2017 Vol. 34, No. 1

Display Method:
2017, 34(1)
Progresses in Studying Drilling Fluid Nano Material Plugging Agents
MA Chengyun, SONG Bitao, XU Tongtai, PENG Fangfang, SONG Taotao, LIU Zuoming
2017, 34(1): 1-8. doi: 10.3969/j.issn.1001-5620.2017.01.001
This paper analyzes the mechanisms under which the hard and brittle shale formations destabilize, introduces the characteristics and application of nano materials, and summarizes the progresses made in the studies of drilling fluid nano material plugging agents, including organic and inorganic nano plugging agents. Also discussed in this paper are several case histories of the application of nano plugging agents. The authors believe that plugging agents having core-shell structures, which take advantage of the rigidity of inorganic nano materials and the deformability and filming ability of organic polymers, do not heavily affect the viscosity and gel strength of the drilling fluids in which the plugging agents can well dispersed. This kind of nano plugging agents can plug the pore throats of shales at low concentrations, thereby produce a pseudo hydrophobic "borehole wall" with some strength. This pseudo "borehole wall" not only hinders the invasion of drilling fluids, it also increases the pressure bearing of formation. The authors thus believe that the combination of inorganic nano materials and organic polymers indicates the direction for the development of anti-collapse additives in the future.
Experimental Study on a New Ultrahigh Temperature Shale Inhibitor
ZHANG Xin, QIU Zhengsong, ZHONG Hanyi, TANG Zhichuan, XU Jiangen, ZHANG Daoming
2017, 34(1): 9-15. doi: 10.3969/j.issn.1001-5620.2017.01.002
Study on high temperature shale inhibitors is of great importance in satisfying the needs of high temperature deep well drilling and in improving the inhibitive capacity of high temperature water base drilling fluids. A new ultrahigh temperature shale inhibitor, HT-HIB, was studied for its high temperature performance and working mechanism through laboratory experiments, such as test of bentonite to yield, hot rolling test, shale core swelling test, pressure transmission measurement, x-ray diffraction to measure the c-spacing of clay, Zeta potential test and thermogravimetric analysis etc. The study has shown that HT-HIB was able to inhibit the hydration, swelling and dispersion of shales, and to contain pressure transmission to some extent, and was superior to the polyamine shale inhibitors presently used in high performance water base drilling fluids. In the experiment, HT-HIB remained stable at 220℃. HT-HIB worked by inserting its amine group at the end of its molecular chain, in a way of monolayer adsorption, in between the crystal layers, thereby destructing the surface hydration structure of the clay particles and squeezing the adsorbed water out of the crystal layers. After adsorbing HT-HIB molecules, the hydrophilicity of clay particles was greatly reduced, and adsorption of water molecules was thus stopped. Furthermore, the solubility of HT-HIB changed with pH of the system, and was thus able to separate out from the system to plug the micro fractures in shales, beneficial to hinder the invasion of water molecules into shales. To summarize, HT-HIB showed excellent inhibitive capacity through synergy of chemical inhibition, wettability reversal and physical plugging. It paves the way to developing the new generation high temperature high performance water base drilling fluids.
Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
HAN Zixuan, LIN Yongxue, CHAI Long, LI Daqi
2017, 34(1): 16-22. doi: 10.3969/j.issn.1001-5620.2017.01.003
The Ordovician carbonate rock reservoirs drilled in Tazhong area (Tarim Basin) have complex geology and developed fractures, 50% of which with widths between 20 μm and 400 μm. These fractures have led to frequent lost circulation, well kick and severe gas cut, which in turn resulted in well control risks. Complex distribution of fractures and high formation temperatures (180℃) make bridging with sized particles less effective in controlling mud losses. In laboratory experiment, commonly used testing methods for evaluating the performance of plugging drilling fluids are unable to effectively simulate the real fractures, and hence there is a big discrepancy between the laboratory evaluation and practical performanceof the plugging agents. To solve this problem, a new method has been presented based on the idea of plugging micro-fractures to prevent gas-cut. In this method, natural/artificial cores are used to make test cores with fractures of 20 μm-400 μm in width and roughness that is closely simulating the fractures encountered in the reservoirs drilled. Included in the new method are a device used to evaluate the performance of a drilling fluid in plugging micron fractures, and an evaluation procedure. With this method, particle, fiber and deformable LCMs sized in microns and nanometers were selected and an LCM formulation compatible with polymer sulfonate drilling fluid and ENVIROTHERM NT drilling fluid developed. This plugging PCM formulation, having acid solubility of greater than 70%,does not render contamination to reservoir.
Study on Enhancing Borehole Wall Stability by Micro Emulsion
ZHANG Jinghui
2017, 34(1): 23-27. doi: 10.3969/j.issn.1001-5620.2017.01.004
Mud shales have plenty of micro-fractures which are difficult to plug and seal. Mud filtrates infiltrate swiftly deep into the formation under the action of osmotic pressure, capillary force and differential chemical potential, causing the formation to become unstable. A micro emulsion has been developed. Measurement of the size distribution of the emulsion droplets showed that the micro emulsion was stable, and the droplet sizes remained stable during a certain period of time in laboratory experiment. The size of the emulsion droplet became slightly bigger after dilution. When the dilution factor reached 20, the size of the droplet did not change anymore. The micro emulsion also had good high temperature stability; it remained stable at 150℃. Diluted micro emulsion had median droplet size of about 30 nm, and was able to enter into shale formations. The droplets can coalesce to form droplets with bigger diameters at certain salinities. In micro emulsion containing 5% NaCl, droplets sized in nanometers disappeared. When the concentration of CaCl2 in the micro emulsion exceeded 0.2%, the median droplet size was several nanometers. These enlarged droplets can be adsorbed inside pores of fractures in mud shale formations and stay there, becoming coalesced, thereby improving the plugging performance of the micro emulsion. Contact angle measurement showed that the micro emulsion remarkably changed the wettability of shales, altering the wettability of the surface of shale from hydrophilicity to some hydrophobicity. In surface tension measurement, addition of 2% of the micro emulsion reduced the surface tension to 31.4 mN/m, indicating that the micro emulsion had some inhibitive capacity. The micro emulsion developed had good compatibility with drilling fluid used and showed only slight effect on the rheology of the drilling fluid. It also helped improve the quality of mud cake and the filtration property of drilling fluid.
Study of Hydrophobic Inhibitive Water Base Drilling Fluid System and Application in Shale Gas Well
JING Minjia, TAO Huaizhi, YUAN Zhiping
2017, 34(1): 28-32. doi: 10.3969/j.issn.1001-5620.2017.01.005
A hydrophilically inhibitive water base drilling fluid has been developed to drill shale gas wells penetrating the Longmaxi Formation. This drilling fluid was formulated with a hydrophilically inhibitive agent CQ-SIA and a high performance lubricant CQLSA. CQ-SIA, the core additive of the formulation, is amphoteric in nature, and can render wettability reversal to the surface of rocks. It forms on the surface of rocks a hydrophilic film, thereby encapsulating and inhibiting the rocks from disintegration by water invasion. Hot rolling test results showed that 1% CQ-SIA gave percent cuttings recovery of 83.72%, remarkably higher than that obtained with KPAM, AP-1 and KCl. CQ-LSA, thanks for its special molecular groups and structure, can form lipophilic film on the hydrophilic surfaces of drilling tools, mud cakes and formation rocks, thereby greatly decreasing frictional resistance experienced in drilling. Sticking coefficient of a 5% bentonite slurry treated with 1% CQ-LSA was 0.0507, lower than the 5% bentonite slurries treated with two commonly used lubricants RH-220 and BARALUBE. The formulated drilling fluid had good rheology,high inhibitive capacity and good lubricity that were equivalent to oil base drilling fluid. Addition of 1%-3% anti-sloughing plugging agent, 1%-2% poly glycol and 0.8%-1.6% nano plugging agent rendered the formulation good plugging performance. It also had good contamination resistance. Success has been gained in the first use of this formulated drilling fluid on the well Changning H25-8. Mud properties in the horizontal fourth interval (3,079 m open hole length and 1,500 m horizontal section) were all maintained stable. No downhole problems have ever occurred. Tripping, wireline logging, casing running and well cementing were all done smoothly.
Synthesis and Application of a Comb Polymer Filter Loss Reducer in Deep Well Saltwater Drilling Fluid
XU Yunbo, LAN Qiang, ZHANG Bin, CHEN Jian, SUN Dejun
2017, 34(1): 33-38. doi: 10.3969/j.issn.1001-5620.2017.01.006
A comb polymer filter loss reducer, DMP-1, was synthesized through solution polymerization with allyl polyoxyethylene ether 400 (APEG400), acrylamide (AM), and 2-acrylamido-2-methyl propane sulfonic acid (AMPS). DMP-1 was developed in an effort to overcome the deficiencies of presently available high temperature salt-resistant filter loss reducers used in an environment with high salinity and divalent salts. The synthesized product was a viscous transparent liquid containing 30%DMP-1. Structure characterization of DMP-1 showed that APEG400, AMPS and AM all participated in the reaction to form the comb polymer and the polymerization was complete. Thermogravimetric analysis showed that DMP-1 decomposed at 320℃. Comparison of DMP-1 with the commonly used filter loss reducers such as DSP-2, Driscal D or PAMS601 showed that, after aging at 180℃, the percent reduction of the viscosity of DMP-1 was less than 42.0%, and the property of DMP-1 remained stable at 200℃. DMP-1 was resistant to salt contamination to saturation, and calcium contamination to 3%. These data indicate that DMP-1 works better in salt and calcium environment than the widely used high temperature salt-resistant filter loss reducers such as DSP-2. Application of DMP-1 in the 3rd interval (penetrating salt and gypsum formations) and the 4th interval (high temperature) of the well Tailai-201 and the well Yongxing-1 in Fuling area demonstrated that DMP-1 performed very well at high temperatures, high salinities and high calcium concentrations, effectively reducing the API filter loss of saltwater drilling fluids and calcium-treated drilling fluids, thereby ensuring the safety of drilling operation.
Development and Application of High Performance Drilling Fluid Bridging Formation Stabilizer
ZHANG Xianmin, JIANG Guancheng, XUAN Yang, FU Jianguo, DONG Wei
2017, 34(1): 39-44. doi: 10.3969/j.issn.1001-5620.2017.01.007
Borehole wall destabilization has long been a problem that needs to be solved. A high temperature bridging formation stabilizer QFT, has been developed based on the working mechanism under which formation stabilizers are adsorbed on clay particles and formation minerals. Monomers used in synthesizing QFT were AM, AMPS and a strong absorbent monomer M, and potassium persulfate was used as the initiator. The polymerization lasted for 4 hours at 60℃. QFT is a white viscous liquid with 10% active content. The molecular weight of QFT is ca. (8-60)×104 g/mol. QFT is a drilling additive of high inhibitive capacity, good filtration control and weak effect on the viscosity of base mud. The highest temperature for QFT to function is 150℃. Laboratory evaluation and analyses showed that, compared with fresh water, the rate of linear expansion of 3%QFT water solution (tested on shale cores) was reduced by 44.56%, and the percent recovery of shale core in hot rolling test was increased by 34.1% at 150℃. The percent recovery of shale cuttings tested with QFT was greater than KCl, KPAM and FA-367. Cores thoroughly disintegrated in fresh water after soaking for 10 min remained integrity after soaking 24 hours in QFT solution. X-ray diffraction showed that the low molecular weight QFT can enter the space between the crystal layers of clay, thereby prevent water molecules from entering the clay. Base mud treated with QFT had fine clay particles with higher specific surface area, indicating that QFT had been adsorbed onto the surface of clay particles through bridging, and this inhibited the agglomeration of clay particles at high temperatures and ensured that there were fine particles in the base mud to form a thin tight mud cake. The API filter loss of a 4% bentonite base mud treated with 3% QFT was reduced by 48.33% after aging. Drilling fluid containing potassium and calcium, when treated with QFT, had reduced filtration rate. With the same drilling fluid, the percent recovery of shale cores (samples taken from field) was more than 95%, and the strength of artificial cores soaked at 120℃ in the potassium calcium drilling fluid with QFT treatment was 14% higher than the cores soaked in potassium calcium drilling fluid with no QFT treatment. Application of QFT on the well H160 in Hongshanzui demonstrated that potassium calcium drilling fluid treated with QFT successfully inhibited borehole wall instability. Meanwhile, the drilling time of this well was reduced by 43% than the adjacent well H170-X. Monthly drilling rate was increased by 70%, and drilling cost was thus remarkably reduced.
A New Method of Simulating Micro Fractures in Shale and Plugging Evaluation Experiment
YANG Juesuan, HOU Jie
2017, 34(1): 45-49. doi: 10.3969/j.issn.1001-5620.2017.01.008
There are many methods available presently for the simulation of micro fractures in Shale. All these methods have limitations, and are unable to trulysimulate the hydration and dispersion processes of shales in contact with water at HTHP conditions. To solve this problem, several simulation methods, such as the smooth steel block simulation method, sand bed plugging experiment method, simulation with artificial fracture (on split rocks) method and transparent tampered glass simulation method etc. were analyzed, and based on the analysis, a new method has been developed. In thenew method, a standard core plug is obtained by dry drilling samples,and artificial fractures are then made in it.The surface of the artificial fractures is covered with tinfoil of different thickness to simulate micro fractures of 10-100 μm in width. The core plug is put into a core holder that is connected with dynamic filter press, and a device for evaluating the capacity of plugging micro fractures in shale is formed. The assembly of the device, the experimental procedure, the function and the advantages of the device are introduced in this paper. An equation for the calculation of the width of micro facture is presented, and the equivalent widths of micro fractures are calculated through conversion of accurately measured data. Laboratory experiment has shown that this simulation method has high precision and good repeatability. This method can be used not only to simulate the hydration, dispersion and swelling of shale in contact with liquids, but also to simulate the plugging of micro fractures by drilling fluid on bottom hole at high temperature and high pressure. The simulation can be used to extensively study the plugging mechanism of micro fractures to provide reliable experiment method and datasupport for the selection of plugging agent and optimization of drilling fluid formulation.
Analysis of the Mechanism of Hydrophobically Associating Polymer used as LCM while Drilling
JIANG Guancheng, LIU Chong, HE Yinbo, JIANG Qihui, WANG Chunlei, GE Qingying, ZHAO Li
2017, 34(1): 50-53,59. doi: 10.3969/j.issn.1001-5620.2017.01.009
A hydrophobically associating polymer, JD, has been synthesized with long chain alkyl dimethyl allyl ammonium chloride, acrylamide, N-vinyl pyrrolidone and acrylic acid in a certain ratio of initiators and a certain polymerization condition. JD was developed to deal with the difficulties in plugging highly heterogeneous permeable formations with conventional lost circulation materials (LCMs). IR characterization showed that JD was a copolymer of the four monomers. Analyses of a 0.3% JD solution, a 0.6% JD solution and a 4% bentonite slurry containing 0.3% JD with transmission electron microscope (TEM) demonstrated that a micelle-like hydrophobically associating structure, with sizes between 0.1-0.2 μm, was formed among the polymer molecules. Meanwhile, a dynamic network was formed between the molecules of JD and bentonite particles, a reason for JD to have superior plugging performance. Using FEI's Quanta200F (a field emission environmental scanning electron microscope) to examine the mud cake formed by a JD treated drilling fluid, it was found that a network structure was generated on the surface of the mud cake by the polymer molecules. In static plugging experiment with a drilling fluid treated with 0.3% JD, it was found that mud losses through a 0.45 mm-0.90 mm sand bed was reduced by 82%, and sand beds of 0.22 mm-0.45 mm and 0.12 mm-0.22 mm were completely plugged, with almost no mud loss. This meant that JD can be used to plug heterogeneous permeable formations to prevent mud losses of different rates. In laboratory experiments, JD showed good compatibility with SMP-II, SPNH and poly glycols. When mixed with Redu1, NH4-HPAN and emulsified asphaltene, the viscosity and the gel strengths of the mixtures were increased to some extent, making JD more suitable for use in drilling fluids with moderate viscosity and gel strengths.
Research on Safe Drilling Technology for Ultra Deep Ultrahigh Pressure Saltwater Zones in Piedmont Area, Kuche
ZHOU Jian, JIA Hongjun, LIU Yongwang, LI Weidong, DENG Qiang, YANG Yanming
2017, 34(1): 54-59. doi: 10.3969/j.issn.1001-5620.2017.01.010
Wells drilled in the piedmont area in Kyche, Xinjiang have to penetrate thick salt and gypsum formations, which have complex geology, ultrahigh pressure saltwater with poor distribution patterns in length and breadth, highly varied formation pressures that are difficult to predict. Drilling fluid properties inevitably become deteriorated when high pressure saltwater cut is encountered. The deterioration of drilling fluid properties in turn results in frequent blowout, lost circulation, or pipe sticking, significantly affecting the progress of drilling operation. To resolve these problems, the entrapment nature of the high pressure saltwater and previous drilling practices were analyzed based on the drilling behavior in high pressure saltwater drilling. In laboratory study, simulating experiments were conducted to determine the limits of saltwater invasion to drilling fluid. Based on the research, a new technique has been developed to minimize the effects of high pressure saltwater. In this technique, the high pressure saltwater is allowed to go into the drilling fluid in annular space in a controlled manner by regulating choke valves and the flow rate of drilling fluid. Each time the volume of water allowed into the well should not exceed 10% of the volume of the annular space. Many times of saltwater draining reduces formation pressure. In this way, the downhole troubles resulted from saltwater invasion can be minimized, thus mitigating the drilling difficulties resulted from the piedmont ultra-deep ultra-high pressure saltwater. Field application of this technique has shown that, using sound method to drain saltwater under controlled pressure is able to reduce saltwater formation pressure. A balance point between water kick and mud loss should be found to ensure the safety of well control.
Effects of Acid and Base Types on pH Controlled Reversible Emulsion
LIU Fei, WANG Yanling, GUO Baoyu, WANG Xudong, ZHANG Yue
2017, 34(1): 60-64. doi: 10.3969/j.issn.1001-5620.2017.01.011
By changing external conditions, reversible emulsion can vary between oil-in-water emulsion and water-in-oil emulsion to play a better role that is expected. Studies have been conducted on the preparation and stability of reversible emulsions and the effects of acid and base types on them. The studies demonstrated that, a reversible emulsion with good reversibility can be prepared with selected emulsifiers through a predetermined process, and the emulsion can retain good stability before and after reversion. The types of acid and base, especially the anions of high valence in acids, play an important role in the reversion of reversible emulsion. Hydrochloric acid and acetic acid can reverse the phase of emulsion. Sulfuric acid does not change the phase of emulsion, nor does it demulsify the emulsion. Citric acid demulsifies emulsion. In phase changing of reversible emulsion caused by NaOH, Na2CO3, NaHCO3 and ammonia, a maximal electric conductivity appeared; it appeared just during the process of phase change, not after the completion of phase change. These studies can be applied in the treatment of mud cakes produced by reversible emulsion drilling fluids formulated with reversible emulsions; using acid solution, the mud cakes can be easily disposed of with good results.
Trajectory Optimization of Extended Reach Well to Widen Safe Drilling Window
SHEN Haichao, ZHANG Huawei, LIU Chang, WANG Jianning
2017, 34(1): 65-69. doi: 10.3969/j.issn.1001-5620.2017.01.012
Extended reach well technology has been used to produce the natural gas in the offshore area from onshore in developing the Block S located in the east of Sakhalin, Russia. The designed well depth (MD) was 12,000 m (TVD 2,800 m) and the horizontal displacement was about 11,000 m. The ratio of horizontal displacement to vertical depth was 3.93. The wells were designed to have four intervals. It was found from the previous experiences that the lower Okobykaiskiy formation and the Daginskiy formation had narrow safe drilling windows (0.3-0.4 g/cm3), downhole problems such as lost circulation, borehole wall collapse and pipe sticking etc. were drilling risks that needed to be considered, especially in drilling extended reach wells. Researches on how to widen narrow safe drilling window were inadequate to meet field requirement, most of which were focused on the optimization of drilling fluid properties to widen the safe drilling window. To solve the narrow safe drilling window problem in extended reach well drilling, mechanical and chemical measurements shall be adopted. First, well profile optimization, improvement of stress state around the borehole and widening of safe drilling window should all be taken into account in the well trajectory designing stage. In this stage, the effects of the main well trajectory parameters on safe drilling window should be analyzed. Based on the analyses, the well trajectory was optimized to reduce borehole collapse pressure and increase formation fracture pressure, thereby realizing the widening of safe drilling window through mechanical method, which in turn paved the way for further widening safe drilling window through chemical method, and created favorable conditions for efficient drilling in areas with narrow safe drilling windows. The technologies of widening safe drilling window obtained have been used successfully in drilling the extended reach wells in Block S, with the safe drilling window widened by 25%-100% compared with the safe drilling window prior to the well trajectory optimization. This work is of importance in dealing with narrow safe drilling window problem.
Drilling Fluid Technology for Deepwater HTHP Well
HU Wenjun, CHENG Yusheng, LI Huaike, XIANG Xiong, YANG Honglie, XIONG Yong
2017, 34(1): 70-76. doi: 10.3969/j.issn.1001-5620.2017.01.013
Well LS25-1S-1 is a deep water HTHP well drilled to 4 448 m, completed at the Meishan Formation. A six-interval well profile was adopted during drilling. The predicted pressure coefficient of the φ212.7 mm target section was 1.70-1.84. Narrow safe drilling window, blowout, lost circulation and the formation of gas hydrate were all problems that needed to be addressed. Meanwhile, the bottom hole temperature and the wellhead temperature are 147℃ and 17℃, respectively, requiring the high density drilling fluid to have good high temperature and low temperature stability, good performance in preventing barite settlement, and good rheology. Gas samples from the block LS were used in studying the formation of gas hydrate. HydraFLASH, a computer software, was used to draw the P-T phase diagram of gas hydrates at different concentrations of gas hydrate inhibitors. From the P-T phase diagram, a gas hydrate inhibition formulation used during drilling and non-drilling processes was formulated:(9%-15%) NaCl+5%KCl+10% KCOOH+ (0-45%) MEG. A high temperature filter loss reducer, HTFL was selected to control fluid loss. At a concentration of 0.8% HTFL, the HTHP filter loss of the formulated drilling fluid was less than 10 mL, and quality of the mud cake was satisfactory. PF-FPA, a newly developed plugging agent, was used in the drilling fluid, and it had better plugging performance than another plugging agent FLC2000. In laboratory evaluation, the drilling fluid formulated showed high temperature stability (170℃), stable rheology at both high temperature and low temperature, resistance to 10% calcium bentonite contamination, good settlement stability and plugging performance, and recovery of permeability higher than 80%. In filed application, through simulation with computer software Drill Bench, the flow rate was reduced to 1 400 L/min, and the corresponding ECD was 1.94 g/cm3, lower than the equivalent density of 1.96 g/cm3, at which lost circulation would occur. At ROP of 10 m/h, the efficiency of carrying drill cuttings out of hole was still higher than 85%, satisfying the need for hole cleaning. The success in completing the well indicted that the formulated drilling fluid had solved the problems previously existing in the area.
Application of Oil Base Drilling Fluids in Donghai Gas Field
ZHU Sheng
2017, 34(1): 77-82. doi: 10.3969/j.issn.1001-5620.2017.01.014
The target zones of the Donghai gas field are the Huagang Formation and the Pinghu Formation, whose formation characteristicssuch as poorly cemented sandstone-mudstone interbeds, fractured mud stone and developed coalbeds, are unfavorable to drilling operation. Unstable borehole wall and poor hole cleaning are the main causes of downhole troubles. Wells drilled in the gas field of interest have maximum hole depth of 6,716 m, maximum horizontal displacement of 4,686 m, maximum TVD of 4,429 m, highest bottom hole temperature of 150℃ and highest temperature at the wellhead of 115℃. High well angle and high ratio of horizontal displacement to vertical depth make it hard to clean the hole, and high formation temperature makes equipment maintenance difficult. A low viscosity high gel strength oil base drilling fluid has been introduced to safely and efficiently drill the gas wells. The oil bade drilling fluid was treated with 2% plugging agent PF-MOLSF, 2% filming plugging agent PF-MOLPF and 2%-3% hydrophobic colloidal plugging agent PF-MOHCP. In field operations, the concentration of the gelling agent PF-HSV-4 was adjusted for the drilling fluid to have good carrying performance, and hence good hole cleaning. In drilling the unstable sections, more filming plugging agent was used. During the whole drilling process of 7 wells, no mud losses and other downhole troubles had ever occurred. Tight hole can be easily removed by reaming, and time spent reaming the hole was reduced by 70% compared with exploratory wells. Other operations were all done safely and smoothly. The HTHP filter loss in drilling the reservoir section was controlled to less than 3 mL, and the filtrate was almost whole oil, helpful in eliminating reservoir damage by water invasion, to name but one. Laboratory evaluation and field application showed that the oil base drilling fluid had good rheology, electric stability and lubricity. Borehole wall stabilization and reservoir protection were both achieved. With the aid of property maintenance and cuttings disposal measures, the application of the oil base mud has made a great coup in the Donghai gas field.
Effects of Different Types of Weighting Agents on the Performance of Oil Base Drilling Fluids
YUE Chaoxian, XIONG Hanqiao, SU Xiaoming, ZHUANG Yan, XU Peng
2017, 34(1): 83-86. doi: 10.3969/j.issn.1001-5620.2017.01.015
The success of oil and gas well drilling depends to a large extent on the performance of drilling fluid, whichis greatly affectedby the weighting agent used. A drilling fluid weighted with different weighting agents will perform quite differently during drilling. In laboratory studies, a micron powder barite, a conventional barite and a micro powder manganese mineral used in formulating drilling fluid samples were analyzed for their particle sizes. The viscosity, API filter loss and friction coefficient of mud cake of the three drilling fluids were measured to study the effects of weighting agent on the performance of drilling fluid. It was shown that the micron powder barite had the finest particle sizes and the drilling fluid formulated with this barite had the highest viscosity, and mud cake of poor quality was formed. Drilling fluid formulated with the conventional barite had poor lubricity. The manganese mineral had bigger particle sizes and wider particle size distribution.A drilling fluid formulated with the manganese mineral and conventional barite had performance that was obviously improved.
Analysis of Reservoir Protection Mechanism by Direct Drilling Fluid Flowback
ZHANG Weiguo, XU Mingbiao, YOU Fuchang
2017, 34(1): 87-91. doi: 10.3969/j.issn.1001-5620.2017.01.016
Horizontal well open hole completion is a way of well completion to maximize well production rate. In offshore drilling, well completion is generally done with solids-free drill-in fluid, supplemented with gel-breaking well completion. Direct flowback of drill-in fluid is a technology developed on the basis of this way of well completion. In this paper, parameter design, additive selection and well completion technique were systematically analyzed and evaluated, and the mechanism of reservoir protection of this technology was also analyzed. The composition of the drill-in fluid is as follows:seawater+soda ash/caustic soda+rheology modifier VIS+starch filter loss reducer STARFLO+soluble salt (shale inhibition and mud weight)+high purity sized calcium carbonate MBA. The three functional additives of the formulation can all be liquefied by 0.3% HTA (a chelating agent) solution. The liquefaction of the additives left no residue and the mud cakes in the wellbore and near the borehole wall were all converted to clear saltwater. MBA is a mixture of calcium carbonate powders with five particle sizes. The particles of MBA can be "inter-inserted" with starch to form a mud cake that is much denser. Laboratory experiment has shown that the drill-in fluid had low-shear-rate viscosity of around 30,000 mPa·s, optimum contamination-resistance and flowback ability, and the highest permeability return. After contaminated with 15% drill cuttings, the drill-in fluid still had permeability return of more than 80%. This drill-in fluid was used in twelve wells in three oil fields and one gas field in the east of South China Sea. The maximum temperature at the hole bottom was 60-130℃, and the highest mud density was 1.20 g/cm3. Three of the twelve wells penetrated low porosity low permeability reservoirs and the rest nine wells penetrated reservoirs with medium to high porosity and permeability. The drilling operation was successful. The use of this technology simplified the process of well completion, saved operational time and cost, and protected the reservoirs from being damaged.
Treatment and use of Waste Drilling Fluid with Existing Solids Control Equipment
HU Zubiao, WANG Qingchen, CHEN Tingting
2017, 34(1): 92-95. doi: 10.3969/j.issn.1001-5620.2017.01.017
Waste drilling fluids in Changqing gas field are treated with gel-breaking and solid-liquid separation technologies to conform to the environment protection requirements. In gel-breaking the drilling fluids, a new gel-breaking agent, CQPJ-1, was developed to replace the single-purpose, slow and low-efficiency conventional gel-breaking agents. CQPJ-1 is able to reduce the quantity of electric charge of clay colloids and suspended particles, thereby decreasing the coagulation stability of the suspension system. By oxygenolysis, CQPJ-1 decomposes polymer materials, producing primary radicals and initiating a chain oxidation reaction, thereby dramatically reducing the molecular weight of polymer. CQXN-1, a cationic polymeric flocculant with moderate molecular weight, was selected to flocculate destabilized clay particles through its cationic group and long molecular chain, making the flocs much easier to mechanically dewater than flocs flocculated with inorganic flocculants. Laboratory evaluation has been conducted on the performance of gel-breaking agents, including H2O2, potassium permanganate, sodium phosphite and CQPJ-1, and the performance of flocculants such as poly aluminum chloride, poly ferric chloride, aluminum sulfate and CQXN-1. It was found that, using existing solids-control equipment, a waste drilling fluid with pH adjusted between 6.0-6.5, after treatment with 2%CQPJ-1 for 3 hours and then adding 0.15%CQXN-1, can be solid-liquid separated at 2,200 r/min. The separation efficiency and results have achieved the expected goal. Contamination index of the liquid phase from the treated waste drilling fluid was greatly reduced, and drilling fluids prepared with the liquid obtained had properties conforming to the requirements of drilling operation.
A Solution to the Improvement of the Quality of Cement Sheath-formation Bonding Based on Geopolymer Theory
BU Yuhuan, ZHAO Letian, WANG Chunyu
2017, 34(1): 96-100. doi: 10.3969/j.issn.1001-5620.2017.01.018
Mud cakes left over on the borehole wall by drilling fluid play a major role in determining the quality of the bonding between cement sheath and formation. Solidification of mud cakes provides a new clue for solving the bonding problem. A new idea of mud cake solidification based on the geopolymer principle is presented in this paper. In this idea, the advantages of mud cake solidification by slag and the advantages of MTA well cementing technology were combined to provide a solution to the improvement of the quality of cement sheath-formation bonding. In laboratory studies, metakaolin and ultra-fine slag, as two potentially active materials, were added to a drilling fluid. Ata ratio of bentonite, metakaolin and ultra-fine slag of 3:3:1, the mud cake formed had higher strength under the action of activator. Optimization of activation parameters showed that, the amount of sodium silicate, the optimum activator, should be 72% of the amount of metakaolin, and the amount of sodium hydroxide (NaOH) used for the activation of slag should be 2% of that of metakaolin. The optimum activating time was 15 min. It was found that the metakaolin and the slag had only slight effect on the properties of the drilling fluid tested. The strength of the mud cake of the base mud was increased by 63 times after solidification, and the strengths of the mud cakes of two drilling fluid formulated were increased by 16 times and 20 times, respectively, indicating that this technology is worth extensive studying.
AMPS/DMAM/FA-A Graft Copolymer Humic Acid Fluid Loss Reducer for Well Cementing
SONG Weikai, WANG Qingshun, HOU Yawei, WANG Lei, TIAN Ye, ZHAO Jun
2017, 34(1): 101-105. doi: 10.3969/j.issn.1001-5620.2017.01.019
A high temperature cement slurry fluid loss reducer, G85L, was synthesized with 2-acrylamido-2-methyl propane sulfonic acid (AMPS), N,N-dimethylacrylamide (DMAM) and fumaric acid (FA) through radical polymerization under the following conditions:AMPS:DMAM:FA=1:0.38:0.08, mass ratio of total monomers to sodium humate=1:0.2, initiation temperature 60℃, and pH (of the monomer solution)=7. G85L was a viscous black liquid containing 20% solids. Analysis of the residual monomers and IR characterization showed that the synthesized product was a graft copolymer, and thermogravimetric analysis indicted that the property of the G85L remained stable at 265℃. Filtration experiment (done in accordance with API RP 10B-2 2013) demonstrated that addition of 4%G85L reduced filter loss of cement slurry to 40 mL at low temperatures, and to less than 50 mL at 200℃. No evidences of side effect of G85L on the thickening time and compressive strength of cement slurry have been observed during experiments. G85L shows good compatibility with many cement slurry formulations and is a universal high temperature filter loss reducer for cement slurries.
Cement Sheath Integrity: Simulation and Measures for Improvement at High Temperature Deep Well Conditions
LI Ning, DU Jianbo, AI Zhengqing, GUO Xiaoyang, LIU Jian, ZHANG Kai
2017, 34(1): 106-111. doi: 10.3969/j.issn.1001-5620.2017.01.020
One of the most important purposes of cement sheath study is to establish experimental apparatus and procedure for evaluating the integrity of cement sheath. The working load of cement sheath in a wellbore can be simulated on an artificial cement sheath using equivalent stress method. With the help of core holder, downhole temperature and stress environment can be simulated. By pressurizing the artificial sheath with gas to see if there is gas channeling, the cement sheath integrity can be verified. CT scanning can be used to probe the internal structure of cement sheath, hence to bring to light the failure mechanism of cement sheath. Based on these ideas, a whole set of equipment was developed and a procedure established to evaluate the integrity of cement sheath. Simulation experiments have been carried out using the equipment and the procedure on cement sheaths found in high temperature high stress deep wells in an oilfield in west China. The results of the experiments showed that, at a certain formation pressure in high stress environment, when casing pressure was first increased to a certain level and then decreased, the cement sheath was damaged and even became failed. Once the channels for gas channeling were formed, no matter how low the pressure was inside the casing, gas bubbles can be detected. It was observed that no visible fractures were found on both ends and the side surface of the cement sheath, but the casing string that was tightly bonded with the cement sheath can now fall out freely, indicating that it was the lack of toughness of set cement that resulted in the failure of the bonding between the casing and the cement sheath, producing a micro annular space for the casing to fall. Data acquired with CT software showed that the interface pore volume of the cement sheath sample was reduced by 67.97%, the volume of the micro annular space was 3061 mm3, 9.51% of the total sheath volume, and the total volume of cement sheath was reduced by 2.21%, proving the existence of micro annular space. By modifying the material added to cement slurry, the toughness of the set cement can be improved, and a cement slurry with 0.2% carbon fiber was formulated. The method described in this paper can be used to evaluate the quality of cement sheath, and as a helpful supporting means in modifying cement slurry additives.
Analysis of High Temperature Strength Retrogression of High Water/Cement Ratio Set Cement with Silica Powder
FU Junfang
2017, 34(1): 112-115. doi: 10.3969/j.issn.1001-5620.2017.01.021
It has been found in laboratory experiment that, a low-density cement slurry of 1.65 g/cm3 (containing 40% sized silica powder) prepared by increasing water/cement ratio to 0.74, had its compressive strength reduced by 20.3%, and the strength measured by ultrasonic method reduced by 50.6% after aging for 48 hours under 185℃ and 21 MPa. This low-density cement slurry was aged for different curing periods, and the set cements obtained were analyzed for their phases and microstructure. It was concluded that the set cements obtained from high water/cement ratio slurry had large micro-pores inside them. During aging, the volume of the micropores was increasing with crystallization of the set cements, thereby leading to strength retrogression. Since micro-pores in set cement greatly affect the sonic transmission speed, the retrogression of the strength of the set cement measured by ultrasonic method is much more severe, as shown in the laboratory experiment. To mitigate the strength retrogression of set cement, a low-density cement slurry (1.65 g/cm3) was prepared by adding 25% of C-filler (a carbon powder with particle size of 0.154 mm and density of 1.35 g/cm3) and reducing water/cement ratio to 0.51. The volumetric fraction of the solid phase in the cement slurry was correspondingly increased from 32.0% to 46.0%. This cement slurry, after aging at elevated temperature, had less micro-pore left inside, and the strength of the set cement was improved.
Synthesis and Study of an AM/AA/SMA Hydrophobically Associating Polymer Used as Thickening Agent in Fracturing Fluids
ZHAO Qingmei, ZHAO Lin, MA Chao
2017, 34(1): 116-121. doi: 10.3969/j.issn.1001-5620.2017.01.022
Hydrophobically associating polymers have found wide applications in oil and gas production because of their unique rheology, high temperature stability and good shear-resistance. A hydrophobically associating polymer HAPAM has recently been synthesized in laboratory with stearyl methacrylate (SMA) as the hydrophobic monomer, and AM and AA as water soluble monomers, through micellar polymerization. The optimum conditions for the synthesis reaction were as follows:the mass ratio of the monomers was 0.3%, pH=6, the mass of SMA was 0.4% of the total mass of monomers, the mass of SDS was 30% of the mass of SMA, and the concentration of chain transfer agent (sodium formate) was 2 mg/L. Laboratory studies on the properties of HAPAM with IR spectroscopy, fluorescence, UV spectroscopy and rotary viscometer showed that HAPAM had hydrophobically association groups in its molecules, and the critical association concentration was ca. 0.5 mg/mL. HAPAM had good water solubility, thickening capacity, shearresistance, and better high temperature performance and salt-resistance than PAM synthesized at the same conditions. Crosslinking reactions of HAPAM with different chemicals showed that organic zirconium was the best crosslinking agent. It is concluded that HAPAM, as a thickening agent for use in fracturing fluids, is worth further extensive studying.
2017, 34(1): 121-121.
Guar Gum Fracturing Fluids Weighted with Formates
REN Zhanchun
2017, 34(1): 122-126. doi: 10.3969/j.issn.1001-5620.2017.01.023
In fracturing formations with higher fracture pressures, high-density fracturing fluids should be used because low-density ones have difficulties fracturing these formations. Weighting agents for use in fracturing fluids should have good water solubility because the fracturing fluids will go deep into the reservoirs. Guar gum fluids, which will crosslink in weak alkaline conditions, cannot be weighted with salts of strong acids and weak bases, such as CaCl2, ZnCl2. Bromide salts, such as potassium bromide, calcium bromide, can be used but are expensive. By balancing the cost and performance, formates were selected to weight fracturing fluids. The density of the fracturing fluid can be adjusted between 1.0 g/cm3-1.5 g/cm3. The performance of formates was affected by the factors such as electrophicility, molecular weight, and dispersity. The tendency of reaction (both chemical and physical) between cleanup additives, clay stabilizers and formates, may lead to flocculation, separation and precipitation of the fracturing fluids. To avoid these unfavorable factors, a micro emulsion cleanup fluid ME-1 and a clay stabilizer FP-2 were selected for use in the fracturing fluid formulation. An organo-boron crosslinking agent was selected through rheology, filtration and gel-breaking experiments. This fracturing fluid, with density of 1.2 g/cm3, has been successfully applied on the well Dong-8 to fracture the formation between 5,353.70 m and 5 364.45 m, with formation temperature of 120℃. The fracturing fluid, after gel breaking, had viscosity of less than 5 mPa·s, and was 100% flowed back. This weighted fracturing fluid technology has provided valuable experiences for fracturing high closure-stress reservoirs in the future.