2017 Vol. 34, No. 5

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2017, 34(5): .
A Viscoelastic Surfactants: Its Development and Application in Micro Foam Drilling Fluids
GUO Jin'ai, XIE Jianyu, SUN Ju, LIU Guangcheng, LU Guolin, YANG Guotao, TAN Anping
2017, 34(5): 1-7. doi: 10.3969/j.issn.1001-5620.2017.05.001
A viscoelastic anionic surfactant VES-1 has been synthesized with amino-compound and long-chain acryl chloride for use in micro foam drilling fluids. A micro foam mud treated with VES-1 was formulated with selected micelle enhancer and secondary surfactants. The micro foam mud had good viscoelasticity and stable foam. Low shear rate (0.01 r/min) viscosity of the foam mud is 100 000 mPa·s, and the half-life longer than 18 min. Based on the formation characteristics of the Wen-23 gas storage, the VES-1 micro foam mud was further treated with foam stabilizer and filter loss reducers to form a micro foam mud of high thixotropy. Laboratory evaluation results have proved its high thixotropy and ability to quickly form network structure inside the mud. The initial (10 s) gel strength of the VES-1 foam mud was at least 12 Pa, and there was only slight difference between the 10 s and 10 min gel strengths. This is especially beneficial to carrying drilled cuttings out of hole and plugging low pressure thief zones to avoid mud losses. VES-1 is apparently superior to the commonly used surfactants (such as OP-10) in mud loss control under pressure. In mud loss experiment, injection of 325 mL of the VES-1 mud at 120℃ increased the pressure to above 10 MPa, indicating that this mud can help resolve mud loss problem in low pressure formations. VES-1 micro foam mud also had good pressure resistance; its density increase did not exceed 0.05 g/cm3 under 30 MPa. After aging at 120℃ for 16 h, the mud properties remained unchanged. The VES-1 mud is able to resist contamination by 10% compound saltwater. It also has good lubricity; the friction coefficient of the VES-1 mud is 54% less than commonly used polymer drilling fluids. Properties of the VES-1 micro foam mud are able to satisfy the needs for the construction of the Wen-23 gas storage.
Recyclable Micro Foam Drilling Fluid: Its Study and Application in Burial Hill Structure in Chad
LUO Huaidong, SHI Libao, ZUO Jingjie, SHI Kaijiao, SONG Juye
2017, 34(5): 8-13. doi: 10.3969/j.issn.1001-5620.2017.05.002
The burial hill structure in Chad has micro fractures that are quite developed and the formation pressure coefficient is generally less than 1.0. Using conventional drilling fluids, severe mud losses are inevitable. To avoid mud loss, recyclable micro foam drilling fluid has been adopted in burial hill drilling. This drilling fluid was first developed in laboratory with a high performance foaming agent GWFOM-LS, which also was also a foam stabilizer. GWFOM-LS is resistant to high temperature (130℃), high salinity (10% NaCl) and high calcium (5 000 mg/L). The micro foam drilling fluid developed has density adjustable between 0.70 g/cm3 and 0.96 g/cm3, and has been used successfully on the well Baobab C1-13 in Chad. The recyclable micro foam drilling fluid showed stable properties in field applications, good cuttings carrying capacity and reservoir protecting performance, satisfying the needs for safe drilling operation. Electric signal transmission through the foam was satisfactory, and severe mud losses in burial hill drilling were resolved. All these successes have laid a solid foundation for burial hill reservoir development.
Application of a Nanomaterial Drilling Fluid in Dagang Oilfield
ZHENG Shujie, JIANG Guancheng, XIAO Chengcai, WANG Xiaoyue, MA Jinsong
2017, 34(5): 14-19. doi: 10.3969/j.issn.1001-5620.2017.05.003
Nanomaterials have been more and more used in drilling fluids, gaining good results in drilling operation. It has been found in the field application that the nanomaterials always become aggregated as the concentrations increase, making it difficult for the nanomaterials to take effect. Based on the study of the mechanisms of nanomaterial aggregation, a nanomaterial was grafted to render it good dispersity in drilling fluid. The molecules of the nanomaterial have good flexibility and deformability. The molecules of the nanomaterial can be adsorbed on the surface of rocks, thereby enhancing the ability of the nanomaterial to plug micro fractures and fissures. A nanomaterial filter loss reducer has been synthesized to formulate a drilling fluid with other nanomaterial additives, such as lubricant and shale inhibitor. The nanomaterial drilling fluid functions properly at 150℃, and has properties as follows:API filter loss ≤ 2.4 mL, HTHP filter loss ≤ 9.8 mL, coefficient of friction ≤ 0.04, percent recovery of permeability of cores ≥ 91%, and percent recovery of drilled cuttings in hot rolling test ≥ 90.5%. Field application has shown that the nanomaterial drilling fluid had good lubricity and reservoirs drilled were effectively protected from being damaged.
Application of Environmentally Friendly High Performance Water Base Muds in Ultra Depp Well Drilling in Piedmont Area
LI Jiaxue, ZHANG Shaojun, LI Lei, SUN Dongshan, ZHANG Chao, WANG Tao
2017, 34(5): 20-26. doi: 10.3969/j.issn.1001-5620.2017.05.004
High density water base drilling fluids have been used to drill ultra-deep, high temperature, ultra-high pressure wells penetrating salt formations in the piedmont structure in Kuche County, Xinjiang. Challenges encountered using conventional water base drilling fluids included difficulties in mud property maintenance, tight hole and pipe sticking. An environmentally friendly high performance water base drilling fluid formulated with borehole wall stabilizer, nano filming agent, high performance lubricant and specially designed fast drilling agent was tested in field operations. The high performance drilling fluid had high inhibitive capacity and good rheology and lubricity, and was environmentally friendly. It also helped protect reservoirs from being damaged. The application of this drilling fluid in a well drilled in the piedmont structure in Kuche has proved its performance as said above. Rate of penetration (ROP) of the well was 6.6% faster than the ROP of an offset well drilled with oil base drilling fluid. No drilling accidents have ever occurred, and occurrence of downhole complications was greatly reduced. This high performance low bio-toxicity water base drilling fluid has passed environment protection inspection. Drill cuttings produced were in their original colors, and were not colored by the drilling fluid. This environmentally friendly high performance drilling fluid has provided a means of drilling complex formations in environmentally sensitive area.
Laboratory Study on Oil in Water Compound Mud Cake Remover
AI Zhengqing, YE Yan, LI Jiaxue, ZHOU Yicheng, LIU Ju, ZHANG Qingwen
2017, 34(5): 27-32. doi: 10.3969/j.issn.1001-5620.2017.05.005
When fractured tight sandstone reservoirs are drilled with high density oil base drilling fluids, solid particles from drilling fluids invade the formation fractures, and mud cakes are formed on the surface of the borehole wall and the surface of the fractures. The solid particles and mud cakes are diffcult to remove, causing formation damage to the reservoirs. A high effciency, high temperature and cost effective oil-in-water compound mud cake remover has recently been developed to resolve these problems. The compound mud cake remover is composed of mixed acids, high temperature penetrant, cleaning agent and emulsifer etc. Comparison of a compound mud cake remover-O/W emulsion system and a mud cake remover-nano-emulsion system showed that compound mud cake remover is better than the nano-emulsion in cleaning oil and eroding mud cakes. The compound mud cake remover has good high temperature stability; it works well at temperatures as high as 120℃. At static conditions, 90% mud cakes can be cleaned with the compound mud cake remover. At dynamic conditions, after removing mud cakes, formation permeability recovery of 89% can be reached, and the optimum treatment time is 8 h. This compound mud cake remover has simple composition and good performance, it fast removes particles and mud cakes plugging flow channels, thereby effectively enhancing permeability recovery, especially when cost-cutting and effciency-enhancing prevail presently.
Study on Performance of High Molecular Weight Polymer Gel and Its Application
LI Yuan, YU Peizhi, AN Yuxiu, YU Tiefeng, ZHAO Yuguang
2017, 34(5): 33-38. doi: 10.3969/j.issn.1001-5620.2017.05.006
In workover operations, wellbore fluids go into reservoir formations, resulting in formation damage. This problem can now be resolved with a high molecular weight polymer gel developed by grafting water soluble acrylamide onto the backbones of natural high molecular weight celluloses. Mechanism analyses and performance evaluation of the high molecular weight polymer gel showed that the gel time of the polymer gel is adjustable between 30 min and 600 min, and time for the gel to break is between 1 d and 30 d. The highest temperature at which the polymer gel functions normally is 160℃. Low apparent viscosity (100 mPa·s) renders the polymer gel good injectability. Using crosslinking agent and catalyst, the gel time can be controlled within a reasonable range, and the gelled polymer gel will lose its flowability, forming a high strength gel plug with high pressure bearing capacity. This polymer gel has good contamination resistance ability, and is resistant to contamination from strong acids, strong bases, saltwater of high salinity and crude oils. After operations, the polymer gel can be broken into low viscosity fluid which can then be circulated out of hole. Compared with conventional mechanical sealing and cement sealing methods, polymer gel has much better application prospects in well workover, lost circulation control and water kick control.
A High Performance Broad-spectrum Oil Remover with Capability of Disposing of Both Oil-bearing Drill
WANG Li, SONG Wenwen, LI Zhiyong, WEI Huoyun, ZHANG Fengyan, LI Yan
2017, 34(5): 39-43. doi: 10.3969/j.issn.1001-5620.2017.05.007
Oil-bearing waste drill solids bring about serious pollution to the environment around the well site. Oils on drilled solids are generally removed with specially designed oil removers which have limited versatility. Based on the pollution characteristics of oil-bearing drilled cuttings and oil-bearing sludge, a new high performance broad-spectrum oil remover has been developed through molecular structure design. The new oil remover is capable of disposing of both oil-bearing drill cuttings and oil-bearing sludge. The structure of the new oil remover has been characterized with IR spectrum and mass spectrum etc. Surface tension and wettability measurement indicated that the new oil remover is highly surface active. The optimum conditions for oil-bearing drill cuttings disposal are:oil remover concentration at 1 000 mg/L, temperature at 50℃, centrifugal speed at 4 000 r/min, and centrifugal rotation time for 10 min. The optimum conditions for oil-bearing sludge disposal are:oil remover concentration at 2 000 mg/L, temperature at 50℃, centrifugal speed at 4 000 r/min, centrifugal rotation time for 10 min. Oil removing test showed that 90% of oils contained on drill cuttings or sludgecan be removed with the new oil remover, realizing oil removing with one broad-spectrum oil remover.
Drilling Challenges and Drilling Fluid Technologies for Shale Gas Drilling in Changning Area
MING Xiansen, YUAN Zhiping, BIN Chenggang
2017, 34(5): 44-49. doi: 10.3969/j.issn.1001-5620.2017.05.008
Challenges encountered in shale gas drilling in Changning area from the Jialingjiang Formation to Hanjiadian Formation are as follows:bit balling in drilling long section of mudstones, mechanical collapse of formation with developed beddings, borehole wall collapse in drilling the top section of well causing pipe sticking, developed fractures with good connectivity resulting in mud losses, borehole enlargement resulted from formation creep, and contamination to drilling fluid by mudstones. Challenges encountered in drilling fluid maintenance and the solution were also provided in this paper. Based on the analyses of drilling problems encountered from Jialingjiang Formation and Hanjiadian Formation, the drilling fluid formulation to be used was optimized accordingly. The optimized drilling fluid was used in 10 times in different wells in Changning area, greatly reduced the occurrence of downhole problems. With the optimized drilling fluid, the Jialingjiang gypsum formation was penetrated with no troubles, the Feixianguan mudstone formation was drilled with success, and cave-in of the Changxing-Longtan formations was avoided. Any downhole complicationsrelated with drilling fluid were all avoided. Lithology variance in the Changning area is remarkable. An in-depth understanding of the formations in this area, and specific suggestions and measures presented in drilling fluids design help minimize the occurrence of downhole complications, providing technical support to quality, efficient and cost-effective drilling of shale gas.
Optimization and Application of Drilling Fluid with Low Free Water in High Angle Well Section
GUO Haifeng, FU Shunlong, CHEN Bo, HUANG Zhao, ZHANG Haishan, WANG Lei, LIAO Jiangdong
2017, 34(5): 50-53. doi: 10.3969/j.issn.1001-5620.2017.05.009
Low free water drilling fluid was required to drill the φ311.15 mm hole section in a gas field in East China Sea. The drilling operation was successful, but the existence of interbedded mudstone and sandstone has resulted in high friction when RIH and excessive torque in the early stage of development. In later stage development of the oilfield, more and more highly deviated wells were drilled, borehole wall instability and borehole cleaning were becoming increasingly urgent because of high well angle and long open hole. In dealing with these problems, sodium chloride was introduced into the low free water drilling fluid to reduce the activity of water base and to enhance the inhibitive capacity of the drilling fluid. Other measures taken included reducing filtration rate to minimize shale swelling. Field operation showed that after the introduction of sodium chloride, the property of the low free water drilling fluid became more stable, and the stability of wellbore was improved, realizing smooth tripping of drill pipes. With these measures, problems in drilling high angle well section through thick shale formation have been resolved, drilling time saved, and the efficiency of drilling operation increased. The technology has provided good technological support for drilling wells with similar borehole profile through formations of the same rock type in East China Sea area.
Study on Effects of Temperature on Coefficient of Heat Conductivity of Saltwater
LI Huaike, LIU Weili
2017, 34(5): 54-57. doi: 10.3969/j.issn.1001-5620.2017.05.010
In studying the effects of temperature (especially low temperature in deep water) on the coefficient of heat conductivity (CHC) of saltwater, transient hot-wire method was adopted to measure the CHC of 5 kinds of commonly used saltwater at different temperatures (4~60℃). Analyses of the experimental data showed that, at the same salt concentration, CHC changed with temperature in similar pattern, i.e., at low temperatures (4~20℃), CHC increases slowly with temperature; at temperatures above 20℃, CHC increases fast with temperature. At the same temperature, CHC decreases with increase in salt concentration. Saltwater samples from 2 deep water wells were measured in laboratory for their CHC. It was found that CHC of the two samples was only slightly affected by temperature; the differences of CHC at 4℃and 50℃ were 0.036 W/(m·K) and 0.53 W/(m·K), respectively. At temperatures above 40℃, CHC of the two saltwater samples was not affected by changes in temperature.
Application of Simple Managed Pressure Drilling Technology in Hexiwu Structure
LI Zhenxuan, XIONG Lasheng, MA Chunhui, WANG Shuai, CUI Shuqing, SHEN Fazhong, ZHANG Yong, LIU Yibin
2017, 34(5): 58-61. doi: 10.3969/j.issn.1001-5620.2017.05.011
The Hexiwu Structure in Huabei Oilfield is characteristic of high pressure, difficult production and low efficiency, and narrow safe drilling window, water/gas kick, lost circulation and differential pipe sticking are problems frequently happened during drilling operations. To resolve these problems, simple managed pressure drilling technology was applied during drilling operations. Based on applied research work, the mud density and the level of the managed pressure at wellhead were optimized. By optimizing the position of the "pressure equilibrium point", mud density was reduced, and severe water/gas kick and lost circulation were avoided. Application of the technology on 7 wells showed that mud density was reduced by 0.1 g/cm3, and average rate of penetration increased by 64.7%, proving that the simple managed pressure drilling technology is worth spreading in areas with high pressure and low permeability formations, or where safe drilling window is narrow.
Study of High Temperature Silicate Cement Slurry
ZHANG Chi, CHEN Xiaoxu, LI Changkun, WANG Yu, YU Yongjin, DING Zhiwei
2017, 34(5): 62-66. doi: 10.3969/j.issn.1001-5620.2017.05.012
Conventional silicate cements at elevated temperatures have a series of problems, such as poor stability, declining of compressive strengthof set cement and cracking of set cement etc. To address these problems, studies have been conducted on the selection of materials for modification of cement, optimization of the mechanical properties of set cement and the overall properties od modified silicate cement slurry. It was concluded that, at elevated temperatures, addition of highly active minerals (such as volcanic ash) into cement can ensure the sound development of the compressive strength of set cement. Crystal whiskers/fibers selected play an important role in the "brittleness reduction and toughness enhancement" of set cement, ensuring that set cement does not crack when curing at elevated temperatures and its elastic modulus is controlled to less than 9.0 GPa. Using high performance filter loss reducers, retarders and high temperature stabilizers suitable for the cement, the cement slurry will have good overall properties, i.e., low filter loss, good high temperature stability, thickening time that is controllable and short transit time etc. This study is of importance to safe cementing of deep and ultra-deep wells with high job quality.
Study on New Oil Well Cement Retarder Able to Inhibit Abnormal Thickening of Cement Slurry
LYU Bin, ZHANG Shande, WU Guangxing, LIU Xin, SHI Zhongnan, CHEN Xiaolou
2017, 34(5): 67-72. doi: 10.3969/j.issn.1001-5620.2017.05.013
Oil well cement slurries treated with retarders presently in use experience abnormal gelation between 90℃ and 150℃; in their gelation curves appear "bulge" and "shoulder". A highly inhibitive branched polymer retarder DR150 has been developed through graft copolymerization to address this problem. Laboratory evaluation o indicated that cement slurries treated with DR150 had these characteristics between 90℃ and 150℃, such as, low initial consistency, thickening time that was adjustable, short transition time, low sensitivity to changes in temperature and concentration of DR150, and being free of high temperature reversal and retarding time that is too long. DR150, having good overall properties, is also able to inhibit other abnormal gelation phenomena. The application of DR150 in the Block Xujiaweizi in Daqing Oilfield has gained success; high quality well cementing job was achieved. DR150 is highly valuable in securing the achievement acquired in unconventional hydrocarbon and deeply buried gas exploration and development, and in improving the job quality of deep well/ultra-deep well cementing.
Development and Application of High Density Salt Resistant Spacer BH-HDS
QI Ben, LIU Wenming, FU Jiawen, LIN Zhihui, SUN Qinliang, WANG Shengming, ZONG Yong
2017, 34(5): 73-78. doi: 10.3969/j.issn.1001-5620.2017.05.014
Wells drilled with high density drilling fluids and wells penetrating formations with salt and gypsum impose stricter requirements on the increase of displacement efficiency of spacers during well cementing. A spacer was formulated with a selected biopolymer, an inorganic suspended matter and compounded inorganic salts as suspending agent, an anionic polymer as thinner, and barite as weighting agent. Study showed that the spacer, with its density adjustable between 1.50 g/cm3 and 2.40 g/cm3, had good rheology and sedimentation stability, and superior high temperature performance. At 180℃, the spacer of 1.80 g/cm3 had density difference of 0.06 g/cm3 between the upper and lower parts of the spacer; when the density of the spacer was 2.20 g/cm3, the density difference became 0.03 g/cm3.Furthermore, this spacer is resistant to the contamination from saltwater of semi-saturation; spacers formulated with saltwater of semi-saturation had good suspension stability and rheology. Good compatibility of the spacer with drilling fluid and cement slurry was obtained by mixing the spacer with drilling fluid, with cement slurry and mixing the space with drilling fluid and cement slurry to test its compatibility. Cement slurries containing the spacer had longer thickening time than pure cement slurries.BH-HDS has been used in high-pressure formations with salt and gypsum (Iraq) and mid-deep reservoir(Dagang oilfield), gaining good operation achievements.
A New Geopolymer Well Cementing Gelled Material and Analysis of Its Resistance to Salt Attack
YANG Zengmin, ZHUANG Jianshan, HE Jianyong, GUO Chunlong, CHU Junjie, BI Yi
2017, 34(5): 79-85. doi: 10.3969/j.issn.1001-5620.2017.05.015
A geopolymer has been proposed to replace the low corrosion resistance gelled material used in cement slurries for cementing deep high salinity wells. Experiments have been done to study the resistance of the geopolymer to salt attack. A mixture of fly ash, metakaolin based geopolymer and class G cement was cured in salt solutions of different salinities for 28 d, and the compressive strength of the mixture was measured. It was found that with an increase in salinity, the loss of the compressive strength of the common set cement is increasing, while the compressive strength of the mixture is increasing with increase in salinity to the contrary. Element analysis with XRF, mineral analysis with XRD and analysis of acidity and alkalinity showed that ion exchange in saltwater environment remarkably changes the hydration environment and hydration product components of cement, resulting in remarkable strength loss of the cement. For the geo-polymerization of geopolymer, however, the effect of the ion exchange process is quite weak. Morphology analysis using SEM demonstrated that in salt water, geopolymer can form much denser microstructure, which is considered to be the main reason for the geopolymer to have an enhanced strength. This study showed that a geopolymer at its early age has superior resistance to salt attack, and can be used to replace cement in cementing deep high salinity wells after being verified with more experiments.
A High Strength Temporary Plugging Agent
LIU Deping
2017, 34(5): 86-90. doi: 10.3969/j.issn.1001-5620.2017.05.016
Many tools and facilities are required in expensive cement plug placement. Cement plug placement in deep and high temperature wells is of high safety risk. To minimize this risk and address the problems associated with cement plug placement, a high strength temporary plugging agent is required. The temporary plugging agent should have such properties as high strength, simplicity in preparing and convenience in pumping. Laboratory experiments have been conducted to select the core materials such as gelling agent and suspending agent, and to develop the required activator. Based on literature survey and laboratory experiments, a high strength temporary plugging agent GQ-1 was developed. GQ-1 has a wide density range (1.50-1.90 g/cm3) and stable properties. The mobility, flow index and consistency of GQ-1 are all in reasonable ranges. GQ-1 is compatible with commonly used drilling fluids, and the plug formed by GQ-1 has high strength. GQ-1 can be mixed with mud circulation and mixing systems, and pumped with drilling pumps. GQ-1 has been applied on two wells (Well Yangdu-H2, for instance) with great success. Pressure test on the plugs formed by GQ-1 in the two wells showed 63.3 MPa and 64.3 MPa, which were qualified. Success of the application on the two wells provided a technical support for the spreading of GQ-1.
Key Factors Affecting the Effectiveness of Evaluating Indicators for Bactericides Used in HPGG Fracturing
WU Lirong, LUO Zhao, WANG Qunli, HOU Wanyong, JIANG Jianhua, CHEN Xian, ZHAO Yu
2017, 34(5): 91-95. doi: 10.3969/j.issn.1001-5620.2017.05.017
Bactericides used in hydroxyl propyl guar gum (HPGG) fracturing fluids are inclined to become decayed quickly, hence hindered well fracturing. In laboratory studies the conditions under which the bactericides were evaluated and the field conditions compared.Three factors were found affecting the decaying process of the bactericides.First, the bacteria used in standard evaluation process do not take into account those from fluid tanks. Second, the pH values of the bactericides used in HPGG (produced through alkaline crosslinking) fracturing fluids should not be less than 7. Consideration should be given to the changes in pH values by greater than 0.1 which will cause changes in the viscosity of the guar gum liquid, and the effectiveness of bactericides should be superior to that of pH value crosslinking modifiers used in HPGG fracturing fluids. Third, percent viscosity retention should be determined on the basis of the viscosities of HPGG of different concentrations and sand carrying capacity through crosslinking performance.
Study and Application of a Corrosion Inhibitor Used in Self-diverting Acid
WANG Yunyun, YANG Bin, ZHANG Zhen, CUI Fuyuan, XU Xingjuan, QIU Weihong, GU Qingjiang
2017, 34(5): 96-99. doi: 10.3969/j.issn.1001-5620.2017.05.018
Horizontal wells completed with screen pipes are generally acidized with diverting acids, a method with which acid can be evenly distributed in a target zone with ease and effectively. Corrosion inhibitors, an important insurance for safe operation of acidization with diverting acids, are not compatible with most of the self-diverting acids presently in use, therefore the diverting action is negatively affected, and the corrosion inhibitive efficiency is remarkably reduced. A self-diverting acid, ZXHS, has recently been developed aimed at addressing these problems. Laboratory evaluation showed that the corrosion rate of ZXHS can be controlled within 5 g/(m2ws) at 90℃, and within 20 g/(m2ws) at 120℃, all conforming to the industrial requirement of "Grade 1" product. A selfdiverting acid treated with ZXHS had viscosity of greater than 160 mPa·s, and good corrosion inhibition and diverting performancecan be achieved with the diverting acid. ZXHS has been used in Dagang oilfield and Al-Ahdab oilfield (Iraq), gaining good operation achievements.
Study and Application of a New Corrosion Inhibitor forHigh Temperature Acidization
ZHANG Shuo, LYU Xuanpeng, LIU Dezheng, XU Qingxiang, MA Tianli, HUANG Qi
2017, 34(5): 100-105. doi: 10.3969/j.issn.1001-5620.2017.05.019
A pyridine quaternary ammonium salt has been developed to satisfy the needs of HTHP acidization operations. The pyridine quaternary ammonium salt was synthesized with 3-methryl pyridine and benzyl chloride as the main raw materials, and a certain ratio of extender and surfactant were added to the product to produce a corrosion inhibitor, HTCI-2 used in high temperature acidizing operations. Evaluation of HTCI-2 showed that the corrosion rate of an N80 coupon was 38.1 g/(m2wh) or 39.6 g/(m2wh) under these conditions:180℃,16 MPa, 20% HCl (or 12%HCl + 3%HF) and 4.5% of HTCI-2. SEM analyses, EDS energy spectrum and polarization curve experiments showed that HTCI-2 is a hybrid corrosion inhibitor that functions through inhibiting anodic reaction. By forming a tight filming against the surface of N80 coupon, HTCI-2 effectively prevents the surface of the steel from being contacted with acids. HTCI-2 is free of toxic alkyne compounds, and is compatible with commonly used additives for acidizing operations. Acidizing job in the well Binshen22-8 in Binshen block was conducted smoothly.
Carboxymethyl Hydroxypropyl Xanthan Gum and Its Rheological Properties
LIU Shuang, ZHANG Hong, FANG Bo, LU Yongjun, QIU Xiaohui, ZHAI Wen
2017, 34(5): 106-110,116. doi: 10.3969/j.issn.1001-5620.2017.05.020
To broaden the application scope of xanthan gum, a carboxymethyl hydroxypropyl xanthan gum (CMHPXG) has been developed withepoxy propane, sodium chloroacetate and xanthan gum (XG) in alcohol solvent. The CMHPXG synthesized was studied for its rheological properties (shearing thinning characteristics, viscoelasticity and thixotropy) and its basic performance (sand carrying capacity, high temperature resistance and shearing resistance) as a fracturing fluid. The study showed that the apparent viscosity of a 0.5% CMHPXG water solution was 3.35 times of that of an XG water solution of the same concentration, and the CMHPXG solution had elastic modulus, viscous modulus and thixotropy loop area obviously greater than the XG solution. The settling velocity of haydite in CMHPXG solution was far less than that in XG solution, greatly improving sand carrying capacity of fracturing fluids. A 0.4% XG solution had apparent viscosity of 43.1 mPa·s, while a 0.4% CMHPXG solution, after being sheared 90 min at 120℃ and 170 s-1, had apparent viscosity of 64 mPa·s, indicating that CMHPXG had better high temperature resistance and shearing resistance. The flow curves of XG solution and CMHPXG solution can be characterized with Cross constitutive equation, and the simulated rheological values were well fitted with the experimental ones. Compared with xanthan gum, the CMHPXG developed has basic properties that are greatly improved.
Development and Evaluation of a New Emulsified Gelled Acid
WANG Xu, JIA Wenfeng, REN Qianqian, WANG Baofeng, JIANG Tingxue, CHEN Zuo, KE Yangchuan
2017, 34(5): 111-116. doi: 10.3969/j.issn.1001-5620.2017.05.021
Gelled acids have commonly been used as retarded acids in acid fracturing carbonate reservoirs. Gelled acids have good retarding and friction reducing performance, they cannot satisfy the requirements of deep acidification of high temperature reservoirs though, and a retarded acid with high temperature resistance and better retarding performance is required. Emulsified acids have these characteristics such as low filter loss, good retarding performance, and capable of generating long acid-eroded fractures, it is the poor high temperature stability of emulsified acids limits their application in acid fracturing operations. In this study, a gel acid and an emulsified acid were mixed together in the development of a new retarded acid, the so-called emulsified gelled acid (EGA). The formula and preparation method of an EGA resistant to 120℃ were determined through laboratory experiment. The stability, temperature resistance, high temperature rheology and acid-rock reaction have been evaluated. It showed that the EGA prepared was stable at room temperature, no segregation and demulsification have ever been observed after standing 48 hours. The EGA can maintain stable for 2 hours under 120℃. The viscosity of the EGA after sheared 80 min under 120℃ and 170 s-1 was 40 mPa·s. Kinetics of the reaction between the EGA and rocks indicated that the reaction rate of EGA with rocks was less than that of emulsified acid and gelled acid with rocks, respectively. These data demonstrate that EGA has good high temperature resistance, double retarding performance, and is worth popularizing.
A pH Regulator Used in Low Concentration HPGG Fracturing Fluids
LI Wei, MA Hongfen, HAO Pengtao, ZHANG Qiuhong, LU Wei, WANG Yue, ZHANG Manyi, LI Shiheng
2017, 34(5): 117-122. doi: 10.3969/j.issn.1001-5620.2017.05.022
Conventional fracturing fluids formulated with hydroxypropyl guar gum (HPGG) and organoboron crosslinking agent have those problems such as high consumption of guar gum, excessive residue and high operation cost etc. Using a new crosslinking extender, the crosslinking environment can be changed, and the B(OH)4- ions necessary for crosslinking reaction are continuously provided by the organoboron in the gel fluid system, ensuring HPGG to do its utmost to gel at the lowest concentration. In this way the consumption of HPGG can be reduced, and formation damage by fracturing fluid residue can be minimized. With this theory, a series of low guar gum fracturing fluids used between 45℃ and 120℃ have been developed. Compared with conventional fracturing fluids, the consumption of HPGG in these low guar gum fracturing fluids was reduced by 20%-35%, and amount of residue reduced by 25%-30%. The temperature resistance, shearing resistance and sand carrying capacity of the low guar gum fracturing fluids are not compromised, and can satisfy the needs of field operations. The new fracturing fluids not only reduce formation damage, they also help reduce time required for fluid mixing and operation cost.
Flow Back or Not after Well Completion: Comparison of Their Impact on Formation Damage in Different
LIU Changlong, ZHANG Liping, LAN Xitang, MENG Xianghai, ZOU Jian, FU Yangyang, ZHANG Lu
2017, 34(5): 123-128. doi: 10.3969/j.issn.1001-5620.2017.05.023
Bohai oilfield has long been developed with water injection. Some water injectors are directly put into injection without flowback because of special environmental requirements and time limit, resulting in high injection pressure and deficiency in injection rate. A study has been conducted to resolve this problem, focusing on whether a well was flowed back or not in the early stage. Differences between formation damage caused by the two operations (flow back or not flow back) were extensively analyzed from the types of formation damage and formation damage mechanisms. Extent of formation damage and effects of formation damage by drilling fluid on water injection in late stage were studied. The study showed that drilling and completion fluids caused formation damage in two ways, retention and adsorption of chemicals. Formation damage caused by retention is a reversible process and can to some extent be relieved, formation damage caused by adsorption, on the other hand, is an irreversible process. Laboratory experiments showed that well flowback greatly reduces permeability impairment by drilling and completion fluids. Formation damage caused by drilling and completion fluids is not just a decrease in permeability by retention and adsorption; it also is concerned with the alteration of the properties of rock surfaces which in turn affects water injection in late stage.