filter Loss Reducer
JIANG Guancheng, QI Yourong, AN Yuxiu, GE Qingying, ZHANG Lingyu
2017, 34(2): 39-44. doi: 10.3969/j.issn.1001-5620.2017.02.007
Filter loss reducers presently in use had poor stability and filtration control ability in drilling deep and ultra-deep wells. To overcome these problems, a terpolymer filter loss reducer has been synthesized in laboratory with 2-acrylamido-2-methylpropane sulfonic acid (AMPS), acrylamide (AM), and N-vinyl pyrrolidone (NVP). The optimum synthesis conditions were as follows:molar ratio of AM:AMPS:NVP=6:3:1, concentration of initiator=0.2%, concentrations of the monomers used was 1.5%, respectively, reaction temperature=50℃, and the reaction time=4 h. Structure analysis of the synthesized product with IR spectroscopy showed that it was a terpolymer, and TEM analysis showed that the synthesized product formed an ordered space network structure in water solution. In a 4% fresh water base drilling fluid, the high temperature stability of the synthesized filter loss reducer was remarkably better than that of PAC-LV; the synthesized filter loss reducer functioned effectively at 180℃.
Simulation of Mud Loss in Formations with Fracture Network
LI Daqi, LIU Sihai, LIN Yongxue, KANG Yili
2017, 34(2): 45-50. doi: 10.3969/j.issn.1001-5620.2017.02.008
Based on the Monte Carlo random modeling theory, a 3-D discrete fracture network formation model has been established in an effort to solve the mud loss problem taking place in complex fractured formations. Using the Bingham model drilling fluid, a model describing the mud losses in networked fracture formations was established. This model took into consideration the linear deformation of the fractures. The model was calculated using finite element method to simulate the behavior of mud losses. Studies showed that this model was able to dynamically simulate the flowrate, rate of mud losses and total volume of mud losses inside a fracture. In fractures that were near the borehole wall, the mud flowrate was high, while in fractures that were far from the borehole wall, the mud flowrate was low. After logarithm transformation, the rate of mud loss curve showed obvious irregular fluctuation phenomenon, quite different from the behavior of mud losses in a single fracture. This phenomenon can be used to identify a formation with networked fractures. The stress sensitivity of fractures had greater effect on mud losses. Taking into account the stress sensitivity, the volume of mud losses increased. The volume of mud losses calculated from numerical simulation was close to the theoretical volume of mud losses, indicating the high reliability of the model established. Field application showed that the studying results can be used to find out mud losses into networked fractures. A mud loss control program based on this study was successfully used in controlling a mud loss just in one shot.
New Method for Evaluating Filtration and Mud Cake Building Performance of Drilling Fluid for Shale Drilling
WANG Pingquan, JING Yujuan, PENG Zhen, BAI Yang, XIE Junni
2017, 34(2): 51-56. doi: 10.3969/j.issn.1001-5620.2017.02.009
To satisfy the need for filtration control performance test with dense low permeability media, a test required for shale gas drilling, a simulated low permeability mud cake formed in shale formation has recently been prepared using barite of millimicron in particle size and commercial barite as solid particle materials, and laboratory high-speed mixer and HTHP filter press as experiment equipment. The permeability of the mud cake was gradually reduced by improving the dispersing stability of the millimicron barite and adjusting the mass ratio of the two barites. The final formulation for making the mud cake was as follows:1,000 mL water + 100 g millimicron barite + 10 g polyacrylamide + 50 g sodium polyacrylate + 200 g commercial barite + 7 g plugging agent. The mud cake made with this formulation had average thickness of 2.24 mm, and average permeability of 1.42×10-7 D. The process of making the mud cake had good stability and repeatability. Using the prepared mud cake, several commonly used water base drilling fluids were tested for their filtration performance, further proving that the mud cake prepared with this method was suitable for use in simulating shale formations with developed micro pores and micro fractures, and in effectively evaluating the filtration and wall building performance of drilling fluids across the shale hole sections.
Application of KCl-Amine Polymer Sulfonate Drilling Fluid in Well Mashen-1
FAN Xiangsheng, MA Honghui, RAN Xingxiu
2017, 34(2): 57-63. doi: 10.3969/j.issn.1001-5620.2017.02.010
The Well Mashen-1 is a key wildcat well of the Exploration Branch of Sinopec located at the high position of the Malubei Structure in the Tongnanba tectonic zone, northeast Sichuan. Completed at a depth of 8418 m, the well was designed to explore the Longwang Temple Formation of Lower Cambrian Series. The fourth interval of the well was drilled to 6 225.4~7 699 m, penetrating the Longmaxi Formation consisting of thick shales, which caused severe borehole instability. Problems also encountered in this interval included high formation pressure coefficient, high formation temperature, and contamination to the drilling fluid by carbonate ions, rendering high risk to the drilling operation. Difficulties in running the drilling fluid in the fourth interval were rheology control of high density mud at elevated temperatures, borehole stabilization and carbonate/bicarbonate ions contamination to the drilling fluid. To deal with these difficulties and problems, a series of laboratory experiments were done to select proper additives and then to formulate a drilling fluid suitable for use in drilling the Well Mashen-1. Based on laboratory experiments, a high temperature polyamine BCG-7 was selected as shale inhibitor at a concentration of 0.4% in the drilling fluid. SMP-3, a quality high temperature filter loss reducer that did not viscosify the drilling fluid, was used at a concentration between 5% and 6%. High performance polymer filter loss reducer PFL-L and HPL-3 were added at concentrations of 2% and 1.5%, respectively, they did not viscosify the drilling fluid either. HR-300 and SMS-19, two thinners, were to be used based on the actual situation. An anti-oxidant was used to try to improve the high temperature stability of the drilling fluid. The final basic formulation was as follows:3%NV-1+0.3%KOH+5%KCl+1.5%HPL-3+1%AOP-1+3% SCL+3%FT+5%SMP-3+3%LF-1+0.4%BCG-7+3%QS-2. The actual concentration of each additive was adjusted based on the actual situation if filed application. In drilling the fourth interval, the drilling fluid had good high temperature rheology, strong inhibitive capacity, high plugging performance and tolerance to carbonate/bicarbonate ions contamination. This drilling fluid provided a powerful technical support for the successful drilling of the fourth interval of the Well Mashen-1, and a KCl-amine based polymer sulfonate drilling fluid finally came into being.
Disposing Waste Oil Base Drilling Fluid from the Wei202H3 Platform
WANG Xingyuan, OU Xiang, MING Xiansen
2017, 34(2): 64-69. doi: 10.3969/j.issn.1001-5620.2017.02.011
Waste oil base muds (OBMs) are disposed of presently by burial or reinjection. Potential pollution to environment and waste of large amount of mineral oil are the problems inusing these disposal methods. A study has been conducted on the recycling of waste OBMs from the Platform 202H3. The waste mud had apparent viscosity of 100-120 mPa·s, plastic viscosity (PV) of 80-100 mPa·s, yield point (YP) of 20 Pa, and 10"/10' gel strengths of 20/35 Pa/Pa The particle sizes of the mud lied between 5.59 μm and 13.74 μm. Studies showed that injection of 2 m3 waste oil base mud back into the well We202H3-3, which penetrated the Longmaxi formation, the final gel strength of the oil base mud in use was increased and the YP/PV ratio became uncontrollable. Use the low quality solids from the waste OBMs, a lost control slurry (LCM muds) was prepared and successfully used in controlling mud losses occurred in the well Changning-H12-3. From these practices, it was concluded that the troubles in recycling waste OBMs lied in the large amount of particles with sizes less than 20 μm, which were difficult to remove with the solids control equipment currently available. Technologies currently available in disposing of waste OBMs will be faced with problems such as safety, large spaces required, energy consumption, transportation, environment protection, and cost. It is thus suggested that the waste OBMs be used in formulating LCM muds, which can be used in controlling mud losses in shale gas drilling, thereby reducing economic losses to some extent. It is also suggested that if supercritical CO2 fluid extraction technology can be used in cost control, it will be an important technology in waste OBMs disposal.
Drilling Fluid Technology for Angle Build Section of Horizontal Wells in Iraq Missan Fauqi Oilfield
CHEN Jianxin, ZHAO Zhenshu, LI Guanghuan, HOU Shili, DONG Dianbin, WANG Xiaoqin, WANG Qian
2017, 34(2): 70-74. doi: 10.3969/j.issn.1001-5620.2017.02.012
In horizontal drilling in the Fauqi oilfield, the angle build and hold sections are generally at depths between 3 350-4 480 m, the Cretaceous system, which mainly composed of limestone, mudstone and shale. Long time of hydrocarbon development has resulted in low formation pressure. During drilling, borehole collapse, differential pressure pipe sticking and lost circulation have been encountered frequently. Based on the formation characteristics, a BZ-KSM drilling fluid was used in drilling the well FQCS**. To improve the rheology of the drilling fluid and to prevent the formation of cuttings beds, an additive BZ-YRH was introduced into BZ-KSM. BZ-YFT, a nano plugging agent and a silicate were used to improve the inhibitive capacity of the drilling fluid. To avoid lost circulation, mud density was maintained between 1.22 g/cm3 and 1.28 g/cm3 in the 5th interval. Prior to POOH to change to directional drilling tool, the mud density was increased to 1.35 g/cm3. Field application has shown that this drilling fluid had good inhibitive and plugging capacity, as well as superior filtration control performance and rheology. Downhole problems such as shale dispersion, borehole instability and difficulties in cuttings carrying have been greatly mitigated, ensuring the success of the drilling operation.
Optimization and Application of Horizontal Drilling Fluid in Yanchang Oilfield
LI Wei, ZHANG Wenzhe, DENG Dudu, LI Hongmei, WANG Tao, WANG Bo, WANG Xiaonan, LI Danyang
2017, 34(2): 75-78. doi: 10.3969/j.issn.1001-5620.2017.02.013
The KPAM polymer drilling fluid presently used in horizontal drilling in Yanchang Oilfield has low inhibitive capacity and poor rheology, resulting in frequent pipe sticking and inability to exert weight on bit during drilling. To improve the performance of the KPAM polymer drilling fluid, a cationic emulsion polymer DS-301 and a emulsified paraffin RHJ-1 have been used to replace the main polymers used. DS-301 is a high molecular weight (more than 6,000,000) cationic polymer inhibitor with multiple cationic groups, and is thus able to effectively viscosify the continuous phase of the drilling fluid. RHJ-1 has superior lubricating and inhibitive capacities, synergistically working with DS-301 to enhance the chemical inhibitive capacity of the drilling fluid. Based on laboratory experiments, a drilling fluid formulation containing 0.3% DS-301 and 2.0% RHJ-1 was selected. The new drilling fluid formulation, after hot rolling for 16 h at 100℃, had plastic viscosity (PV) of 25 mPa·s, yield point (YP) of 12.5 Pa, coefficient of friction of 0.233, and percent recovery of shale cuttings of 92.8%, better than KPAM polymer drilling fluid in rheology and inhibitive capacity. Pipe sticking has been greatly mitigated since the use of this new drilling fluid. 1% extreme pressure lubricant JM-1 was added in the drilling fluid to improve its lubricating performance and solve the problem of being unable to exert weight on bit in horizontal drilling, and the coefficient of friction was further reduced to 0.137. In field application, the filtration rates of the drilling fluid in three wells were controlled below 5 mL, and the ratios of YP/PV at about 0.48 Pa/(mPa·s). Cuttings carrying capacity of the drilling fluid was improved, and borehole wall stabilized. No downhole troubles have ever been encountered during drilling, and higher ROP was achieved.
Comparison of Performances of SMP-I and SMP-II at High Temperature and in Salt Environment
XU Chuntian, ZHANG Ruifang, XU Tongtai, XIAO Weiwei
2017, 34(2): 79-82. doi: 10.3969/j.issn.1001-5620.2017.02.014
Drilling fluid additives should have their range of use clearly defined to make the best use of them, and great attention should be paid on this issue. Take the SMP-Ⅰ and SMP-Ⅱ as examples, the application characteristics, production technology, and the mechanisms of reducing filtration rate and resisting salt contamination are analyzed in this paper. The ranges of use of SMP-Ⅰ and SMP-Ⅱ are discussed and the differences in high temperature and salt-resistant performances of the two additives manufactured by different production technologies are compared. Laboratory experiment has shown that in drilling fluids with salinity less than 2%, and borehole temperature below 180℃, the performance of SMP-Ⅰ was better than SMP-Ⅱ. At 120℃ and 150℃, SMP-Ⅰ worked well in different salinities up to saturation, while SMP-Ⅱ only functioned in drilling fluids containing 25% salts or in under-saturated and saturated drilling fluids. At 180℃, SMP-I can be used in saltwater drilling fluids with salinities less than 20%, while SMP-Ⅱ can be used in saltwater drilling fluids with salinities greater than 20% to saturation.
Treatment of Formation Water Invasion in Air Drilling
ZHANG Weijun, DENG Mingyi, XIANG Chaogang, CHEN Junbin, OU Yangwei
2017, 34(2): 83-86. doi: 10.3969/j.issn.1001-5620.2017.02.015
A serious concern in air drilling is the invasion of formation water into the hole, viscosifying the dry cuttings into viscous lumps which are adhered at the surface of the drill string and borehole wall, resulting in pipe sticking. Based on the mechanism that fluid with low surface tension can penetrate fast into and break the lumps, 9 surfactants was selected for the evaluation of their osmosis, and dispersing performance using static measurement of surface tension, wetting angle measurement, timing-area method, area measurement in specific time span, round fabric method, hot rolling test method and particle size distribution measurement. The 9 surfactants tested all had wetting ability. Surfactants with smaller hydrophobic groups in their molecular structures had strong osmosis. The dispersity of anionic surfactants is governed by the electric double layer theory, while the dispersity of nonionic surfactants is governed by steric effect. High molecular weight polymers have better dispersity than common surfactants. Laboratory experimental results showed that diesel oil treated with CJY had strong osmosis and dispersity, making it a better chemical in disintegrating mud lumps than oil based pipe sticking agent JKZ. Diesel oil treated with CJY performed better at elevated temperatures. This study provides a method for the solution of formation water cut during air drilling.
Effects of Particle Size on Hydration Heat and Mechanical Performance of Cement
HUANG Jin, YAO Xiao, JIANG Xiang, WANG Zhiguo, LV Zhiguo, LI Zhiyuan
2017, 34(2): 87-92. doi: 10.3969/j.issn.1001-5620.2017.02.016
The particle sizes of oil well cement are closely related to its performance and use. Oil well cements of different particle size distribution obtained with three grinding methods have been studied for their early hydration exothermic rate (rate of hydration heat liberation), hydration product of set cement, pore structure and the micro-morphology of particles using ICC, XRD MIP and SEM experiments. It was shown that physical grinding cannot produce nano particles; it can only produce ultra-fine particles. Particles size distributions of cement slurries with the same water/cement ratio had no appreciable effect on the density of the slurries and the hydration products. On the other hand, cement slurries with smaller particle sizes had shortened thickening time, poor rheology, reduced percentage of free water, and better stability. Meanwhile, ultra-fine cement particles had enhanced hydration reactivity and higher hydration heat and hydration exothermic rate. The cumulative hydration heat released in 24 hours of a 0.013 mm ultra-fine cement (MC1000-0.5) was 91.03% higher than that of conventional class G cement (G-0.5) at the same water/cement ratio of 0.5. The ultra-fine particle cement produced more hydration products in a short period, and the set cement had improved early strength and impervious performance, and reduced total porosity. The set cement of a 0.013-mm ultra-fine cement (MC1000-0.7) had 1-d compressive strength and flexural strength that were 226.32% and 153.13% higher than those of the class G cement (G-0.7) respectively at the same water/cement ratio of 0.7. The MC1000-0.7set cement had 28-d total porosity and permeability that were 10.1% and 41.7% lower respectively than those of the G-0.7 set cement, while the late-stage compressive strength of the MC1000-0.7 set cement only slightly increased.
Research on the Hydration Mechanism of A Kind of Solidifiable Leakage-proof Working Fluid
LI Zaoyuan, ZHOU Jingdong, DENG Zhizhong, GUO Xiaoyang
2017, 34(2): 93-98. doi: 10.3969/j.issn.1001-5620.2017.02.017
While cementing in the low pressure and easy to leak hole section, low formation bearing pressure、leakage and channeling often lead to low cementing quality. So a low density (1.30 g/cm3) working fluid which can be solidifiable and prevent leakage was studied to solve the problem. The working fluid was made form the high quality spacer fluid in which a kind of curing properties of the material (2.60~2.90 g/cm3)replacing weighting material was added. The working fluid can effectively balance formation pressure and cure in annulus, thus preventing leakage and improving cementing quality. The strength of samples after curing and hydration mechanism of the working fluid were mainly analyzed in the paper. The results showed that the structure of the curing strength development is that hydroxyl ions damaged the vitreous body structure of the curing agent. Through the adjustment of the formula, curing test specimens from 30~90℃ had a certain compressive strength. The research and development of the working fluid system provided a new way for the design of the leak protection working fluid. The working fluid system can also be applied to sealing in drilling engineering to increasing the formation bearing pressure.
Study and Application of Slim Hole Cementing Technology for Ultra-deep Well Mashen-1
KANG Haitao, ZENG Yanjun, MU Yajun, CAI Yunping, FENG Lin
2017, 34(2): 99-105. doi: 10.3969/j.issn.1001-5620.2017.02.018
The Well Mashen-1 is the deepest well found in Asia, the gas zone of which has been sealed with 146.1 mm liner string. Difficulties encountered during drilling included HTHP, small annular clearance, low displacing efficiency, narrow drilling window, and severe U-tube effect. In combating these problems, it was considered that dynamic pressure-bearing experiment was able to more accurately simulate the borehole pressure change during well cementing, thereby helping prevent mud losses. Fluids entering the borehole with density grading and rheology grading were beneficial to increasing displacing efficiency. Three-stage flushing prepad had strong resistance to contamination and better flushing performance. A high temperature anti-channeling latex cement slurry was developed based on the optimized high temperature cementing additives. It had good high temperature stability and strong antichanneling ability. The set cement had high compressive strength and good elasticity and toughness. The U-tube effect can be mitigated with varied flowrates and effective laminar flow displacing, in this way the lost circulation during well cementing was avoided and the displacing efficiency ensured. By adding 0.7%BS200-G and 3%BS200R (retarders) in the cementing slurry, the thickening time became adjustable and was not vulnerable to the effects of density and temperature anymore. JR, a latex, was added at percentage of 12%, and the lead slurry and tail slurry had right-angle thickening characteristics, with values of 0.9 and 0.5, respectively. The gel strengths of the cement slurry had transit time of 28 min and 22 min, respectively. The cement slurry also had high mobility and good rheology. After adding 50% quartz sand, the effect of high temperature on the strength of set cement became weakened, and the strength of the set cement showed good late-stage development. Adding 1% BS6000, a plasticizer into the cement slurry, the set cement had elastic modulus 53.13% lower than that of conventional cement slurries, indicating that the cement slurry had good plasticity. The experimental results showed that the cement slurry had good high temperature stability, good rheology, strong anti-channeling ability, and excellent mechanical performance when set. The Well Mashen-1 was successfully cemented with high cementing job with the high temperature anti-channeling latex cement slurry and the technology discussed above.
Cementing Tight Reservoir with Low Temperature High Strength Tough Cement Slurry
DING Zhiwei, YANG Junlong, WANG Yao, JI Hongfei, YUAN Xiong, RAO Kaib
2017, 34(2): 106-110,116. doi: 10.3969/j.issn.1001-5620.2017.02.019
The Yanchang tight reservoir in the Changqing has shallow burial depth and low static bottom hole temperature. Conventional cement slurries used in this area produced highly brittle set cements with strengths that are developed very slowly. In large-scale stimulated reservoir volume fracturing, the brittle set cement easily lost its integrity, severely endangering the production of tight oil and the production life of the well. To solve these problems, a low temperature high strength tough cement slurry has been formulated with a low temperature accelerating early strength DRA, a low temperature strengthening material DRB, a low temperature toughness improving agent DRE-300S, and some other cement slurry additives. This cement slurry, at 55℃, had 24-hour compressive strength of 35.8 MPa, and 168-hour compressive strength of 50.6 MPa. Compared with conventional cement slurries, the compressive strength of this cement slurry was increased by 33.1%, and the elastic modulus reduced by 14.3%, showing good low temperature toughness. The sealing integrity of the cement sheath under the action of alternating stresses was greatly improved. This cement slurry has been successfully used four times in cementing the φ139.7 mm production casing string in horizontal wells in Changqing Oilfield, providing a technological base for the application of low temperature high toughness cement slurries.
Liner Cementing the high pressure gas wells in the Block Gaoshiti-Moxi
SONG Yousheng, ZOU Jianlong, ZHAO Baohui, LIU Aiping
2017, 34(2): 111-116. doi: 10.3969/j.issn.1001-5620.2017.02.020
In cementing the φ177.8 mm liner string in high pressure gas wells in the Block Gaoshiti-Moxi of southwest oilfield, problems such as active gas zones, narrow drilling windows, poor compatibility of fluids and large temperature difference at high temperatures, were encountered. Technical measures were prepared to deal with these problems, and a self-healing anti-channeling high density cement slurry was developed for cementing wells with large temperature difference at high temperatures. Laboratory study of the cement slurry showed that the cement slurry had density between 2.0 g/cm3 and 2.8 g/cm3, and in field application, the cement slurry can be prepared to have a density of 2.6 g/cm3 in one mixing circulation. This cement slurry functioned at temperatures between room temperature and 180℃. Differences between the density of the top and bottom of cement slurry column was less than or equal to 0.05 g/cm3. The fluid loss of the cement slurry was less than or equal to 50 mL. The thickening time had good linear relationship with the concentration of retarders, and the transit time for the thickening of the cement slurry was not longer than 10 min. The maximum transit time of the gel strengths of the cement slurry was 20 min. The 24-hour compressive strength of the set cement was greater than 10 MPa, and the 48-hour compressive strength of the cement top was greater than 3.5 MPa. The strength of the cement slurry developed fast at low temperatures. The set cement formed had stable non-shrinking volume, possessing a mechanical performance that is similar to that of tough cement. The cement slurry expanded when in contact with oil and gas, ensuring the quality of bonding between cement sheath with casing string and borehole wall, and the integrity of sealing, which in turn mitigating the risk of gas channeling after cementing job. High quality of cementing job with this cement slurry was obtained in cementing the well Gaoshi-X and the well Gaoshi-Y, with no pressure developed in the annular space after cementing.
Development of a New Low Density High Strength Hydraulic Fracturing Proppant
DONG Bingxiang, CAI Jingchao, LI Shiheng, NI Xiaojin, CHEN Ting, TU Zhiwei
2017, 34(2): 117-120,125. doi: 10.3969/j.issn.1001-5620.2017.02.021
The use of high performance low density ceramic proppants in reservoir fracturing not only avoids the settling of proppant particles during their migration in fractures, thereby effectively lengthening the fracturespropped and enhancing the fluid conductivity of the fractures, it also helps relax the requirements for the performance of fracturing fluid, and reduce the pumping power required and minimize operating risks. This paper discusses the preparation of a low density high strength ceramic proppant from a low-grade bauxite (containing less than A12O3) and fly ash, an industrial waste. Mixtures of the bauxite, the fly ash and some special accessories in a certain ratio were ground, and then calcined at high temperatures to form spherical ceramic particles with low density and high strength. The proppant prepared had particle sizes between 0.45 mm and 0.9 mm, bulk density between 1.40 g/cm3 and 1.55 g/cm3, and apparent density of ca. 2.75 g/cm3. In laboratory test, only 5% of the proppant particles were broken into pieces under a closure pressure of 52 MPa. This ceramic proppant, because of its superior performance, will find wide application in low permeability reservoir development and shale gas reservoir stimulation.
Study and Application of a New Self-diverting Acid for Use in Sandstone Fracturing
GAO Shang, FU Yangyang, MENG Xianghai, LIU Changlong, WANG Rui
2017, 34(2): 121-125. doi: 10.3969/j.issn.1001-5620.2017.02.022
The main reservoirs in the Bohai oilfield are characteristic of big permeability differences between different production layers, and high heterogeneity. This has resulted in the acid solution flowing mainly into the high permeability layers, further aggravating the permeability differences, making it difficult to effectively improve the conductivity of the layers with medium and low permeability, and resulting in poor acidizing job quality. A new self-diverting acid was developed to deal with these problems. The self-diverting acid was viscosified with ZX-1, an amphoteric surfactant. Laboratory experiments have been conducted on the rheology, compatibility, gel-breaking and the diverting acid stimulation performance of the self-diverting acid. It was shown that the simulated fresh acid had viscosity of 6 mPa·s, which was easy to inject into reservoir formations. The viscosified simulated self-diverting acid had viscosity of 60 mPa·s, highly resistant to shearing. And the simulated residue acid had viscosity of only 2 mPa·s, easy to be flowed back. The self-diverting acid was well compatible with corrosion inhibitors, iron ion stabilizers, swelling inhibitors and cleanup additives, and no precipitation and residue were observed in the experiments. Gel breaking of the self-diverting acid was easy to realize with isopropyl alcohol, demulsifiers, ethylene glycol mono-butyl ether and acid solutions. Viscosity of the self-diverting acid after gel breaking was less than 10 mPa·s. Part of the gel within the viscosified acid may not be broken at the time of application, but with time, it will automatically become broken, rendering no permanent damage to the potential of reservoir. The self-diverting acid had good diverting property, with the permeability difference ratio increased from the initial value of 2.00 to the final value of 10.70. After acid stimulation, the permeability of the low-permeability layers was enhanced remarkably, and the permeability differences between the high-and low-permeability layers were reduced. When the permeability difference reached 10.7, diverting acid stimulation can still be achieved. Based on the results of the field application, the self-diverting acid will find wide application in the future.
Calculating Low Temperature Phase Equilibrium of NaCl-KCl-CaCl2 Completion Fluid Based on Pitzer Model
ZHAO Zhiqiang, CHEN Yuanbo, YI Yong
2017, 34(2): 126-130. doi: 10.3969/j.issn.1001-5620.2017.02.023
Crystallization point, a main performance index of composite brine completion fluids, can only be obtained through laboratory experiments because most of the articles and handbooks only give the crystallization point of the single salt. If the crystallization point of a composite brine can be calculated with mathematical model, then large amount of tedious experiment can be saved, and the optimization of composite brine completion fluid can be achieved using the calculated data. Using the Pitzer model and the Spencer model parameters, salts commonly used in completion fluids, such as NaCl, KCl and CaCl2, were calculated for their solid-liquid phase equilibrium both as single salt and binary salts. The liability of the calculation was verified using documented data and experiment data. It was shown that at temperatures below 25℃, the relative standard deviation between the calculated values and the documented data was less than 0.1, satisfying the need for completion fluid study and design. At temperatures above 25℃, the relative standard deviation for KCl became larger, and the Pitzer parameters of KCl needed to be adjusted for phase equilibrium recalculation.