2016 Vol. 33, No. 1

Display Method:
2016, 33(1)
Development and Evaluation of a New High Temperature Filter Loss Reducer Used in Oil Base Drilling Fluid
WANG Maogong, CHEN Shuai, LI Yanqin, SUN Jinsheng, XU Xianguang
2016, 33(1): 1-5. doi: 10.3969/j.issn.1001-5620.2016.01.001
An oil base mud filter loss reducer, DR-FLCA(functions at 220℃), was developed through imidization of humic acid by diethylenetriamine followed by hydrophobic modification by octadecyl tri-methyl ammonium chloride. The molecular structure, micromorphology and thermo-stability of DR-FLCA was characterized using IR spectroscopy, SEM and thermogravimetric analysis, and laboratory experiments were conducted to evaluate the effects of DR-FLCA on the rheology, electrical stability and HTHP filtration of high temperature high density oil base drilling fluid. DR-FLCA retains emulsifying capacity because of the imide group, phenolic hydroxyl group and alcoholic hydroxyl group on the molecular chains of DR-FLCA, and the long chain organic ammonium on the molecule chain. The micromorphology of this filter loss reducer is an aggregate of loose thin layers. DR-FLCA decomposes at 248℃. A 2.4 g/cm3 oil base drilling fluid treated with DR-FLCA, after aging at 220℃ for 16 hours, have the following properties:filter loss 8.6 mL, electrical stability 1,154 V, plastic viscosity 69 mPa·s, and yield point 7 Pa, demonstrating better filtration, (secondary) emulsifying, thinning and HTHP (200℃) filtration performances than Baker Hughes' and Halliburton's corresponding products(HTHP filtration are 5.4,8.2 and 6.5 mL), the electrical stability of which also decreases after aging, but the quality of mud cake is slightly poorer than Baker Hughes' and Halliburton's corresponding products.
Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
QIN Yong, JIANG Guancheng, DENG Zhengqiang, GE Lian
2016, 33(1): 6-10. doi: 10.3969/j.issn.1001-5620.2016.01.002
A primary emulsifier, HT-MUL, for high temperature oil base drilling fluid was developed using tall oil fatty acids and maleic anhydride, and the optimum acid value of tall oil fatty acids and optimum concentration of maleic anhydride for the reaction were determined. Evaluation of HT-MUL shows that HT-MUL performs very well as an emulsifier. Using HT-MUL, a water-in-oil emulsion (O/W ratio=60:40) was formulated, having electrical stability of 490 V, and another water-in-oil emulsion (O/W ratio=90:10), having electrical stability of 1,000 V. Comparison of HT-MUL with other primary emulsifiers demonstrates that emulsions formulated with HT-MUL have higher electrical stability voltage, lower filter loss and higher rate of emulsion, proving that HT-MUL has better general performance than other emulsifiers. A high performance high density oil base drilling fluid was formulated using HT-MUL, retaining electrical stability of 800 V and filter loss less than 5 mL after hot rolling at 220℃. Oil base drilling fluids formulated with HT-MUL have good high temperature performance and emulsion stability.
Control and Prevent Oil Base Mud Loss with Expandable Plugging Agents
LIU Wei, LIU Na, ZHANG Xiaoping
2016, 33(1): 11-16. doi: 10.3969/j.issn.1001-5620.2016.01.003
An oil base mud loss prevention fluid (LCM mud) was formulated through optimization of additives and expandable plugging agents. Compatibility, plugging capacity and pressure containment of the LCM mud were evaluated through laboratory experiments. The LCM mud showed good rheology and high electrical stability in laboratory experiments. In experiments with the LCM mud on 1-5 mm simulated fractures, the pressure containment of the LCM mud was 7.0 MPa. Depths of invasion of the LCM mud into API sand beds were reduced by 95% or higher. In a horizontal shale gas well operation, more than 60% of the mud losses were controlled at the first try. Volumes of high density (2.10-2.45 g/cm3) oil base mud lost were controlled within 10 m3, demonstrating that this LCM mud satisfied the needs for mud loss control in field operations.
High Performance Water Base Drilling Fluid for Shale Gas Drilling
LONG Daqing, FAN Xiangsheng, WANG Kun, FAN Jianguo, LUO Renwen
2016, 33(1): 17-21. doi: 10.3969/j.issn.1001-5620.2016.01.004
A high performance water base drilling fluid is in urgent need to replace the oil base muds currently used in shale gas drilling in both the directional section and the horizontal section. This paper discusses the field application and laboratory study of two high performance water base drilling fluids. One of the high performance drilling fluids, GOF, has been used in the horizontal section of the well Changning H9-4, the directional and horizontal sections of the well Changning H9-3, and the well Changning H9-5. Another high performance drilling fluid is a highly inhibitive water base fluid of high lubricity, and has been used in the horizontal well YS108H4 in the block Zhaotong. This fluid utilizes organic and inorganic salts as the shale inhibitors and lubricant and diesel oil to render the fluid lubricity. In filed application, the ROP of the directional section was increased by 50%-75%, and that of horizontal section increased by 75%-100%. Advantages and disadvantages of the two fluids are discussed in the paper, based on laboratory experimental data and field application information. Ideas to improve the performance of the fluids are presented for the preparation of better high performance water base drilling fluids.
Synthesis and Application of a New High Temperature High Performance Salt Resistant Shale Inhibitor
HOU Jie, LIU Yonggui, SONG Guangshun, SONG Tao, YAN Jing, ZHAO Xiaozhu
2016, 33(1): 22-27. doi: 10.3969/j.issn.1001-5620.2016.01.005
Quaternary ammonium salts and cationic inhibitive agents presently used are not strong enough in shale inhibition, Polyamine (such as JY-1), although strong enough, has deficiencies in molecular stability and high temperature tolerance. To improve the molecular stability and high temperature tolerance of polyamine inhibitive agents, a high temperature salt resistant low molecular weight polyamine, JY-2, was synthesized, based on the profiling and re-design of molecular structure of JY-1. The optimum synthesis condition of JY-2 is as follows:reaction temperature 220-240℃, reaction time 4-5 h, catalyst concentration 0.10%, molar ratio of monomer B and a polyhydric alcohol 1:1.8, reducing agent concentration 1.0%. IR spectroscopy showed that the actual molecular structure of JY-2 is conforming to the designed molecular structure, containing secondary amine and tertiary amine groups. JY-2 has moderate molecular weight (508 g/mol), is nontoxic and contains no weak ether bonds. Laboratory analyses recommended that the molecular formula of JY-2 should be C23H66N7O4.JY-2 has inhibitive capacity similar to that of polyamines produced abroad, and is much more inhibitive than those presently used in China. JY-2 has good long-time inhibitive performance, and good compatibility with other additives used in fresh water base and saltwater base drilling fluids. Optimum treatment of JY-2 is 0.5%-1.0%. Water base drilling fluid using JY-2 as the main additive has been used the well Gu693-104-Ping104 in Daqing, solving the extremely water sensitive shale and clay stones of the Nenjiang Formation and Yaojia Formation. Percent of hole enlargement (hole section drilled with the JY-2 mud) was only 7.1%, and ROP was 7.11 m/h. Study and field application show that JY-2 has outstanding inhibitive capacity, good molecular stability and is tolerant to high temperatures to 180℃, and can be used in drilling highly water sensitive shale formations.
Development and Evaluation of a High Density Drilling Fluid Lubricant
WANG Lin, DONG Xiaoqiang, YANG Xiaohua, XUE Yuzhi, LI Tao
2016, 33(1): 28-32. doi: 10.3969/j.issn.1001-5620.2016.01.006
A high density drilling fluid lubricant, SMJH-1, was developed using polyalcohol, long-chain fatty acids with double bonds in their molecules, and natural minerals. SMJH-1 is a high molecular weight ester with ability to reduce extreme pressure friction. Drilling fluids treated with 1%, 2% and 3% SMJH-1 have coefficient of friction reduced by 24.2%, 33.6% and 38.3%, respectively. SMJH-1 functions at 180℃ and in drilling fluids contaminated with 30% salt. SMJH-1 reduces the HTHP filter loss of drilling fluids with density between 1.4 g/cm3 and 2.0 g/cm3, while only slightly affects their rheology. SMJH-1 can spread on the surface of steel, forming a solid film by physico-chemical adsorption and lateral adhesion, hence enhancing the hydrophobicity of the surface and controlling the vortices in the flowing fluid. In this way the friction between fluid and solid surface is reduced. SMJH-1 has been tried in the drilling of the Well Yuanlu-601H and Yuanlu-301, and proved successful.
Preparation and Characteristics of Nano Polymer Microspheres Used as Plugging Agent in Drilling Fluid
WANG Weiji, QIU Zhengsong, HUANG Wei'an, ZHONG Hanyi, BAO Dan
2016, 33(1): 33-36. doi: 10.3969/j.issn.1001-5620.2016.01.007
Conventional plugging agents can hardly form mud cakes on the surface of shales because of the very low permeability and very small size of pore throat in shales. Nano particles, on the other hand, are easy to block the pore throats in shales, hence to hinder the invasion of liquid phase of drilling fluid, to maintain the stability of borehole wall, and to protect reservoir formations. A nano polymer microsphere plugging agent, SD-Seal, was developed through emulsion polymerization, using styrene and methylmethacrylate as reactive monomers and KPS as initiator. Laboratory studies show that SD-Seal particles have good dispersity and regular shapes (mostly spherical). The particle size of SD-Seal is about 20 mm, and the decomposition temperature is 402.5℃. Test of SD-Seal on rock sample taken from the Maxi Formation reducesthe permeability of the rock by 95%.
Laboratory Evaluation of a New Temporary Plugging Agent ZDJ
GUO Limei, XUE Jinhua, CHEN Xi
2016, 33(1): 37-41,47. doi: 10.3969/j.issn.1001-5620.2016.01.008
A new temporary plugging agent, ZDJ, was produced to overcome the deficiencies of conventional reservoir protection technology and elastic sealing agents. ZDJ has a core-shell structure, and good deformability enabling it to be adhered on to the interior surface of pore throats, thus protecting reservoir from being damaged. This technology does not necessitate the accurate compatibility of additive's particle sizes with diameters of pore throats. ZDJ is produced with AM, AMPS, DMC, N, N'-Methylene bis-acrylamide and an inorganic agent A, using radical polymerization.The black part at the center is a rigid core, and the transparent part at the brim is an elastic mass. The evaluation indicates that ZDJ shows the optimum plugging performance at 50% (mass fraction) of A. Sand beds plugged with 0.5% ZDJ have fluid invasion depths of 2.3-5.9 cm, and API filter loss of 8.5 mL. When ZDJ, sulfonated asphaltene and LV-CMC are compounded at a ratio of 4.5:1.5:1.0, the best plugging and filtration control performances can be achieved. Sand beds plugged with 1.0% of the compound have fluid invasion depths of 0.6-2.7 cm, and filter loss of 6.1 mL. In tests on artificial sand cores having permeabilities of 200×10-3-300×10-3 μm2,99.2% of pores are plugged with the compound, and permeability recovery reaches 99.3%, indicating that ZDJ, sulfonate asphaltene and LV-CMC have good synergistic effect in hindering the invasion of mud filtrates and solids, thus realizing the protection of oil and gas reservoirs.
Low Temperature Rheology of Clay-free Seawater Base Drilling Fluids
QIU Zhengsong, LI Zhaochuan, HUANG Wei'an, MAO Hui, ZHONG Hanyi, QIU Yongping
2016, 33(1): 42-47. doi: 10.3969/j.issn.1001-5620.2016.01.009
A clay-free seawater base drilling fluid of excellent low temperature rheology was prepared for use in offshore drilling where low temperature viscosification of drilling fluids was frequently encountered. Additives used in the drilling fluid have been optimized on self-made deep water drilling fluid simulation device. This fluid has good low temperature rheology after aging at 130℃. Before and after aging, the ratios of apparent viscosity at 4℃ and 25℃ are 1.179 and 1.250, respectively, the ratios of plastic viscosity at 4℃ and 25℃ are 1.167 and 1.240, respectively, and the ratios of yield point at 4℃ and 25℃ are 1.200 and 1.265, respectively. This fluid has stable gel strengths. The PV/YP ratio is in a range of 0.625-0.694 Pa/(mPa·s), the API filter loss is about 9.0 mL, the coefficient of friction is 0.181, percent shale swelling is 10.0%, and percent shale cuttings recovery in hot rolling test is 87.0%. This fluid also helps protect reservoirs and prevent the generation of gas hydrate.
Study on Coalbed Methane Reservoir Sensitivity in Ningwu Basin and Drill-in Fluid Technology
FAN Fan, ZHENG Yuhui, LYU Haiyan
2016, 33(1): 48-51. doi: 10.3969/j.issn.1001-5620.2016.01.010
Stress sensitivity, alkali sensitivity and water sensitivity conducted on rock samples taken from coalbed methane reservoir of the Ningwu Basin demonstrate that strong stress sensitivity, moderate alkali sensitivity and moderate-strong water sensitivity exist in the reservoir formations. It is suggested that the drilling fluid used in reservoir drilling in the Basin should have controlled mud weight and pH value, high temporary plugging capacity and inhibitive capacity, which help minimize damage to the permeability of reservoir rocks. A set of filming drill-in fluid, CQ-FDC, suitable for drilling the coalbed methane is as follows:(0.2%-0.3%)G304(organosilicon)+(2%-5%)FHY-2(compound salts)+(0.3%-0.5%) G310(viscosifier)+(1%-3%)G301(filter loss reducer)+(1%-2%) G325(temporary plugging agent)+ NaOH. This drill-in fluid showed in laboratory experiment percent reduction in linear swelling of cores by 71.56% after 12 h of test. Permeability recovery experiment showed that damage of the drill-in fluid to the permeability of coal samples 4# and 9# was less than 15%. CQ-FDC has been successfully applied in 6 coalbed methane wells in Ningwu Basin, average hole enlargement of these wells being 15.77%, and average rate of permeability impairment of the reservoir rocks was 16.73%. Average ROP of the six wells was increased in comparison with offset wells.
Effect of Sealing and Plugging Capacity of Drilling Fluid on Borehole Stability of Weisan Member in Block Xuwen
XU Chuntian, MA Chengyun, XU Tongtai, TANG Y, an
2016, 33(1): 52-56,62. doi: 10.3969/j.issn.1001-5620.2016.01.011
Borehole instability of the Weizhou Member has been encountered during drilling in Block Xuwen, although the mud weight used exceeded the equivalent density calculated from the collapse pressure of the formation, as known from logging data and analyses of 3 pressure profiles. It was found that fractures and fissures were developed in the Weisan Member. In laboratory experiments, cores taken from the formation of interest were immersed in drilling fluid, and changes in collapse pressure were calculated using a simplified equation of calculating mud weight from collapse pressure. It was found that the rock strength decreased with immersion time, resulting in a large increase in collapse pressure of formation; in the experiments, the collapse pressure increased by 12.15% after 5 d of immersion in drilling fluid. Analyses of borehole instability in the Weisan Member indicated that lack of sealing and plugging of formation by drilling fluid resulted in filtrate invasion, which in turn reduced the strengths of formation and increased the pressure of formations near the wellbore. The collapse pressure of formation was thus increased, resulting in borehole instability. Based on these understandings, the formulation of drilling fluid was modified by adding organic salts, encapsulators and amine additives into the drilling fluid, and using ZHFD, QS-4 and NFA-25 as plugging agents. With this optimized drilling fluid, the time required for the borehole to collapse was prolonged, and borehole instability of the Weisan Member was prevented.
Optimization of Drilling Fluid Rheology Pattern Using Improved Golden Section Method
LI Qi, WANG Zaixing, SHEN Liyang, WANG Yaojia, LI Xuyang
2016, 33(1): 57-62. doi: 10.3969/j.issn.1001-5620.2016.01.012
Rheological parameters of drilling fluid and selection of rheology pattern play an important role in drilling operation. Using exhaust algorithm and other methods, such as numerical computation method, regression analysis and optimization theory, three evaluation indices, i.e., correlation index, sum of squares of residues and variance of residues are introduced. Using golden section method, the contraction of the root interval can be accelerated. These studies give birth to the so called improved golden section method. In this improved golden section method, initial iterative values become unnecessary, and the method has good convergence, getting rid of deficiencies of the rheological model presently in use. This method is suitable for the parameter calculation and optimization of rheological patterns using 2-parameter, 3-parameter and 4-parameter equations. Using computer language MATLAB, large scale computation can be realized. Comparison of the computation results and those of others shows that the three evaluation indices presented are useful, and when used in combination with the improved golden section method, rheological parameters can be calculated, and rheological model optimized with good accuracy. The computational result of the variance of residue is reduced by 19.7%, a higher computational accuracy.
Anti-channeling High Density Cement Slurry Technology for Horizontal Shale Gas Well in Weiyuan
ZHANG Shunping, ZHANG Sen, QIN Yi, DING Zhiwei, JIN Jianzhou, XU Ming, YU Yongjin
2016, 33(1): 63-67. doi: 10.3969/j.issn.1001-5620.2016.01.013
High formation pressures, long cementing hole sections, big temperature differences between surface and bottom hole, and high energy perforation and multi-stage fracturing in later period prevail in well cementing jobs in Weiyuan area where shale gas wells have been drilled. A high density anti-channeling cement slurry is developed to solve these problems. The cement slurry is formulated with filter loss reducer DRF-2120L, high temperature retarder DRH-200L, high temperature stabilizer DRK-3S, latex anti-channeling agent DRT-100L and purified iron powder, with the density ranging in 2.20-2.40 g/cm3. This cement slurry has good stability (density difference between the top and the bottom is zero), good mobility, no free water, low filter loss (<50 mL), low elastic modulus (<7 MPa), moderate compressive strength and strong anti-channeling capacity. (transit time <10 min, SPN=1.47-1.80), satisfying the needs for shale gas well cementing in south Sichuan. This cement slurry has been applied on 13 wells in Weiyuan till the end of March, 2015. Till the end of June, 2015, 4 wells of the 6 electric-logged wells have been successfully cemented, and the other two cemented up to scratch.
Solidification of Slag Mud Cake that Improves Cementation Quality of the Second Bonding Interface
MEI Yukun, LI Ming, LIU Lu, ZHANG Guanhua, GUO Xiaoyang
2016, 33(1): 68-72. doi: 10.3969/j.issn.1001-5620.2016.01.014
Poor solidification of filter cake results in poor cementation quality of the second bonding interface (between filter cake and cement sheath). Technology for the solidification of slag mud cake is presented to try to improve the cementation quality of the second bonding interface. This technology is based on the characteristics of slag, which can be activated by alkali. Several studies have been conducted, including:effects of slag mud cake on the cementation performance of the second bonding interface; flushing fluid for this technology; and phase composition and functioning mechanism of filter cake inspected using XRD. The studies show that the slag mud cake solidification technology helps improve the cementation quality and the cementation morphology of the second bonding interface. The flushing fluid further improves the cementation quality. Slag mud cake, having the potential of being solidified, after penetration and pre-activation by the flushing fluid, exchanges matters with cement slurry. Both the slag mud cake and the cement during this course hydrate simultaneously, producing C-S-H gels which encapsulate and link solid particles and fill the spaces among cement particles, making the filter cake and cement sheath solidify as a whole. It has been proved that this technology, when used in combination with the designed flushing fluid, is beneficial to the improvement of the cementation quality of the second bonding interface. These studies are of importance to the use of inorganic gel materials in drilling fluids, especially the recycling of industrial wastes.
High Temperature Corrosion Resistant Cement Slurry Used in Fire Soaked Well Cementing
LI Lianjiang
2016, 33(1): 73-78. doi: 10.3969/j.issn.1001-5620.2016.01.015
Fire soaking production is an advantageous thermal production technology fast developed in recent years. This technology requires cement slurry to have the thermal stability above 550℃ and resistance to CO2 corrosion, such as GWC-500S, a phosphoaluminate cement which was developed by adding phosphate, alumina powder, corrosion resistant agent and activator into an aluminate cement. A liquid filter loss reducer GWF-500L and an inorganic acid retarder GWR-500S have also been developed for use in the cement. A cement slurry was developed with these materials and the set cement was tested using XRD at 50℃, 300℃ and 600℃. Hydrates of the cement and their changes with temperature were analyzed. Set cement calcinated at 600℃ was analyzed using SEM for its profile. Changes in the strength of the phospho-aluminate cement after calcination at 550℃ for 7 d were evaluated. Resistance to CO2 corrosion of set cement at 120℃ and a CO2 partial pressure of 6.9 MPa was evaluated. It is understood through these studies and evaluations that the phospho-aluminate cement slurry has thickening time adjustable between 40℃ and 100℃, API filter loss of less than 50 mL, and good rheology. The set cement has the advantages such as:resistance to high temperature to 550℃, resistance to CO2 corrosion, adjustable density, moderate thickness, good stability, and good compatibility with drilling fluids and spacers. The cement slurry has been successfully tried on well Yingshi X in a fire soak test block in XX oilfield. Laboratory experiments and field application prove that the phospho-aluminate cement slurry satisfies the needs for fire soak well cementing.
Study on Low Temperature Cementing Slurry
BU Yvhuan, HOU Xianhai, GUO Shenglai
2016, 33(1): 79-83. doi: 10.3969/j.issn.1001-5620.2016.01.016
A chlorine-free early-strength agent AA was developed by compounding colloidal SiO2, sulfate and alcohol amine. The development of AA is aimed at solving the troubles existed in cementing low temperature coalbed methane wells and cementing the surface hole section of deep water offshore wells. Effects of AA on the performance of oil well cement were studied. Using XRD and SEM, the hydrate of cement and the functioning mechanism of AA were analyzed. A 1.35-1.87 g/cm3 cement slurry suitable for low temperature well cementing was prepared using light weight material and other additives. Laboratory study shows that AA simultaneouslyaccelerates the hydration of cement clinkers C3S and C2S, and consumes the Ca(OH)2 produced. Pozzlanic reaction between SiO2 and Ca(OH)2 give birth to a C-S-H gel, which fills the pores and spaces formed by cement particles. Early strength of set cement is thus remarkably enhanced. This low temperature cement slurry has 24 h compressive strength of 13 MPa at 30℃, thickening time of 196-258 min, filter loss of 24 mL, free liquid of 0, and mobility greater than 20 cm. Other advantages of this cement slurry include short transient time and gas channeling prevention.
Study on Low Temperature Accelerator for Cement Slurry
SUN Xiaojie, YU Gang, ZHENG Huikai, ZHU Haijin, TANG Shaobing, MA Yongle
2016, 33(1): 84-87. doi: 10.3969/j.issn.1001-5620.2016.01.017
A study on the acceleration performance of different accelerators was conducted to try to find an effective low temperature accelerator for the AMPS cement slurry. A high performance accelerator BCA-210S that can be used in AMPS cement slurry was selected using orthogonal experiment method. BCA-210S has the ability to promote the hydration of AMPS cement and to shorten the time for cement slurry to thicken at low temperatures. Using BCA-210S, time required for cement slurry to thicken at low temperatures can be controlled to about 60 min, transit time required for the gel strength of cement slurry reduced to 10 min, and compressive strength of set cement under 30℃ increased to 5.3 MPa after 8 h. It is concluded that BCA-210S increases the early compressive strength of set cement, which in turn exhibits excellent low temperature early strength and anti-channeling performances. As a new multi-function accelerator, BCA-210S is beneficial to solving problems encountered in cementing low temperature wells and adjustment wells.
Study and Application of Solids-free Flushing Spacer
LIU Wenming, XIAO Yao, QI Ben, FU Jiawen, SUN Qinliang, LI Jianhua
2016, 33(1): 88-91. doi: 10.3969/j.issn.1001-5620.2016.01.018
A solids-free flushing spacer was developed for use in drilling operation to prevent open holes and high permeability sandstones from being damaged by the solids in spacers. In laboratory experiments, the density of the spacer can be adjusted between 1.00 g/cm3 and 1.80 g/cm3. No density difference was found of the top and the bottom of the spacer after aging at 180℃, indicating that no sedimentation ever occurred. The spacer was a Newtonian fluid, having plastic viscosity of 6 mPa·s and yield value of 0, meaning that turbulent flow displacement can be easily realized. When contaminated with a mixture of organic salt drilling fluid and salt-resistant cement slurry, the flow index of the spacer increased, while the consistency factor decreased, meaning that the spacer was compatible with organic salt drilling fluid and salt-resistant cement slurry. When mixed with saltwater at different ratios, thickening time of the mixture was prolonged, which is beneficial to safe operations. 90% or more pseudo mud cakes and oil dirt on the borehole wall can be flushed away, which is beneficial to the development of bonding strength between cement sheath and borehole wall. This solids-free spacer has been used 29 times in Iraq, successfully solving problems encountered in cementing high temperature wells, and wells with salt and gypsum formations.
Rheology and Drag Reduction of Hydrophobic Amphoteric Quadripolymer Solution
PENG Fei, FANG Bo, LU Yongjun, QIU Xiaohui, HUANG Caihe, LIU Yuting
2016, 33(1): 92-96. doi: 10.3969/j.issn.1001-5620.2016.01.019
A hydrophobic amphoteric quadripolymer PAADC was synthesized for use as a drag reducer in slippery water fracturing fluids. PAADC, made from monomers AM, AMPS, DMAM and CDAAC, was studied in laboratory on its rheology and drag reduction capacity, and the rheology of PAADC solution at different concentrations is measured. Change of the friction coefficient and rate of drag reduction of the PAADC solutions with generalized Reynolds number is discussed in this paper. Comparison between the rheology and drag reduction capacity of PAADC and those of another water-soluble terpolymer PAAD (synthesized from AM, AMPS and DMAM) was conducted. PAADC solution has, as the studies indicated, very good shear thinning capacity, and the thixotropy of PAADC is better than that of PAAD at the same concentration. The maximum rates of drag reduction of PAADC solution of different concentrations (0.1%, 0.2%, 0.3%, and 0.4%) are 32.29%, 63.32%, 69.52% and 67.35%, respectively, indicating that PAADC concentration remarkably affects the drag reduction capacity of thesolutions, and 0.3% PAADC solution is preferred in drag reduction.
Acidizing Offshore Sandstone Reservoir with a Single Slug Active Acid System
SUN Lin, YANG Junwei, ZHOU Weiqiang, YANG Miao
2016, 33(1): 97-101. doi: 10.3969/j.issn.1001-5620.2016.01.020
In offshore oil and gas development in China, particle migration, clay particle blocking and inorganic salt blocking during mixed water injection for sewage cleaning have caused damage to unconsolidated sandstone reservoirs. Conventional acidizing jobs in an effort to stimulating the wells drilled were restricted by those adverse factors such as limited work space on well platform, repeated acidizing jobs and short effective production time of the acidized wells, etc. In a study to solve these problems, the synergy of different additives is exploited. In laboratory experiments, HCl, three polyprotic acids, a corrosion inhibitor, a fluorocarbon surfactantand a cationic polymer are mixed in a certain ratio and order to produce a compound, the HX-01 active acid system, which is further concentrated for the ease of job. HX-01 is injected with water in a single slug into the well, greatly simplify the acidizing job. In field acidizing work, HX-01 shows those advantages such as strong scale dissolution, low surface tension, strong clay dissolution, low damage to formation matrix, reduced advancing speed deep in reservoir formations, low corrosion and high dynamic displacing capacity etc. The use of HX-01 has solved the problems encountered in offshore well acidizing jobs, and changed the operation techniques of the conventional acidizing process presently in use.
A New Amphoteric Surfactant Self-diverting Acid System
DONG Jingfeng, Abudukadeer·Abudurexiti, LI Xiaoyan, Gulijianati·Azhati
2016, 33(1): 102-106. doi: 10.3969/j.issn.1001-5620.2016.01.021
In acidizing work, conventional self-diverting acid becomes viscosified at pH between 2 and 4, thus limits the function of converting acids. A new amphoteric surfactant self-diverting acid (VES) was developed based on the viscosifying mechanism viscoelastic surfactant. The viscosity of this acid is increasing during the reaction of acid and rocks, and decreasing when the pH of the reaction system is becoming low. The effects of surfactant, hydrochloric acid, calcium ions on the viscosity of the diverting acid were explored and acid-rock reactions simulated. The equation of kinetics of acid-rock reactions was fitted in accordance with the reaction rate of the acid and rocks. Heat resistance, rheology and gel-breaking ability of VES were studied. In acid-rock reaction, VES had the highest viscosity (144 mPa·s) at hydrochloric acid concentration of 5%, and the acid was diverted. The viscosity of VES was decreasing at temperature above 90℃, indicating that this self-diverting acid is suitable for use in medium- to low-temperature reservoirs. VES has good shear-thinning capacity; more than 90% of the viscosity of VES can be recovered. The reaction rate of VES is 1/2 of the reaction rate of hydrochloric acid, which is beneficial to slow-release diverting. The spent acid, whose viscosity is low (30 mPa·s), is easy to gel-broken and get hydrated when in contact with hydrocarbons and formation water, and the solution after gel-breaking has lower viscosity and surface tension, meaning that it will impose no damage to reservoir formations. VES in field application has obviously enhanced oil production, and shows good prospect in well stimulation.
Preparation and Application of Concentrated Oleic Alcohol Association Polymer Thickening Agent Used in Fracturing Fluids
REN Zhanchun, HUANG Bo, ZHANG Liaoyuan, XIE Guixue, ZHANG Zilin
2016, 33(1): 107-112. doi: 10.3969/j.issn.1001-5620.2016.01.022
Several problems have long existed in continuous preparation and injection of fracturing fluid with dry thickening agents. These problems include high labor intensity, dusting, non-homogeneity of the fracturing fluid (such as generation of solid particles and gel conglomerates of dry thickening agents when dissolving in water), and long dissolution time of thickening agents etc. A new concentrated oleic alcohol association polymer thickening agent was recently developed to solve these problems. The new thickening agent is made of liquid paraffin, methanol, hydrophobic association polymers thickening agents and dispersant, and has good stability and mobility. In laboratory testing, this new thickening agent, a non-crosslinking polymer, dissolved completely in water in only 2 min, and no fisheyes have been found in the solution, making it possible to prepare fracturing fluid fast at well site. A fracturing fluid treated with 0.65% (mass fraction) of the thickening agent has a retained viscosity of 103 mPa·s after shearing at 150℃ and 170 s-1 for 2 h. Compared with guar gum fracturing fluids, fracturing fluid prepared with the new thickening agent has better sand carrying capacity, lower friction coefficient (rate of friction reduction is 63.15%), less residue (less than 80 mg/L), less filter loss and lower formation damage (in dynamic filtration test, permeability impairment was 30%). Fracturing fluids treated with this new thickening agent have been successfully used in 8 wells in Block A, Shengli oilfield.
Study on Filtration Property of Hypercritical CO2 Fracturing Fluid for Shale Reservoirs
LIU Zhenguang, QIU Zhengsong, ZHONG Hanyi, MENG Meng
2016, 33(1): 113-117. doi: 10.3969/j.issn.1001-5620.2016.01.023
Filter loss of fracturing fluid plays a major role in the geometry of fractures created by the fracturing fluid and the performance of fracturing. Reports on the filtration property of hypercritical CO2 fracturing fluid used in shale formation fracturing have not been found at present. Experiments have been conducted on shale reservoir cores (buried at 1,300-2,300 m, with natural fractures developed) taken from the Longmaxi Formation in Sichuan Basin, using a self-made filtration simulator, to study the filtration property of CO2 fracturing fluids with different initial phase states, at 55℃ and (confining pressure) 20 MPa, and different injection pressures and back pressures. Analyses of the experimental data indicate that in the conditions mentioned above, the filtration coefficient of CO2 fracturing fluids is between 1.00×10-4 m/min0.5 and 48.17×10-4 m/min0.5, with the spurt loss being negative. The filtration rate of CO2 fracturing fluid increases with increases in injection pressure, differential pressure, and the widths of fractures. The dominant factor affecting the filtration property of CO2 fracturing fluid in different conditions is different; at hypercritical state (7.38 MPa, 31.1℃), the CO2 fracturing fluid, because of its high viscosity, has a lower filtration coefficient.
Clear Autogenetic Heat Fracturing Fluid and Its Experiment
XIONG Bo, XU Minjie, WANG Liwei, CHE Mingguang, LIU Yuting
2016, 33(1): 118-121. doi: 10.3969/j.issn.1001-5620.2016.01.024
Several autogenetic heat fracturing fluids find their use in reservoir fracturing. In autogenetic heat fracturing, activating agent is added into the fracturing fluid for heat generation, and this makes the process much less efficient. A clear autogenetic fracturing fluid was prepared using a hydrophobic polymer as the thickening agent. The thickening agent has a salt-resistant component added during its synthesis, enabling the thickening agent to be readily dissolving in saltwater. Using organo-zirconiumacidic crosslinking agent, activating agent using for heat generation and modifying agent for crosslinking reaction are not necessary anymore. Fracturing fluid treated with 0.6% of the thickening agent has good heat-resistance and shear-resistance, good elasticity and gel breaking capacity. After shearing for 60 min at 100℃ and 170 s-1, the fracturing fluid retains a viscosity of about 140 mPa·s, and its visco-elasticity equivalent to that of conventional guar gum fracturing fluids. Residue of the fracturing fluid is 11.9 mg/L. This fracturing fluid is suitable for use in fracturing medium-to low-temperature reservoirs. By monitoring pressure changes of the reaction, the extent of reaction of heat generators is measured on a HTHP dynamic acidizing corrosion tester, and this measurement is both simple and accurate, suitable for the optimization of the formulation of autogenetic heat fracturing fluids, and the assessment of the extent of reaction of heat generators. The study shows that no reaction has ever taken place between heat generators in base fluid at 40℃, and 55% of the heat generators react at 80℃, while at 120℃, all heat generators react with each other, indicating that the fracturing fluid should be prepared in advance, and the operation process is the same as that of conventional fracturing fluids.
Effect of Chemicals on Gel Breaking of Associative Structure Fracturing Fluid
JI Sixue, YANG Jiang, LI Ran, QIN Wenlong, QIU Xiaohui
2016, 33(1): 122-126. doi: 10.3969/j.issn.1001-5620.2016.01.025
Supermolecules used in fracturing fluids form associative structures, making the gels of the fracturing fluids very difficult to break. Studies on the effects of several additives on the gel breaking performance of fracturing fluids at 90℃ were conducted. The fracturing fluids used have supermolecular associative structures in them, and the additives tested include organic solvents, peroxide, diesel oil, kerosene, alcohols and mixture of these additives. It is found that at 90℃, addition of 0.5% ethylene glycol monobutylether and 0.5% triethanolamine in a fracturing fluid reduces the viscosity of the fracturing fluid by 80 mPa·s and 77 mPa·s, respectively, and the minimum viscosity of the fracturing fluid maintains at 30 mPa·s. Addition of 0.1% sodium persulfate in a fracturing fluid reduces the viscosity of the fracturing fluid to 4.312 mPa·s in 120 min, showing remarkable potential in gel breaking. Addition of 0.6% diesel and 0.6% kerosene in a fracturing fluid, breaks the gel in 50 min and 40 min, respectively. Interaction between poly fatty alcohols and the association polymers will reduce the viscosity of the fracturing fluid; addition of 1.0% n-octanol reduces the viscosity of fracturing fluids containing supermolecular associative structure to 24 mPa·s. Mixture of chemicals can also reduce the time for gel breaking. For instance, a mixture of 0.03% FeSO4 and 0.1% ammonium persulfate reduces the time by 60 min, and so does the mixture of 0.05% FeS and 0.1% ammonium persulfate. Using the methods described above, gels of fracturing fluids containing supermolecular associative structures can be broken, with no intervention from crude oil.