2016 Vol. 33, No. 6

Display Method:
2016, 33(6)
Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
YAO Rugang, ZHANG Zhenhua, PENG Chunyao, FENG Yanyun, DING Guangbo
2016, 33(6): 1-9. doi: 10.3969/j.issn.1001-5620.2016.06.001
This paper discusses the instruments and procedures available presently for evaluating fltration property, sizes of pore throats, thickness and compressibility of mud cake. Analyzed in this paper are the status quo of using SEM and energy spectrum in studying the microstructure of mud cake and the distribution of mud cake constituents. Studies presently conducted were focused on the observation of surface topography, while knowledge about the interior microstructure of mud cake is still in demand when optimizing the quality of mud cake. The spatial distribution of the microstructure of mud cake needs to be extensively studied in the future to further understand the mechanism of fltration control and the way of reducing fltration rate. These studies are of help to the development and perfection of the basic theory of controlling drilling fluid fltration and ability of building mud cake, and will provide guide and technical support to the development of new high performancemud additives and to the improvement of drilling fluid technology.
Progress in Studying Cement Sheath Failure in Perforated Wells
LI Jin, GONG Ning, LI Zaoyuan, HAN Yaotu, YUAN Weiwei
2016, 33(6): 10-16. doi: 10.3969/j.issn.1001-5620.2016.06.002
Perforation well completion is a widely used completion method, and is of great importance to oil and gas well stimulation. With more and more wells completed with perforation, more attentions have been paid to the sealing integrity of cement sheaths after perforation, especially the perforation of wells with thin pay zones. Research work presently done has been focused on the effects of perforation on casing strings, while little attention has been paid to the damage of cement sheath. Oil and gas well perforation has characteristics such as being powerful, short time, high temperature, and being highly destructive. It is pointed out in this paper, based on analysis, that the diffculties in studying the failure of cement sheath mainly lie in laboratory simulation, determination of the degree of damage to the cement sheath, determination of the cement sheath's resistance to impact under practical conditions, and ascertaining the effects of perforation parameters on the integrity of cement sheath, etc. Researches presently done on the topics such as perforation simulation methods used both in China and abroad, integrity of cement sheath after perforation, shock or impact resistance of cement sheath, and the effects of perforation parameters, are summarized in this paper. Defciencies of the researches are also discussed herein. Also included in this paper are technical measures concerning self-healing cement, cement slurry and set cement performance designs, optimization of perforation parameters, and prediction of dynamic damage to downhole cement sheath etc.
Study and Application of a High Temperature Drilling Fluid with Strong Plugging Capacity
KONG Yong, YANG Xiaohua, XU Jiang, LIU Guichuan, ZHANG Guo, JIN Junbin, LI Xiong
2016, 33(6): 17-22. doi: 10.3969/j.issn.1001-5620.2016.06.003
A high temperature borehole wall stabilizing agent SMNA-1 was developed to resolve problems encountered in high temperature deep well drilling. SMNA-1 functions at high temperature to above 200℃. It has a rigid molecular structure and is deformable at high temperature. SMNA-1 is able to enhance the strength of mud cake through its deformability and cohesion capacity. SMNA-1, through its hydrophobicity, also forms a sealing membrane on the surface of mud cake to bind free water and enhance the toughness and consistence of the mud cake, thereby reducing HTHP flter loss and enhancing the capacity of drilling fluid to plugging and stabilizing borehole wall. A high temperature polymer flter loss reducer, SMPFL-L, was synthesized with acrylamide, 2-acrylamide long carbon chain sulfonic acid and diene sulfonic acid through free radical polymerization. SMPFL-L has low widely distributed molecular weight. A saturated saltwater drilling fluid treated with 2%SMPFL-L had its HTHP flter loss reduced to 54 mL. The property of SMPFL-L remained stable at 210℃, and had good deflocculating ability. SML-4, a high temperature salt-resistant flter loss reducer, has been developed for use in high density muds weighted with weighting materials that will result in high solids content. SML-4 is able to alter the surface behavior, enhance the dispersity, and thin the hydration flm of weighting material. A high density saltwater drilling fluid treated with 4% SML-4 had its API flter loss reduced from 164 mL to 5.8 mL, without increasing the viscosity of the drilling fluid. A drilling fluid of 2.0 g/cm3 treated with 2% SMJH-1 had its extreme pressure friction coeffcient reduced by 24%. A high temperature drilling fluid with strong plugging capacity has been developed with SMNA-1 as the main additive, SMPFL-L and SML-4 as flter loss reduces, SMJH-1 as high effciency lubricant. This drilling fluid formulation was successfully used in drilling the third interval (1,300 m) of the well Shunbei-1-1H located in Xinjiang, and no downhole troubles were encountered. The average percent hole enlargement was only 6.88%, and good application results were achieved.
Study on Alkyl Polyglucoside Derivative Drilling Fluid and Its Use In Shale Gas Drilling
ZHAO Hu, LONG Daqing, SI Xiqiang, WANG Shanju, SHI Peiqian, LIU Jiezheng, WU Jian
2016, 33(6): 23-27. doi: 10.3969/j.issn.1001-5620.2016.06.004
The YS108 shale gas block is located in Huangjinba, Zhaotong, Yunnan Province, and the pay zone of this block is the Longmaxi formation of the lower Silurian series. The lithology of the pay zone is mainly gray, black shales which are easy to slough and collapse. In horizontal drilling, high friction and drag, pipe sticking and diffculties in hole cleaning are problems that have been frequently encountered. To mitigate these diffculties, an alkyl polyglucoside (APG) derivative drilling fluid was formulated with NAPG, CAPG and APG as the main additives. NAPG is a polyether amino APG made from APG by introducing polyether and amino groups into the APG molecular structure. NAPG has better inhibitive capacity, high temperature stability and lubricity. CAPG is made from APG by introducing quaternary ammonium group into the APG molecular structure. CAPG has better inhibitive capacity and high temperature stability. NAPG and CAPG effectively reduce the Zeta potential and hence the activity of shales. APG was used in the drilling fluid as the main lubricant, plugging agents of different sizes (0.03-100 μm) and low molecular weight alkyl glucoside viscosifer were used to satisfy the needs of plugging micro fractures found in the Longmaxi shales. This drilling fluid had 7.5 min API flter loss of 0 mL, HTHP flter loss≤5 mL. The extreme pressure friction coeffcient was less than 0.10 if mud density was less than 2.30 g/cm3. As a drilling fluid with strong inhibitive capacity, good plugging capacity and good lubricity, the APG derivative drilling fluid successfully helped solve the diffculties previously encountered. In feld application, gauge hole, good hole cleaning and good lubricity were obtained. Compared with 6 wells drilled nearby with high performance water base drilling fluids and wells drilled in an adjacent block, the well drilled with this drilling fluid had ROP increased by 14.6%-18.8%. The use APG derivative drilling fluid has satisfed the needs for horizontal shale gas drilling and well completion.
Shale Inhibition Characteristics of a New Polyamide-Amine Dendrimer
TANG Zhichuan, QIU Zhengsong, ZHONG Hanyi, ZHANG Xin, ZHANG Daoming
2016, 33(6): 28-32. doi: 10.3969/j.issn.1001-5620.2016.06.005
Dendrimers, because of their unique molecular structures and characteristics, have been receiving more and more attention in recent years. Polyamide-amine (PAMAM), the most understood dendrimer, has been widely used in many felds, including oilfeld chemistry. In a recent study, the inhibitive capacity of PAMAM with different generations was evaluated through bentonite yield test, hot rolling test and particle size distribution test etc. Using surface tension tester, Zeta potentiometer and X-ray diffraction tester, PAMAMs of different generations were characterized. It has been shown that PAMAM s of different generations (G0-G5) all have superior shale inhibitive capacity, better than that of KCl and Ultrahib (a polyamine product used as a shale inhibitor). The adsorption of PAMAMs in between the layers of clay is related to their concentrations. At low concentrations, the adsorption is monolayer adsorption; at higher concentrations, the adsorption becomes double-layer adsorption. PAMAM has high intensity of amine base at its surface, and after partial protonation in water, it is adsorbed on to the surface of clay particles through electrostatic force and hydrogen bond, reducing the hydration repulsion of clay particles and squeezing interlayer water molecules out of clay, thereby inhibiting the hydration and dispersion of shales.
Borehole Stability in Drilling the Paleogene System and Inner Buried Hill in Huabei Oilfeld
WANG Dongming, CHEN Mian, LUO Yucai, YU Jiantao, XU Minglei, YU Haifa, YANG Kai
2016, 33(6): 33-39. doi: 10.3969/j.issn.1001-5620.2016.06.006
The lithology of the Paleogene system in the Huabei oilfeld is mainly sandstone and mudstone, intercalated occasionally with basalt and coal bed. Different formation pressure systems have been found in this oilfeld. Time required for coping with troubles during drilling accounted for 73.62% of the total time required for coping with troubles encountered in the whole process of drilling operation. The destabilization mechanism of the micro-fractured Paleogene system has been studied from mineral analysis, rock mechanics, formation stress measuring to mechanism of borehole wall destabilization. Large variations of cohesion (6-25 MPa) and angle of internal friction (26°-45°) of formation rocks and high formation stress cause micro fractures along the weak planes in rocks, resulting in borehole collapse and lost circulation. Abundant clays cause the formation to hydrate and swell, and after long time of soaking in water, network of fractures result. When pressure of mud column is greater than the collapse pressure of formation, the widths of the fractures increase exponentially, resulting in borehole wall sloughing. To stabilize borehole wall, Polyetheramine and a nano plugging agent were introduced into KCl drilling fluid. Polyetheramine inhibit osmotic hydration of clay through ether bonds and hydrogen bonds, and the unique action of amino group. This technology has been used in several wells such as Yangtan-1, Wen'an-101x and Antan-1x which penetrated the Paleogene system, no downhole troubles have occurred. The well Yangtan-1 successfully penetrated the long section shale formation which experienced severe borehole wall collapse in adjacent wells. The average hole enlargement of the well Yangtan-1 was only 1.8%, and the maximum hole enlargement, 14.82%. The well Antan-1x had maximum mud density of 1.50 g/cm3, 0.19 g/cm3 less than the mud density used in adjacent wells. Furthermore, excessive mud density is disadvantageous to borehole wall stabilization. It is suggested that the mud density should only be 15% higher than the equivalent density of collapse pressure, provided that there is no well control risk.
Experimental Study on Oil Base Mud Loss Control with Gel LCM
WANG Can, SUN Xiaojie, QIU Zhengsong, LIU Junyi, HUANG Daquan, ZHANG Xianbin, Pu Dan
2016, 33(6): 40-44. doi: 10.3969/j.issn.1001-5620.2016.06.007
Loss of oil base mud downhole is diffcult to stop in feld operation and causes great economic loss. An oil base mud loss control method is presented to effciently control oil base mud loss. This method uses gel lost circulation material (LCM) to control oil base mud loss. In selecting additives for gel LCM, a gelling agent NJZ was found to have good solubility in diesel oil and had good gelling capacity. NJZ reacted very well with a crosslinking agent JLJ to form high quality gels. It did not form good gel with the crosslinking agent AlCl3f 6H2O and NaOH. Highest gel strength was obtained by reacting a 10.0% NJZ solution with 4.0% crosslinking agent solution under the action of an emulsifer EHJ. The formulation of the gel LCM was optimized by orthogonal experiment, and the effects of temperature, pH and shearing on gel strength were analyzed. Laboratory experiment has shown that the gel LCM can be used the way cement LCM is used, and can be squeezed in multiple times. Compared with water base gel LCM, this oil base gel LCM worked better in stopping mud loss and has good high temperature stability; it had high gel strength even at 120℃, and was able to tolerate a pressure gradient of 1.05 MPa/m.
Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
WANG Xin, ZHANG Minli, WANG Qiang, ZHUANG Wei, ZHANG Weijun, WANG Zhibin, LI Yifeng
2016, 33(6): 45-50. doi: 10.3969/j.issn.1001-5620.2016.06.008
Four blocks in the Qaidam Basin, Niudong, Lenghu, Zahaquan and Yingxi, have formation rocks with complex lithology, such as salt, gypsum, mirabilite, and hard and brittle shales etc. Downhole troubles have been frequently encountered in previous drilling operations. The Niudong nasal structure in the piedmont of the Altun Mountain in the basin, affected by the orogenesis, has overall formation dipping angles between 60° and 70°. High formation stress, high pressure saltwater and varied coeffcients of pressure have resulted in frequent borehole wall instability in open hole section. A BH-WEI drilling fluid for the so-called "three high" (high pressure, high sulfde, and high risk area) wells, has been used in drilling 20 wells since 2013. To perform well in drilling fluid technical service, relevant data were investigated prior to drilling. Based on laboratory experiment and feld practice, it was concluded that drilling fluid with low activity, strong plugging and inhibitive capacity was benefcial to borehole wall stability. Four key exploratory wells, the frst multi-lateral horizontal well and the frst horizontal well in Zahaquan have been completed, the maximum mud density used was 2.35 g/cm3, the average percentage of hole enlargement was 4.67%, and the ratio of successful wireline logging was 100%. The well Zaping-1 is the frst horizontal well targeted with tight oil reservoir in Zahaquan. In the block Dongping, a four-interval horizontal well was drilled in 2013 with Weatherford's MEG drilling fluid. This well was not be able to drill to the designed depth because of severe mud losses and other downhole troubles. Using the BH-WEI drilling fluid, six horizontal wells were completed successfully in 2013-2014 in the same block, and no downhole trouble has been encountered throughout the drilling operations. Two horizontal wells, Ping-1H-2-1 and Ping-1H-2-2, put into production in 2014, were both high production rate wells in the same block; the average daily gas production rate was 50×104 m3/d. Field application has shown that the BH-WEI drilling fluid had simple formulation, and the mud properties were thus easy to maintain. The BH-WEI drilling fluid had good shear thinning property, high YP/PV ratio, low plastic viscosity, low pressure loss in annular space, good hole cleaning performance and good lubricity and inhibitive capacity. Using this drilling fluid, borehole collapse in drilling the dark gray Jurassic mudstone, inability to exert WOB in horizontal drilling and differential pipe sticking were avoided. To concluded, the BH-WEI drilling fluid is a unique drilling fluid suitable for use in drilling exploratory well and horizontal well in the troublesome drilling areas in Qinghai oilfeld.
Method of Evaluating Corrosion Rate of Formates to Casing and Tubing Strings and the Influencing Factors
YANG Xiangtong, XIAO Weiwei, LIU Hongtao, XU Tongtai, XIE Junfeng, ZHANG Ruifang
2016, 33(6): 51-57. doi: 10.3969/j.issn.1001-5620.2016.06.009
Standard method for evaluating the corrosion rate of formatesis not presently available. A method of evaluating the corrosion rate of formates to casing/tubing strings has been presented with an idea borrowed from the methods of evaluating the corrosion rate of metals. In laboratory experiment, metal coupon weight loss method and a CGF-II HTHP static corrosion tester were used to study the influencing factors such as the type of the formate, production technique, pH, steel material quality, density, and retarder etc. It has been found that using TP140 steel coupon, the corrosion rate of sodium formate was more than 2 times that of potassium formate, because the Cl content in sodium formate (0.619%) was greater than the Cl content in potassium formate (0.0243%). For potassium formate, different production processes resulted in different sulfur contents; potassium formate A contained 0.18% sulfur, far more than that of potassium formate B (0.0477%) and potassium formate C (0.046%), and thus, the corrosion rate of potassium formate A was much higher than that of the latter two. The corrosion of formate salts to steel is much severe under acidic conditions. Water solutions of formate salts taken from a well site needed to be buffered with sodium carbonate and sodium bicarbonateor potassium carbonate and potassium bicarbonate. The corrosion rate of TP140 steel in potassium formate solution was 20 times of the steel BG13Cr or JFE13Cr, indicating that potassium formate had lower corrosion rate to stainless steel than to carbon steel. Since high concentration of HCOO- is good for the protection of steel, the corrosion rate of TP140 steel in 1.20 g/cm3 potassium formate solution was more than 2 times of the corrosion rate of TP140 in potassium formation solution of 1.40-1.57 g/cm3. Thus, corrosion inhibitors should be used when low density formate muds are used. Based on these experimental data, the use of corrosion inhibition measures can be justifed when using formate drilling fluids.
Treatment of CO2 Contamination to Water Base Drilling Fluids
CHEN Fu, YANG Mei, AI Jiawei, LI Wei, LUO Taotao, CHEN Junbin
2016, 33(6): 58-62. doi: 10.3969/j.issn.1001-5620.2016.06.010
Many technologies handling CO2 contamination to drilling fluids have shortages in practical use. This paper summarizes the defciencies of the methods commonly used, and presents advices for the treatment of CO2 contamination based on the mechanisms of contamination:drilling fluid should have moderate bentonite content, and Ca(OH)2 and CaCl2 should be used. High temperature saltresistant and highly adsorptive drilling fluid additives should be used, and old mud replaced with new one if necessary. Contamination of drilling fluids by CO2 has been encounteredin drilling the wells XX46-X1and XX008-6-X2. To cope with the CO2 contamination in drilling the well XX46-X1, centrifuges were used to control solids content and vacuum degassers used for continuous degassing of the drilling fluid at the surface. Mud density was increased to 2.0 g/cm3 to prevent CO2 gas cut. A proper amount of 0.2% Ca(OH)2, SMP-II, SMP-III, RSTF (high temperature salt-resistant flter loss reducer), HTX (high temperature thinner) and NaOH solution were usedto minimize the negative effects of CO2 on the properties of the drilling fluid. 0.5% CaCl2 solution was used when the CO2 gas cut became severe in late period. With these treatment, the viscosity and gel strengths of the drilling fluid were reduced, and the rheology and flter loss controlled, satisfying the needs of engineering and achieving the desired results.
Application of Drilling Fluid Zero-discharge Technology in Bailu Lake Multi-well Pad
XU Yunlong, XU Dui, ZHANG Xiaoming, XIA Wenan, LIU Tianke, SUN Ronghua
2016, 33(6): 63-67. doi: 10.3969/j.issn.1001-5620.2016.06.011
The Bailu Lake multi-well pad is located in a scenic area where environmental protection requirements are tough and solidifcation of waste drilling fluid for burial is prohibited. Multi-well pad technology was adopted in the drilling of 43 wells in this area to conform to the environmental protection requirements. Diffculties encountered during drilling included fast drilling, large amount of drilling fluid to be treated, reuse of fltered water, too much equipment which occupied large area, tough requirements on drilling fluid for drilling long open section, hydration and swelling of the shallow shales, and instability of the deep borehole wall. A calcium chloride drilling fluid was chosen to drill these wells. The coarse drill cuttings, without treatment by additives, were separated out from liquid phase and solidifed. The fne drill cuttings, on the other hand, were fltered under pressure to remove the liquid phase. Since the additives were added in solution form instead of being added directly into the drilling fluid, time required for the separation of the fne cuttings and liquid phase was shortened from 60 min to 20 min, and the maximum treatment rate reached 9 m3/h. Furthermore, the pipeline between the cuttings agitator and the flter was modifed, adding a vertical hydraulic piston charging pump to enhance treatment effciency. An auxiliary water flushing pipeline was installed on cutting trough to avoid the piling of cuttings therein. Drilling practice has shown that in multi-well pad drilling, using drilling fluid zero-discharge technology and environmentally friendly drilling fluid formulation can satisfy the needs of tough environmental protection and reuse of drilling fluid. The rate of penetration can also be greatly improved, effectively reducing drilling cost.
A New Low Density Slag Cementing Slurry
LIU Lu, LI Ming, GUO Xiaoyang
2016, 33(6): 68-72. doi: 10.3969/j.issn.1001-5620.2016.06.012
Floating beads and hollow glass beads are commonly used lightweight additives in cement slurries. These lightweight additives are expensive, and generally large amount of them are needed in formulating cement slurries of required density. Cement slurries treated with floating beads and hollow glass beads have poor compatibility with drilling fluids. A clue borrowed from MTC technology can be used to solve these problems, that is, using slag as a gelling material to replace oil well cement in formulating cementing slurries. Activators and retarders as assorted agents in this new technology have been studied. An alkaline metal hydroxide JHQ and an alkaline metal salt of silicate JGY were preliminarily screened out as the activators through large amount of laboratory experiments, and the concentration of the activators were determined to be 3% and 2%, respectively. At these concentrations of activators, the set cementing slurry had compressive strength of 12.5 MPa. The retarder selected, HNJ, has hydroxycarboxylic acid groups on the α and β carbon atoms that have strong chelating capacity to calcium ions. The result of the chelating was the formation of highly stable pentacyclic or hexacyclic structures. HNJ was adsorbed on the surface of slag particles to retard the hydration process and prolong the thickening time. The thickening time was almost in a positive linear relationship with the concentration of HNJ. A bentonitic suspending agent, GYW-201, was selected to enhance the stability of the cementing slurry and to control flter loss. GYW-301, a high polymer suspending agent, was used in combination with GYW-201. The slag cementing slurry is suitable for use at 50-90℃, and has density adjustable between 1.30 g/cm3 and 1.50 g/cm3. Low cost, low flter loss, good sedimentation stability, good compatibility with drilling fluids, linearly adjustable thickening time, fast-developing low temperature strength were the advantages of the cementing slurry. Good cementing job quality has been obtained in the Jiangsu oilfeld. As a low cost technology, this new slag cementing slurry has the potential to replace low density cement slurry in cementing low pressure wells liable to lost circulation, wells with long cementing section, and under-balanced wells.
A Novel Thixotropic Well Cementing Slurry
LU Haichuan, LI Yang, SONG Yuanhong, WEI Jijun, ZHU Zhiyong, LU Yanli
2016, 33(6): 73-78. doi: 10.3969/j.issn.1001-5620.2016.06.013
Mature thixotropic cement slurries are seldom seen in China presently. Slurries commonly used in oilfelds are of weak thixotropy, temperature sensitive, and have poor overall properties. To solve these problems, a thixotropic agent, N-1, has recently been developed by combining a synthesized amphoteric polymer and an inorganic nano material. The amphoteric polymer has high widely distributed molecular weight (MW, about 6.0×106). At room temperatures, the high MW polymer molecules dissolve very slowly, and the dissolution becomes fast as temperature rises. This feature ensures the amphoteric polymer. The inorganic nano material selected is a fbrous material, which forms a network in water through adsorption and entanglement. N-1 was characterized for its microstructure, and was used as main additive to formulate a novel thixotropic cement slurry. Laboratory evaluation indicated that the cement slurry had strong thixotropy and did not lose without the action of pressure. At a pressure of 2.1 MPa, a cement slurry treated with 1.0%N-1 to 1.5%N-1 had volume of loss from 380 mL down to 0 mL. At elevated temperatures, the thixotropy of the N-1 treated cement was enhanced, instead of weakened, and had low flter loss (40 mL) and high strength (aged at 62℃ for 24 hours, the strength was 31.6 MPa.) Compared with conventional cement slurries, this cement slurry has strong thixotropy and good overall properties, and can satisfy the needs of well cementing.
Prediction of Safe Starting Pressure after Pump Halt for Thixotropic Cement Slurry Injection
YUAN Bin, YANG Yuanguang, YANG Shengrong, LIU Liming, CHEN Xiaoju
2016, 33(6): 79-83. doi: 10.3969/j.issn.1001-5620.2016.06.014
The use of thixotropic cement slurry is an effective means of anti-channeling and controlling lost circulation in feld operations. In pumping thixotropic cement slurry, if pump halts, the pressure of re-starting the pump will increase with time. Too big an initiation pressure may result in lost circulation to weak formations, or lead to the pumping that is unable to be re-started. To solve this problem, a model describing the characteristics of thixotropic cement slurry has been presented based on the analysis of several thixotropy models. A combination of this model and pressure drop equations gave birth to the model for predicting the safe re-starting pump pressure in injecting thixotropic cement slurry. The re-starting pressures for thixotropic cement slurry injected into wells with different well profles were calculated, indicating that the longer the halt of pump and the smaller the annular clearance, the higher the re-starting pressure required. After pump halted for 30 min and 60 min, the re-starting pressures were 13.94 MPa, and 21.12 MPa, respectively. The re-starting pressure when a φ139.7 mm casing was used was 4.66 MPa lower than when a φ177.8 mm casing was used, if the pump halted for 30 min. If the pump halted for 60 min, this re-starting pressure decrease was 7.51 MPa. The concentration of thixotropic agent also affected the additional pressure loss. When the concentration of the thixotropic agent was reduced form 5% to 2.5%, the 30 min re-starting pressure was reduced by 42.73%. From these data it is understood that thixotropic cement slurry should be used in wells with big annular clearance to minimize the risk experienced in restarting the pump.
Cementing Wells Penetrating Clastic Rocks with Self-healing Cement in Block Tazhong
TIAN Baozhen, LI Qingjie, QIN Yi, SUN Wanxing, SHEN Lei, CHEN Dacang, ZHANG Liang, ZHOU Jian
2016, 33(6): 84-90. doi: 10.3969/j.issn.1001-5620.2016.06.015
The clastic formations in the Block Tazhong have complex structures, poor lithological characters and toughness, and high brittleness. During drilling operation, wells penetrating the clastic formation have experienced borehole collapse and sloughing, and borehole of irregular sizes was formed. Cementing of the production casing string has long been facing with diffculties such as low formation pressure and mud losses in the Permian system, coexistence of oil and water in the same zone, interbedding of sandstone and shale, thin sandstones and hence multiple pay zones, short distance between a pay zone and a water zone, and inter-channeling of oil and water, etc. Based on the study on the mechanism of gas-channeling in cement slurry, a leading slurry with density of 1.35 g/cm3, and a tail slurry with density of 1.88 g/cm3 were formulated with several additives, such as silica powder, lightweight material BCE-610S, medium temperature retarder BXR-200L, drag reducer BCD-210L, self-healing agent BCY-200S and anti-channeling flter loss reducer BCG-200L. This cement slurry had good stability, mobility, zero free water, low fltration rate (flter loss<50 mL), elastic modulus near 7 GPa, high compressive strength, and ability of anti-channeling. By optimizing the composition of the cement slurry column in hole, pressure balancing during well cementing was realized. Using well cementing software, the displacing effciency was improved. As a set of self-healing cementing technology, it has been used in 4 wells in Tazhong, all cementing jobs successful, especially the main pay zones which were cemented with excellent job quality, effectively solved the diffculties in well cementing in clastic rock formations.
Anti-channeling High Density Cement Slurry Used in Cementing Well Hongbei-1
ZHONG Fuhai, FEI Zhongming, GAO Fei, SUN Wanxing, QIN Yi, ZHENG Yanli
2016, 33(6): 91-94. doi: 10.3969/j.issn.1001-5620.2016.06.016
The well Hongbei-1 is a well with the frst class well control risk drilled in the Qinghai oilfeld. It is also a well with the highest formation pressure drilled in that oilfeld. A high density (2.4 g/cm3) anti-channeling cement slurry was developed to cope with the cement slurry channeling. Hematite, a weighting material that needs less water in formulating drilling fluid, was selected to weight the cement slurry. To enhance the stability of the cement slurry, an ultra-fne amorphous particles, CEA-1, was used as extender. CEA-1 has the ability to adsorb large amount of free water and has a higher reactivity. An anti-channeling agent, FLOK-2, was developed by mixing a latex fber as the primary component, with CaCl2 and K2O as the secondary components. A high performance friction reducer, FS-13L, was developed by reaction between carboxylic acid as the primary raw material, and sodium sulfte as the secondary raw material. Laboratory experiment has shown that the SPN of the cement slurry was<3. When temperature changed by±5℃, the thickening time of the cement slurry changed by less than 44 min. When the density of the cement slurry changed by±0.05 g/cm3, the flow index of the cement slurry varied between 0.71 and 0.59, and the consistency factor varied between 1.06 mPa·sn and 3.14 mPa·sn. A flushing spacer compatible with the drilling fluid used was also developed. The composition of the spacer is:water+320% hematite powder+35%OCW-1L (flushing agent)+10%CEA-1+4%spacer agent. Field application has shown that this cement slurry had good stability and anti-channeling performance. When used in combination with assorted technical measures, the quality of the cementing job can be enhanced, and operation safety ensured.
Study on the Rheology and Drag Reducing Performance of Epoxy Chloropropane Modifed Cellulose Solution
ZHU Yimei, FANG Bo, LU Yongjun, QIU Xiaohui
2016, 33(6): 95-100. doi: 10.3969/j.issn.1001-5620.2016.06.017
To improve the viscoelasticity of carboxymethyl hydroxyethyl cellulose (CMHEC) solution to widen its feld of application, a water soluble EPIC-CMHEC has been developed by reacting epoxychloropropane (EPIC) with CMHEC. EPIC-CMHEC and CMHEC water solutions were studied for their rheology (flow curve, viscoelasticity, constitutive equation, and thixotropy etc.) and drag reducing performance. The study has shown that compared with that of the CMHEC solution, the viscosity of the EPIC-CMHEC solution was notably increased. Water solution of 3 g/L EPIC-CMHEC had viscosity of 56.6 mPaf s, 2.1 times of the viscosity of a 3 g/L CMHEC solution (18.3 mPaf s), and the elasticity of the EPIC-CMHEC solution was better than that of the CMHEC solution. Sheared at 170 s-1, when temperature was increased from 20℃ to 80℃, the viscosity of 0.3% EPIC-CMHEC solution was 19 mPaf s, still higher than the viscosity of a 0.3% CMHEC solution at 25℃. EPIC-CMHEC solution had better drag reducing performance. The maximum percentages of drag reduction of 0.10% EPIC-CMHEC solution and CMHEC solution were 72.70% and 68.41%, respectively. The flow curves of the EPIC-CMHEC solution and the CMHEC solution can be expressed with cross constitutive equation. EPIC-CMHEC is expected to fnd its use in oil/gas development and where drag reducing is required.
The Development and Application of a Recyclable Clear Fracturing Fluid
WANG Gaihong, LIAO Lejun, GUO Yanping
2016, 33(6): 101-105. doi: 10.3969/j.issn.1001-5620.2016.06.018
Stimulated reservoir volume fracturing operation in Changqing oilfeld requires large amount of fracturing fluids. To save water, fracturing fluids are required to be recycled. However, the recycled hydroxypropyl fracturing fluid presently commonly used in Changqingdoes not have the ability to carry sands, and the technique for recycling low molecular weight guar gum fracturing fluid is not feasible for feld use. A recyclable clear fracturing fluid was developed recently in an effort to solve these problems. This fracturing fluid was formulated with 3% XYCQ-1 (a thickening agent), 0.05% XYPJ-2 (gel breaker), and 0.01%-0.1% XYTJ-1 (a water quality conditioner). XYCQ-1 is a polysaccharide thickening agent made by microbial cultivation and fermentation, and has the ability to render fracturing fluid stable viscosity in only 10 sec. XYPJ-2 is a mixture of a natural enzyme and a molecularly modifed enzyme, composed of the same polysaccharide as that in XYCQ-1. Site-specifc mutagenesis was used on the molecular structure of the thickening agent to promote specifc reaction to the enzymes to form non-natural new disulfde bond, thereby ensuring the gel resuming and recycling of gel-broken fracturing fluid. XYTJ-1, by reaction with Ca2+ and Mg2+in the recycled fracturing fluid to form watersoluble complexes or chelates, eliminates the negative effects of high valence metal ions on gel formation. Laboratory experiments indicated that the properties of the fracturing fluid remained stable at 80℃, and had good sand carrying capacity, frictionreduction and cleanup capacity. Almost no sedimentation was found of the fracturing fluid kept quiescence at room temperature for 24 hours, or stayed in 80℃ water bath for 15 minutes. At injection rate of 64 L/min, the percentage of friction reduction was 67%, and percentage of core damage only 6.70%. In the stimulated reservoir volume fracturing operation in 21 horizontal wells in the Changqing oilfeld, 10.46×104 m3 fracturing fluid was consumed, and the recycled fracturing fluid, after simple treatment (liquid-sand separation by settling), was reused for making fracturing fluid. The fracturing fluid has been recycled for 10 times, and the clear fracturing fluid made from the recycled fracturing fluid has good sand carrying capacity, indicating that the recyclable clear fracturing fluid has satisfed the needs of multi-stage fracturing operation.
A High Temperature Shear-resistant Association Supramolecular Polymer Weak Gel Fracturing Fluid
JIANG Qihui, JIANG Guancheng, LU Yongjun, LIU Ping, QIU Xiaohui
2016, 33(6): 106-110. doi: 10.3969/j.issn.1001-5620.2016.06.019
Supramolecular polymer chemistry is a new interdiscipline of supramolecular chemistry and polymer chemistry. Based on the research work previously done on supramolecular fracturing fluid, a high temperature shear-resistant supramolecular polymer viscosifer, SPM-2, has been synthesized with a zwitterionic surfactant ASF-1 (having good solubilization to hydrophobic monomers), a synthesized long-chain unsaturated cationic monomer, LCM, and another synthesized high temperature monomer HTM, through micelle copolymerization. By compounding the synthesized SPM-2 and PCA-1 (a physical crosslinking agent with worm-like micelle), an association supramolecular polymer fracturing fluid (0.8% SPM-2+0.5% PCA-1) with weak gel has been developed. This fracturing fluid has supramolecular "honeycomb" grid structure, and apparent viscosity that increase with increase in the concentration of PCA-1. It has been proved that ASF-1 and LCM formed strong physical crosslinking. Sheared at 150℃ and 170 s-1 for 2 h, the apparent viscosity of the fracturing fluid was maintained at about 58 mPa.s, higher than the apparent viscosity of the SPM-2 solution itself by 30 mPa.s. Increased the shear rate frst from 40 s-1 to 170 s-1, and then reduced the shear rate to 40 s-1 again, the viscosity of the fracturing fluid was reduced and resumed sharply, showing good resistance to shearing. Scanned at frequency of 0.01-10 Hz, the elasticity of the fracturing fluid was better than its viscosity. The settling rate of proppant in the fracturing fluid was less than 8×10-3 mm/s. Compared with the supramolecular polymer SPM-2, this fracturing fluid has suspending capacitythat is an order of magnitude higher. The fracturing fluid, after gel-breaking at 90℃ for 2 h, had viscosity less than 2 mPa·s, and no residue had been found therein. Core experiment indicated that core damage by the fracturing fluid was lower than 10%. Laboratoryexperiments showed that this fracturing fluid can satisfy the needs for fracturing high temperature tight sand gas reservoirs.
Preparation and Evaluation of a New High Performance Diverting Acid
WANG Yanli
2016, 33(6): 111-115. doi: 10.3969/j.issn.1001-5620.2016.06.020
Carbonate rock reservoirs have plenty of micro fractures. Unidirectional fngering of acid solution in acidizing carbonate reservoirs always results in diffculties in communicating fractures and low effciency of acidizing fracturing job. To improve the job effciency, a new high performance diverting acid, which is sensitive to CO2, has been developed. The diverting acid has a formulation as follows:3.96%SDS+1.09% MPDA+24% HCl+0.5% Z-1 (a corrosion inhibitor). This acid, although not viscoelastic, can acquire viscoelasticity through the reaction of TMPDA with SDS at the presence of CO2, because the reaction of TMPDA with SDS produces a surfactant Gemini which had superior viscoelasticity. The diverting acid resumed its original state as soon as CO2 disappeared. Laboratory study has shown that this diverting acid had good high temperature stability, good shearing performance, and superior diverting ability. In core experiment, several groups of cores were displaced with the new diverting acid. It was found that the permeability of the acid-flooded cores increased remarkably, even after removing the biggest permeability increases of two groups of cores. The effciency of acidizing fracturing job can be improved with the new diverting acid, and recycling of the diverting acid may also be realized.
Key FactorsAffecting Damage by Fracturing Fluidsto Jiannan Tight Sandstone Gas Reservoir
FU Meilong, HU Zewen, HUANG Qian, TANG Fang
2016, 33(6): 116-120. doi: 10.3969/j.issn.1001-5620.2016.06.021
Carboxymethyl hydroxypropyl guar gum fracturing fluid, an oligomer fracturing fluid and hydroxypropyl guar gum fracturing fluid are used in fracturing the tight sandstone gas reservoirs in Jian'nan block. In recent laboratory experiments, the viscosity, surface tension and residue of the three fracturing fluids after gel-breaking were measured. It was found that there were some differences in the properties of these three fracturing fluids after gel breaking. The measurement of core damage has shown that the ratio of cores' water block damage (65%-80%) was far greater than the ratio of cores' matrix damage (5%-15%), indicating that water block damage was the main damage to reservoir permeability. The ratio of matrix damage and the ratio of water block damage are not only related to the properties of fracturing fluid, they are also related to core permeability and lithology. Through decomposition experiment, it was understood that the amount of residue of fracturing fluid was the key factor affecting matrix damage, and the core permeability was the key factor affecting water block damage. Experiment on water block removal has shown that cores with severe water block damage can have permeability increases by more than 70% after removing waterblock, indicating that the measures of removing water block did work.
Effect of Retained Fracturing Fluid on the Imbibition Oil Displacement Effciency of Tight Oil Reservoir
GUO Gang, XUE Xiaojia, LI Kai, FAN Huabo, LIU Jin, WU Jiang
2016, 33(6): 121-126. doi: 10.3969/j.issn.1001-5620.2016.06.022
The flowback of fracturing fluid directly affects the production rate of a reservoir in the later stage of production. In laboratory studies, the basic physical properties of reservoir core and fracturing fluid were measured. Based on the measurement, factors affecting automatic imbibition and key factors affecting oil/water replacement by fracturing fluid were studied through experiment. The optimum imbibition recovery rate and the maximum imbibition rate for feld use were determined in laboratory studies. Differences between imbibition and displacement are explained by nuclear magnetic experiment. The experimental results have shown that influencing factors affected imbibition rate in an order of:interfacial tension > permeability > viscosity of crude oil > salinity. The imbibition recovery rate increased with increase in permeability, while the amplitude of increase was gradually reducing.When the viscosity of the simulated oil was in a range of 1.204-4.864 mPa·s, the imbibition recovery rate increased with decrease in the viscosity of the simulated oil. When the salinity of the imbibition fluid was in a range of 1 000-80 000 mg/L, the imbibition recovery rate increased with increase in salinity, When the concentration of cleanup additive in imbibition fluid was in a range of 0.005%-5%, i.e., the interfacial tension was in a range of 0.316-10.815 mN/m, the use of the imbibition fluid containing 0.5% cleanup additive (interfacial tension 0.869 mN/m) got the maximum imbibition recovery rate. Static imbibition experimental resultshave shown that higher interfacial tension did not necessarily result in higher recovery rate; instead, there was an optimum interfacial tension at which the amount of bypassed oil was minimized, and the imbibition recovery rate was maximized. This fnding provides a guide to enhance recovery rate from tight reservoirs.