2018 Vol. 35, No. 1

Display Method:
2018, 35(1)
Application of Micro Powder Manganese Weighting Agent in Drill-in Fluids
ZHANG Hui, JIANG Shaobin, YUAN Xuefang, XU Tongtai, WANG Xi, XIAO Weiwei
2018, 35(1): 1-7. doi: 10.3969/j.issn.1001-5620.2018.01.001
This paper summarizes the progresses made abroad in micro manganese weighted drill-in fluids, analyzes the advantages and disadvantages of weighting materials used in high density drilling fluids, and describes the properties of micro manganese powder weighting agent, such as its chemical composition, physic-chemical property, microscopic shape, particle size distribution, Zeta potential, dynamic stability, density, acid solubility and Mohs' scale of hardness. Compared with traditional weighting materials (barite and hematite etc.) used in high density drilling fluids, micro manganese powder has these properties such as smaller particle sizes, better sphericity and higher specific surface area. Drilling fluids weighted with micro manganese powder show good rheology, antisettling property and lubricity, satisfactorily resolving the contradiction between the rheology and anti-settling property of a high density drilling fluid. The authors have paid much attention in introducing the effects of micro manganese powder on the properties of drill-in fluids and reservoir protection, and presented the application results of the micro manganese powder weighted drilling fluids in north Kuwait and Cormorant North oilfields.
Quantitative Study on Surface Bound Water of Clay with Low Field NMR
SU Junlin, DONG Wenxin, FENG Jie, YANG Peiqiang, LUO Pingya
2018, 35(1): 8-12. doi: 10.3969/j.issn.1001-5620.2018.01.002
The types and extents of clay hydration are directly related to the stabilization of water sensitive shale borehole. Thermogravimetric analysis, a widely used method presently in determining the type and content of clay in formation rocks, is unable to quickly, intuitively and quantitatively measure the type and extent of clay hydration. Based on the relationship between low field NMR T2 relaxation spectrum and the mobility of water molecules, the total signal amplitude of the T2 peak is used to determine the total water content in clay, the ranges of T2 values to determine the types of clay hydration, and the area of the T2 peak to determine the contents of three kinds of water. Laboratory experiments showed that the strongly bound water, weakly bound water and free water in water-saturated clay have T2 values ranging in 0.001-0.1 ms, 0.1-15 ms and 15-200 ms, respectively, corresponding to the contents of the three kinds of water, which are 14.83%, 67.69% and 17.48%, respectively. The T2 relaxation spectrum also intuitively demonstrates that temperature buildup drives water molecules in clay from low degree of freedom to high degree of freedom. BPEI with 8 amino groups is able to dispel more than 90% of the strongly and weakly bound water and all the free water from clay.
Study and Application of a High Performance High Temperature Polymer Drilling Fluid
LIU Xiaodong, GU Huilin, MA Yongle, ZHANG Yong
2018, 35(1): 13-20. doi: 10.3969/j.issn.1001-5620.2018.01.003
Laboratory study has been conducted on a high performance high temperature (up to 200℃) polymer drilling fluid which was to be used in high temperature deep well drilling in environmentally sensitive offshore area. The drilling fluid under investigation has LC50 of greater than 10×104 mg/L, and was formulated with a synthetic polymer as the main additive, and auxiliary additives such as nanophase plugging agent, shale inhibitive agent and extreme pressure lubricant etc., which rendered the drilling fluid shale inhibitive capacity and lubricity matching those of oil base drilling fluids. The drilling fluid formulation is environmentally friendly and can be discharged directly into the sea. The experimental results showed that the high temperature seawater drilling fluid, formulated with barite and formates was stable for more than 48 h at 200℃, and had HTHP filter loss of 12-25 mL. It was resistant to the contamination caused by 20% NaCl and 0.5% CaCl2. 96 h LC50 of brine shrimp by the drilling fluid was greater than 10×104 mg/L. EC50 of luminescent bacteria was greater than 30×104 mg/L.The LC50 and the EC50 values indicate that the toxicity of the drilling fluid conforms to the bio-toxicity requirements of discharging the drilling fluid to Class I sea area. The application of the drilling fluid in oilfields around the Bohai Sea has gained good results; the deepest wells drilled with the drilling fluid was 6,066 m, and the highest bottom hole temperature was 204℃.
Study on Factors Affecting pH Value of Saltwater Drilling Fluids and Methods of Buffering pH Value
LI Xuan, HUANG Weian, JIA Jianghong, WANG Youwei, LI Yunping, WANG Jingwen
2018, 35(1): 21-26. doi: 10.3969/j.issn.1001-5620.2018.01.004
In deep well drilling, the pH value of saltwater drilling fluids decreases quickly and is difficult to control when drilling salt/gypsum formations, salt/gypsum/shale formations and formations with high-pressure salt water. In laboratory experiments, salts, surfactants and amines were investigated for their effects on adjusting and controlling the pH value of saturated saltwater drilling fluids before and after aging. It was understood from the experiments that salts formed by strong bases and weak acids, anionic surfactants, nonionic surfactants, the compounded products of anionic surfactant and nonionic surfactant, and amines all to some extents were able to buffer the pH value of saturated drilling fluids before and after aging. Studies on the effects of mud salinity, commonly used saltwater additives such as sulfonates on pH showed that an increase in the salinity led to quick decrease in the pH value of bentonite base mud. Polymer additives obviously affected the pH value of saturated drilling fluids. Sulfonated additives, on the other hand, was more or less able to buffer the pH value of a mud. A surfactant compound composing 0.3% WJG and 0.1% SDBS has been presented as a new way of pH buffering. This surfactant compound is able to effectively buffer the pH values of seawater drilling fluid, high density saturated drilling fluid and high density organic salt drilling fluid.
Research on Application of a Novel Nanophase Material in Water Base Drilling Fluids for Shale Drilling
LIU Fan, JIANG Guancheng, WANG Kai, WANG Xi, WANG Jinxi
2018, 35(1): 27-33. doi: 10.3969/j.issn.1001-5620.2018.01.005
A layered Nanophase material LDP of 30 nm in particle sizes has been developed to satisfy the needs of shale drilling such as cuttings carrying, plugging nanometer-sized fractures and inhibiting the dispersion of shale formations. Laboratory experiments showed that a 2%LDP suspension, after aging at 120℃, had higher elastic modulus, yield stress and better shear thinning ability than a 6% sodium bentonite suspension. In 0.5%PAC-LV solution, 1%LDP shows better ability in increasing the viscosity and gel strengths of the solution than 4% Na-bentonite. Periodic oscillatory strain scanning demonstrated that LDP suspension showed better ability to restore and break down its gel structure at the switch of high strain and low strain. Particle size measurement and transmission electron microscopy indicated that, compared with Na-bentonite, it is much easier for the LDP to form network structure both in water and in PAC-LV solution. To evaluate the plugging performance of LDP, shale samples rinsed in different solutions were measured for their pore sizes using N2 adsorption method. The measurement showed that LDP has better plugging capacity than nano SiO2 and Nabentonite. SEM scanning showed that LDP can plug the long and narrow nano-sized holes in shale. In clay swelling test, the percent core swelling caused by 2%LDP solution was 45% of the percent core swelling caused by fresh water, better than 7%KCl solution. The percent shale cuttings recovery of LDP in hot rolling test at 100℃ was 59.6%, equivalent to 7%KCl solution. Clay clod rinsed in 2% LDP solution for 96 h still kept its integrity. In general, LDP nanophase material is beneficial to viscosity and gel strength enhancement, plugging of nanometer-sized pores and inhibiting shale formations, and is thus prospective in formulating high performance water base drilling fluids for shale drilling.
Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
QU Yuanzhi, HUANG Hongjun, WANG Bo, FENG Xiaohua, SUN Siwei
2018, 35(1): 34-37. doi: 10.3969/j.issn.1001-5620.2018.01.006
An extreme pressure organic sulfur anti-wear additive has been developed for use in water base drilling fluids. Structural characteristics and extreme pressure anti-wear performance evaluation showed that the organic sulfur compound is a saturated alkane, with sulfur content as high as 35.49%, and has good extreme pressure anti-wear property. An extreme pressure anti-wear additive, MPA, was developed with a modified vegetable oil as the base oil, the extreme pressure organic sulfur anti-wear additive and surfactants. The components of MPA are all environmentally friendly. Performance evaluation showed that MPA has good compatibility with other additives, and is completely dispersible in fresh water or drilling fluids. It helps optimize the properties of drilling fluids and has excellent lubricity.
The Establishment of a New Model for Differential Sticking Analysis
YANG Xueshan, SONG Bitao, REN Mao, HE Zhumei, OU Biao, QI Congli
2018, 35(1): 38-41,46. doi: 10.3969/j.issn.1001-5620.2018.01.007
Accurate prediction of differential sticking plays an important role in minimizing and even preventing pipe sticking. Models presently in use for the prediction of differential sticking are not perfect, lacking studies on the relationship between mud cakes and pressures on the borehole wall. A new differential sticking prediction model has been established based on the studies made by other researchers, taking into account those factors such as the properties of mud cakes, differential pressure and the closed contact interface between drill string and borehole wall. Analyses of differential sticking mechanisms and calculation with drilling data indicated that the closer the permeability of an external mud cake to the permeability of a mud cake formed inside the formation, the higher the pressure exerted on the borehole wall, and this is beneficial to the prevention of differential sticking. A thin high quality external mud cake with good compressibility generates a low adhesion force at the time of differential sticking which is also easy to be unloaded, thereby fundamentally realizing the prevention of differential sticking. This study will provide theoretical guidance to the prevention of differential sticking in field operations and to drilling fluid program design.
A Dual-Pressure Vibrating Tube Type Device for Mud Density Measurement
LUO Yunfeng, LIU Baoshuang, WANG Zhongjie, LAN Qiang
2018, 35(1): 42-46. doi: 10.3969/j.issn.1001-5620.2018.01.008
Mud density control plays a very important role in preventing downhole troubles. There are many factors affecting the online measurement of mud density, such as shaking of well site, mud flowrate and air trapped the mud etc. A serial dual-pressure vibrating tube type mud density measuring device has been designed by modifying the original mud density online test device, realizing the online measurement of mud density. Laboratory and field test showed that the modified dual-pressure vibrating tube type online mud density test device has high precision and high accuracy, with measurement error controlled in less than 0.003 g/cm3. In the working range of the device, the test results are not influenced by temperature and mud flowrate.
Study and Application of Optimized Solids Control Technologies in Jidong Oilfield
2018, 35(1): 47-52. doi: 10.3969/j.issn.1001-5620.2018.01.009
Each block in Jidong Oilfield has different target zones, well depths and well types, and the drilling fluids used in drilling the target zones are also different. Drilling fluids used in drilling operations had solids content and content of bentonite that were higher than necessary. The high contents of solids and bentonite led to a series of problems such as highly viscosified drilling fluid, reduced ROP, differential pipe sticking, and sticking of wireline logging tools etc. To resolve these problems, solids contents and bentonite contents of the drilling fluids used, the configuration and use of solids control equipment (SCE) in each block were investigated, and the effects of formation characteristics, drilling fluid formulation, and the configuration and use of SCE on the control of solids content in drilling fluid were analyzed. Technologies targeted at the specific requirement of solids control was prepared, mainly including the maximum solids and bentonite contents allowed, rules for formulating and converting drilling fluids, and rules for solids control and use of SCE during drilling operations. These technologies have been used on the well G76-65 and the well G76-61 in the block Gaoshangpu. Compared with other 5 wells drilled nearby, it was found that from mud formulation, the addition of polymer additives to the use of SCE, the technologies mentioned above were strictly applied on the two wells. And correspondingly, the properties of the drilling fluids used on these two wells were pretty good, and wireline logging jobs were successful in the first try. Field practices have proven that the optimized solids control technologies are beneficial to the fast, efficient and quality drilling operations.
Lost Circulation Control with High Filtration Lost Circulation Materials
HOU Shili, LIU Guangyan, HUANG Daquan, TANG Changqing, SHU Ruhong, WEI Jinran
2018, 35(1): 53-56. doi: 10.3969/j.issn.1001-5620.2018.01.010
Lost circulation materials with high filtration rate can be used in plugging mud loss zones and enhancing the pressure bearing capacity of the formation. The lost circulation material (LCM) losses its liquids swiftly when spotted at the loss zones and the solids of the LCM formed solid plugs inside the channels through which the mud losses. Drilling fluid flowing passing the surfaces of the solid plugs losses its liquids and forms dense mud cakes on the surfaces of the solid plugs, thereby increasing the pressure bearing capacity of the formation. A high filtration rate LCM has been developed for use in lost circulation control. It has almost no effect on mud rheology, and the volume of the filtrate in 30 s was 180 mL. It can be weighted to 2.3 g/cm3 with barite. In laboratory experiments, the high filtration rate LCM was tried on simulated fractures of different widths, and the pressure bearing capacity was 7 MPa. The high filtration rate LCM has been tried in field operations 7 times in different wells. It has been shown that the success rate using the high filtration rate LCM was 71%, and the time spent in controlling mud loss was only 3-4 h. The successful application of the high filtration rate LCM has provided technical support to high quality high efficiency drilling operations.
Application of KCl Organic Salt Polymer Drilling Fluid in Upper Section of Wells Drilled in Block Shuangyushi, West Sichuan
ZHOU Daisheng, LI Qian, SU Qiang
2018, 35(1): 57-60. doi: 10.3969/j.issn.1001-5620.2018.01.011
The target zones in the block Shuangyushi in west Sichuan are buried deep, and wells drilled in that block have completion depth of at least 7 000 m. Air drilling is generally adopted in drilling the upper φ444.5 mm and φ333.4 mm in an effort to drill fast. It is critical to convert air drilling fluid to liquid base drilling fluids, and so is the performance of drilling fluids used in drilling with "high efficiency PDC bit + PDM". KCl organic salt polymer drilling fluid, under the synergistic effect of KCl and organic salts, performs much better in inhibiting the hydration, dispersion and swelling of shaly formations. Plugging agents, on the other hand, quickly form dense mud cakes on the borehole wall, thereby reducing invasion of mud filtrate into formations and preventing the dry borehole wall generated in air drilling from collapsing because of water (mud filtrate) absorption. By minimizing hydration and dispersion of drilled cuttings, mud rheology becomes stable and is easy to maintain. A drilling fluid with good inhibitive capacity, low viscosity and gel strength is helpful in enhancing bit hydraulics and minimizing adsorption of drilled cuttings on drill bit, thereby avoiding bit balling. Reduction in the concentration of micron-sized particles and submicron-sized particles is helpful in ROP enhancement. Field application of the drilling fluid in well Shuangtan-8 showed that the use of KCl-organic salt polymer drilling fluid ensured the borehole stability of the air drilling section, helped drilling through the bottom of the Shaximiao formation (Shayi member), Lianggaoshan formation, Ziliujing formation and Xujiahe formation successfully. During drilling operations, tripping of drilling string was smooth, borehole wall was stable, electric wireline logging was conducted favorably, no downhole problems took place, and penetration arte was satisfactory. The use of the KCl-organic salt polymer drilling fluidhas satisfied the needs of engineering and mud logging.
A Bulk Expansion Pressure-bearing Lost Circulation Process Suitable for Use in the West Wing of Tianhuan Collapse in Ordos Basin
LI Zhihong, CHEN Pengwei, GAO Guocheng
2018, 35(1): 61-65. doi: 10.3969/j.issn.1001-5620.2018.01.012
In the west wing of the Tianhuan Collapse in Ordos Basin, Changqing Oilfield, mud losses have often been encountered when drilling to the Luohe Formation and Liujiagou group, in which fractures (both vertical and horizontal) are very developed and formation water is active. Rates of mud losses resulting from pressure differential are in a range of 20-100 m3/h. Conventional methods seldom succeeded because of the difficulties in controlling this kind of mud losses. Many kinds of lost circulation material were tested in laboratory and a bulk expansion lost circulation material, HSW-1, was selected. In controlling mud losses, HSW-1 slurry was first spotted into the thief zone to form a pressure bearing barrier to protect the thief zone from being eroded by mud flow. Cement plug was then spotted into the thief zone protected by HSW-1 slurry to completely stop mud losses. HSW-1 when in contact with water will expand to 500-800 times of its original volume, and the pressure bearing capacity of the set HSW-1 slurry is 11 MPa at test pressure of 7 MPa. HSW-1 works normally at 120℃, and time for the HSW-1 to set is 2-6 min. A special tool has been developed for the targeted delivery of HSW-1 to the place where HSW-1 is required because of its short set time, and success rate of mud loss control with HSW-1 can thus be increased.
Drilling Fluid Technology for Mud Loss Control and Borehole Wall Stabilization in the Slant Section of Horizontal Wells in Sulige Gas Field
2018, 35(1): 66-70. doi: 10.3969/j.issn.1001-5620.2018.01.013
In horizontal drilling operations in Sulige gas field, mud losses and borehole wall collapse have occurred in the same slant open hole section. This problem is especially frequently encountered in the block Su-54, where the Liujiagou formation has low pressure bearing capacity and mud losses have occurred frequently. The Shuangshiceng formation, on the other hand, has high collapse pressure and is therefore prone to borehole collapse. Mud losses in the Liujiagou formation and borehole wall collapse in the Shuangshiceng formation are characteristic of the formations in Sulige gas field. To deal with these problems, a compound salts drilling fluid with "low clay content, strong plugging capacity and low density" was developed through laboratory experiments. This drilling fluid, with a certain content of useful solids, was treated with 2% emulsified asphalt, 3% ultra-fine CaCO3 and 1% polyglycol. When the hole angle was increased to 30°, the drilling fluid was further treated with pre-hydrated bentonite slurry to have bentonite content of not higher than 50 g/L. This helped improve the quality of mud cakes, thereby enhancing the capacity of the mud to protect the borehole wall from collapsing. The addition of bentonite slurry also increased the yield point of the mud, rendering the mud better hole cleaning capacity, and this in turn helped decrease mud weight and flow rate necessary for safe drilling operations. Field operations proved that this mud formulation has properties that are compatible with the formation characteristics of the Sulige gas field, and has good inhibitive capacity and strong mud loss control capacity. Remarkable application effects of the drilling fluid formulation have been gained in Sulige gas field.
A Temperature Sensitive Expanding Microcapsule Anti-Gas-Channeling Cement Slurry
ZHANG Xingguo, YU Xuewei, GUO Xiaoyang, YANG Jixiang, YAN Rui, LI Zaoyuan
2018, 35(1): 71-76. doi: 10.3969/j.issn.1001-5620.2018.01.014
A temperature sensitive expanding microcapsule anti-gas-channeling agent has been synthesized with acrylonitrile (AN), methylmethacrylate (MMA) and methyl acrylate (MA) as the wall material, and iso-butane as the core material. The effects of the amount of iso-butane used in the synthesis on the performance of the anti-gas-channeling were studied, and the performance of the temperature sensitive expanding microcapsule anti-gas-channeling cement slurry in controlling gas channeling was evaluated. The studies and the evaluation results showed that the temperature sensitive expanding microcapsule anti-gas-channeling agent can be obtained under the following conditions:in 100 g of deionized water add AN, MMA and MA in a ratio of 3:0.4:2, 30% iso-butane, 1% lauroyl peroxide (LPO, as initiator), 0.1% 1, 4-butanediol dimethacrylate (BDDMA, as crosslinking agent), 20% nano silicon dioxide (as dispersant), and react these substances at 65℃ with the protection of nitrogen. The anti-gas-channeling agent has initial expansion temperature of 65℃, optimal expansion temperature of 83℃, and is resistant to temperature as high as 120℃. Rate of expansion of the anti-gas-channeling agent is 50. Stimulation of water-channeling/gas-channeling in oil well cement and test of cement slurry condensation and contraction indicated that volumetric contraction of cement slurry can be made up for with less than 2% of the synthesized anti-gas-channeling agent, meaning that this anti-gas-channeling agent has good gas-channeling prevention ability.
Causes of Trapped Annular Pressure in High Pressure Gas Wells in Central Sichuan and Well Cementing Solution
LIU Yang, XIAN Ming, FENG Yuqi
2018, 35(1): 77-82. doi: 10.3969/j.issn.1001-5620.2018.01.015
High pressure gas wells drilled in the central Sichuan Basin penetrated multiple pay zones and encountered multiple formation pressure systems. Shallow gases above the Xujiahe Formation and high pressure formations such as the Jialingjiang Formation and the Feixianguan Formation have active gas show. Well cementing job quality has been good, yet there have 12 wells with abnormal pressure in the annulus B and annulus C. By analyzing the well cementing operations, the sources of gas causing the annular pressure and the time for the pressure trapped in the annuluses, and using apparatus and software for cement sheath integrity evaluation to analyze the effects of subsequent work conditions on the sealing integrity of cement sheath, it is inferred that the main causes of pressure trapped in annulus C are that the mechanical performance of the conventional set cement does not satisfy the needs for sealing interlayers in high pressure gas wells, and the integrity of the cement sheath is thus damaged during pipe string pressure test after well cementing, and decrease in mud weight further deteriorates the situation. It is also inferred that pressure trapped in annulus B because of poor job quality in cementing the φ177.8 mm liner string and the weakening of the cement bonding in subsequent operations. Based on the analyses, a micro-expanding cement slurry with good toughness has been developed to fast cement the well to prevent gas from invading into the borehole and to prevent gas channeling from happening. This cement slurry has been applied on 12 wells into which packer type liner hangar was run. Rate of certified job quality of cementing the φ177.8 mm liner string as measured with acoustic amplitude evaluation was increased from 52.98% to 73.18%, indicating that trapped annular pressure problem has been satisfactorily resolved.
Study and Application of Mechanisms Weightable Surfactant Treated Preflush for Well Cementing
2018, 35(1): 83-88. doi: 10.3969/j.issn.1001-5620.2018.01.016
Weightable surfactant treated preflush for well cementing is a preflush viscosified directly with surfactant micelles instead of inorganic suspending agents or organic polymer suspending agents to render the preflush viscosity and gel strength necessary for the suspending of solid particles. This paper gives a detailed description of the suspending mechanisms of this kind of preflush. The weightable surfactant treated preflush can be used in cement slurries with a variety of densities and has good suspending stability and flow properties. It is resistant to high temperatures up to 150℃. It is compatible with drilling fluids and cement slurries, and its rheology can be changed to satisfy the needs of different work conditions. By controlling the viscosity of the preflush, turbulent flow and plug flow can be achieved in displacing hole fluid, and optimum flushing results can be obtained. The use of this kind of preflush improves the bonding between casing string and cement sheath, and the bonding between cement sheath and borehole wall. The weightable surfactant treated preflush also functions as a spacer in well cementing. Field operations on an extended reach horizontal well and a non-conventional well showed that the rheology of the preflush can be adjusted to satisfy the needs of the operations and to obtain optimum displacement and good well flushing. The preflush had good high temperature anti-settling property, which is helpful in improving the job quality of well cementing and guaranteeing the safety of well cementing operations.
Study and Application of a Novel Thixotropic Additive for Oil Well Cement
LU Haichuan, YAN Ping, LIU Gang, WANG Chuncai, HUO Mingjiang, WANG Haiping, Aierken·Abulimiti
2018, 35(1): 89-93. doi: 10.3969/j.issn.1001-5620.2018.01.017
Conventional thixotropic additives used in oil well cement have some shortages such as weak thixotropy and poor overall performance which negatively affecting operation safety. A new thixotropic additive BCJ-200S has been developed to overcome these shortages. BCJ-200S is made of a synthetic polymer and an ultra-fine inorganic powder in a ratio of 2:3. Studies on the performance of BCJ-200S showed that it remarkably improves the thixotropy of oil well cement. A cement slurry treated with 1.5% BCJ-200S had 10 min gel strength increased from 2.3 Pa to 61.0 Pa after standing 10 min. The φ300 readings of the cement slurry before and after standing were 206 and 210, respectively. The gel strength of the cement slurry became 61.3 Pa after standing 10 min more. These data indicate that the cement slurry treated with BCJ-200S had good reversible thixotropy, and BCJ-200S did not negatively affect the thickening, filtration and strength performances of the cement slurry. Laboratory studies also showed that BCJ-200S helps improve the mechanical performance of set cement and enhance the resistance of set cement to breaking. BCJ-200S is also well compatible with other commonly used oil well cement additives. BCJ-200S was first used on the well Guan38-22 in Dagang oilfield. The Ng2 water section in the wellbore was sealed off with 12 m3 thixotropic cement slurry successfully on the first try. The maximum squeezing pressure used to pump cement slurry was 16 MPa. After drilling out the cement plug, the wellbore section sealed was pressure tested with 8 MPa, with no leaking. With the use of BCJ-200S, water cut was finally suppressed.
Resource Utilization of Pyrolyzed Oil Cuttings (Ⅱ): Study on the Performance of Cement Slurry with Drilled Cuttings Residue
YAO Xiao, CAI Hao, WANG Gaoming, GE Zhuang, XIAO Wei, HUA Sudong
2018, 35(1): 94-100. doi: 10.3969/j.issn.1001-5620.2018.01.018
Residues from pyrolyzed drilled cuttings from wells drilled with oil base muds are tried to replace part of the oil well cement (YJ) to make cement slurry for well cementing. Studies have been conducted on the effects of the concentration of pyrolyzed oil drilled cuttings (PODC) and water/solid ratio on the properties of cement slurry. The PODC was measured for its early heat of hydration, hydration products of set cement, pore structure and microscopic morphology with ICC, XRD, MIP and SEM, respectively. The PODC was optimized for its engineering performance with filter loss reducer CHL, silica fume and crystal expansion agent KW-4. It was found that with an increase in the concentration of PODC, the mobility of the cement slurry was increased, the density of the cement slurry was reduced, the setting time of the cement slurry was prolonged, and the compressive strength of the set cement was reduced to some extent. At water/solid ratio of 0.40, a cement slurry with drilled cuttings residue for intermediate casing cementing, PODC-6:40% YJ + 60% PODC + 3% CHL + 4% silica fume + 2% KW-4, and a cement slurry with drilled cuttings residue for production casing (nonproductive section) cementing, PODC-3:70% YJ + 30% PODC + 3% CHL + 3% silica fume + 2% KW-4, were formulated respectively. The engineering properties of the cement slurries with drilled cuttings residue have satisfied the needs of well cementing operations. Microscopic analyses of the cement slurries indicated that cement slurries with PODC had low heat of hydration, and the hydration products of the cement slurries were C-S-H gel and CH. Compared with cement slurry not treated with PODC, the PODC cement slurries had less hydration products, and the degree of density of the PODC cement slurries was also slightly reduced. It is expected that this study will provide a new approach to resource utilization of PODC, and is of potential environmental benefit and economic benefit.
A New Fracturing Fluid with Temperature Resistance of 230℃
YANG Zhenzhou, LIU Fuchen, SONG Lulu, LIN Lijun
2018, 35(1): 101-104. doi: 10.3969/j.issn.1001-5620.2018.01.019
The natural vegetable gum fracturing fluid presently in use works effectively at temperatures up to 177℃. To fracture formations with higher temperatures, a fracturing fluid with temperature resistance of 200-230℃ has been developed with ultrahigh temperature thickening agent, high temperature resistant zirconium crosslinking agent, high temperature stabilizer and efficient gel breaker through large quantity of laboratory experiments. The experimental results showed that, under the synergetic effect of these additives, the fracturing fluid is suitable for use in fracturing formations whose temperatures are higher than the temperature limit of conventional gels. The fracturing fluid has good shear-resistance property at high temperatures up to 230℃, and the polymer consumption for formulating the fracturing fluid is obviously reduced. Complete gel breaking can be realized with the fracturing fluid, and damage to the fluid conducting formations with proppants is low.
A Technology for Stimulating Low Permeability Heavy Oil Reservoirs
HE Chunming, WU Gang, LU Hao, ZHONG Xiaojun, ZHANG Ming, MENG Jie, GUO Zhaoxia, ZHOU Xu
2018, 35(1): 105-108. doi: 10.3969/j.issn.1001-5620.2018.01.020
A set of technologies, with "reservoir stimulation plus fluid quality improvement" as the core technology, have been developed to stimulate low permeability heavy oil reservoirs, which have poor physical properties and high viscosity crude oil, and show poor stimulation results with conventional fracturing technology. An ionic surfactant was selected through laboratory experiment as the viscosity reducer for crude oil, and the dosage of the viscosity reducer was determined to be 3% through optimization. Physical simulation results showed that time required for the viscosity reducer to show optimum viscosity reducing effect was 1-3 d. A low damage fracturing fluid with ultra-low concentration (0.18%) viscosity reducer was formulated through optimization, and the viscosity of the fracturing fluid was maintained at 100 mPa乌s after shearing the fluid at 60℃ and 170 s-1 for 120 min. Using this fracturing fluid, a high conductivity tip screen-out fracturing technology has been developed. This technology has been applied on the well X in Huabei Oilfield, and the initial oil production rate after fracturing was 10.06 t/d, 3 times of the oil production rate of the adjacent well, and water production rate was 1.54 m3/d. The total amount of oil increased 3 months after fracturing was 518 t, indicating that the fracturing job was successful. This technology has provided a good clue for stimulating reservoirs of the same type.
A Compound Acid for Medium to High Water-cut Screen Pipe Completed Wells in Wenchang Oilfield
XIA Guang, LIU Chunxiang, ZHOU Jiyong
2018, 35(1): 109-113. doi: 10.3969/j.issn.1001-5620.2018.01.021
Some oil wells in the Wenchang Oilfield (located in the west of South China Sea), which were completed with screen pipe, are now having high water-cut. In acidizing operations, acids are difficult to be distributed evenly, thus the production of fluid is increased, while the production of oil remains low. Based on the characteristics of the reservoir rocks and the well completion method used, a compound acids, formulated with a self-diverting acid WZX-02 and a retarding acid WHS-05, was developed to deal with the said problems. The compound acids are able to control themselves from entering into formations of high permeability, thereby avoiding water-cut increase after acidizing operations. The compound acids have been pilot tested on the Well D in Block M in Wenchang oilfield. Prior to acidizing, the well had liquid production of 68 m3/d, oil production of 32 m3/d, and water-cut of 53%. After acidizing, the liquid production increased to 207 m3/d, oil production to 117 m3/d, and water-cut reduced to 43%, demonstrating that the compound acids had remarkable ability in oil production enhancement, and can be used in acidizing screen pipe completed wells with high water-cut.
Preparation and Evaluation of a Hydrophobic Cationic Guar Gum for Fracturing Fluid
LIU Tongyi, TANG Huang, CHEN Guangjie, DONG Guofeng, TANG Wenyue
2018, 35(1): 114-118. doi: 10.3969/j.issn.1001-5620.2018.01.022
A modified guar gum (CTGG) has been prepared to minimize formation damage caused by conventional guar gum fracturing fluids. CTGG was obtained through solvent method using guar gum as the raw material, CT1 (a long chain hydrophobic cationic monomer produced with N,N-Dimethyl dodecyl amine and epichlorohydrin) as etherizing agent, methanol as solvent, and sodium hydroxide as catalyst. Characterization of CTGG with IR spectroscopy showed that hydrophobic cationic group has been introduced into the molecular structure of CTGG which dissolved in 60 min. Water insoluble matters and residue were both less than conventional guar gum, The viscosity of CTGG is greater than GG and HPG at different concentrations. Other evaluation experiments indicated that gels formed by CTGG in water had viscosity of 300 mPa·s at 120℃. A fracturing fluid containing 0.35% CTGG (mass ratio) was resistant to shearing at 120℃, having viscosity of at least 67.4 mPa·s and residue of only 246.45 mg/L. These data demonstrate that CTGG has good solubility, thickening performance and temperature and shearing resistance, which are beneficial to protect reservoirs from being damaged.
Temperature Resistance and Shear Resistance of Xanthan Gum and Its Derivatives
LIU Shuang, ZHANG Hong, QIU Xiaohui, FANG Bo, LU Yongjun, ZHAI Wen
2018, 35(1): 119-123. doi: 10.3969/j.issn.1001-5620.2018.01.023
Temperature resistance and shear resistance are important parameters of fracturing fluid and the one the key factors to the success of fracturing job. To widen the application of non-crosslinking xanthan gum fracturing fluids and improve their job performance, study has been conducted on the effects of chemical modification and molecular conformation of xanthan gum (XG) on the high temperature resistance and shear resistance of XG solution. It was found that at low temperatures, chemical modification can remarkably enhance the temperature resistance and shear resistance of XG. At high temperatures, chemical modification plays almost no role in enhancing the temperature resistance and shear resistance of XG. Chemical modification improves the networking structure of XG molecules and the viscoelasticity of XG solution. Addition of salts (ions) into XG solution accelerates the formation of double helix conformation of XG molecules. The combined action of chemical modification and salts on XG remarkably improves the temperature resistance, shear resistance and suspending capacity at elevated temperatures. Comparison of rheology before and after shearing at 180℃ indicated that salts can enhance the viscoelasticity, thixotropy and apparent viscosity of XG solution at elevated temperatures, improving its sand carrying capacity, and widening the application of non-crosslinking fracturing fluids formulated with XG and modified XG. It is concluded that combined action of chemical modification and salts greatly improves the rheology, temperature resistance and shear resistance of XG solution, thereby widening the application of non-crosslinking fracturing fluids formulated with XG, especially the XG fracturing fluids mixed with seawater.
Study on High Temperature Block Removing Fluids Used on Dina-2 Ges Field
YANG Shuzhen, YAO Erdong, CHEN Qing, ZHOU Fujian, JING Hongtao, ZHANG Hangyan, WANG Shan
2018, 35(1): 124-128. doi: 10.3969/j.issn.1001-5620.2018.01.024
Severe sand production and blocking of production string have been encountered in Dina-2 Gas field, seriously affecting the safe and steady production of the well. An efficient high temperature chelating block removing agent has been developed to deal with the problems above mentioned. Based on the study on the characteristics of the rocks found in the Dina gas field, a high temperature organophosphorus acid chelant that can efficiently chelate calcium, aluminum and iron ions was selected through complexometric titration. The chelant was then mixed with hydrofluoric acid and weak organic acids in different ratios to form many base block removing fluids. The blocking removing fluids were then tested through dissolution and corrosion of rock powders for their dissolving rate, high temperature resistance and corrosion inhibitive capacity. Two formulations with better performance were chosen through the tests. The dissolving ability of the two block removing fluids was verified by reacting them with the blockage found in a well. It was found that the block removing fluids were able to function properly at 160℃. The dissolving rate of the block removing fluids was increasing with time, with a maximum of 75%. Compared with mud acid, the new block removing fluids have these advantages such as low acidity, weak corrosiveness, high dissolving capacity, and ability to effectively prevent secondary sedimentation. Analyses of the mineral components and solution of the blockage reacted with the block removing fluids have shown that the block removing fluid are able to quickly dissolve most of the blockage and slowly dissolve quartz and feldspar etc., and metallic ions such as calcium, magnesium, aluminum and iron ions can be effectively dissolved into the solutions, demonstrating the block removing fluids of their superior high temperature performance.