Abstract: Difficulties in controlling the emulsion stability, rheology and filtration property of the oil based drilling fluids are often encountered in drilling deep and ultra-deep wells in which high temperatures, high pressure formations and salt-waters, thick salt and gypsum zones and shale formations are penetrated. To deal with these problems, an ultra-high temperature high density oil based drilling fluid was formulated with synthesized emulsifiers, high temperature viscosifier, flow pattern additive, wetting agent, filter loss reducer and ultra-fine barite. The emulsifiers are an imidazoline amide with tall oil aliphatic hydrocarbon group grafted with unsaturated anhydride. Laboratory evaluation of the drilling fluid demonstrated that this drilling fluid can work normally at temperatures up to 220 ℃. The density of the drilling fluid can be weighted to 2.8 g/cm3. Using compounded weighting agents significantly improved the rheology of the drilling fluid. This drilling fluid is able to resist to contamination from 40% fresh water, or 40% compound salt water, or 5% – 10% shale cuttings, or 5% – 10% gypsum. The drilling fluid had good rheological stability and suspending stability at 65 ℃/atmospheric pressure to 220 ℃/172.5 MPa. This ultra-high temperature high density oil based drilling fluid has provided a technical support to the safe and efficient development of deep and ultra-deep buried oil and gas resources.
QIU Zhengsong, ZHAO Chong, ZHANG Xianbin, et al.Study and performance evaluation of ultra-high temperature high density oil based drilling fluids[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：663-670. doi: 10.12358/j.issn.1001-5620.2021.06.001.
Abstract: Severe loss of borehole working fluids into fractured formations is one of the major technical problems encountered in oil and gas drilling engineering. Curable resin and downhole crosslinking polymers are common lost circulation materials (LCMs) used for controlling this kind of loss. However, these LCMs are difficult to control in downhole crosslinking reaction and the cured LCMs have low strengths. This paper describes PMMM, an amino resin modified through partial etherification. Using Raman spectroscopy, the molecular structure of PMMM was analyzed and the mechanism of curing of the resin revealed. The time for PMMM to cure is shortened with increase in the concentration of curing agent or time, and can be controlled in a range of 1-10 h at temperatures between 80 ℃ and 130 ℃. PMMM will not shrink after curing, and is resistant to the contamination by maximum 10% water based mud. The compressive strength of PMMM which is treated with nano CaSO4 whickers, first increases and then decreases with increase in the concentration of the CaSO4 whiskers. PMMM treated with 0.5% nano CaSO4 whiskers has a maximum compressive strength of 56 MPa after aging at 80 ℃ for 24 hours, which is higher than the same compressive strength of conventional cement LCMs. Using viscosity data gathered at temperatures between 100 ℃ and 130 ℃ and the revised Arrhenius viscosity equation, a viscosity-temperature-time equation was obtained through data fitting. Change of viscosity at 90 ℃ predicted with this equation coincides with the data measured, indicating that the fitted equation can basically be used to predict the viscosity change of PMMM when heated. All in all, the curable PMMM resin LCM has many advantages such as easy to formulate, curing condition controllable and high compressive strength after curing etc. PMMM LCMs can be a good choice in dealing with severe lost circulation.
LIU Fan, LIU Qinzheng, HAO Huijun, et al.Synthesis and evaluation of a high strength curable resin LCM PMMM[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：671-676, 683. doi: 10.12358/j.issn.1001-5620.2021.06.002.
Abstract: Molecular structure design of temperature-sensitive deformable lost circulation materials (LCMs) was conducted in an effort to find a way of overcoming the problems existed in the current LCMs which can only be used in too narrow a temperature range. Based on the technical clue of directional adsorption of LCMs on the formations via deformation of the LCMs under the influence of formation temperature, a temperature-sensitive deformable LCM named SMSHIELD-2 was successfully developed through optimized design of molecular chain, deformability and dispersibility. The SMSHIELD-2 can be used in temperatures from 100 ℃ to 150 ℃ and the temperature range in which the SMSHIELD-2 can perform effectively is gradually broadened using induced intramolecular crosslinking reaction. Molecular structure characterization and performance evaluation of SMSHIELD-2 with IR spectrometry, NMR and pressure transfer tests show that SMSHIELD-2 functions properly in a wide temperature range between 100 ℃ and 150 ℃. SMSHIELD-2 has good compatibility with other additives. It is able to effectively seal off microfractures in hard brittle shales and to improve the plugging and anti-collapse performance of drilling fluids. SMSHIELD-2 was used in drilling the complex hole section of the well X1 in Shunbei block in Xinjiang. By plugging the primary pores and micro-fractures in the formations with SMSHIELD-2, the well was successfully drilled, and two new engineering records was made.
KONG Yong.Synthesis and application of a temperature sensitive deformable plugging agent[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：677-683. doi: 10.12358/j.issn.1001-5620.2021.06.003.
Abstract: A gel microsphere lost circulation material (LCM) has been synthesized through inverse emulsion polymerization. The composition, morphology and thermal stability of the gel microspheres were characterized using electron microscope, IR spectroscopy, thermogravimetric analysis and particle size analysis. It was found in these studies that the gel microspheres are in a micron spherical structure, with their particle sizes ranging from 4.5 μm to 68 μm. The initial thermal decomposition temperature of the gel microspheres is 150 ℃. The effects of the amount of emulsifier added into the reaction, mixing of the reactants and oil/water ratio on the particle size of the gel microspheres were examined and the performance of the gel microspheres evaluated. The results of the examination showed that the reaction conditions have a great influence on the sizes of the gel microspheres; as the amount of emulsifier increases, the average diameter of the gel microspheres decreases. Proper stirring promotes the stability of the emulsion, thereby reducing the particle sizes of the gel microspheres. An increase in oil/water ratio decreases the average particle size of the gel microspheres. The LCM evaluation test results showed that the gel microspheres have a good lost circulation control effect; gel microspheres, which are produced at 4% emulsifier, oil/water ratio of 7∶3 and without stirring have average particle size of 45.1 μm, and are the best LCM.
LI Zhong, FENG Huanzhi, XING Xijin, et al.Preparation of gel microspheres for water based drilling fluids and its application in lost circulation control[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：684-690. doi: 10.12358/j.issn.1001-5620.2021.06.004.
Abstract: Soaking of rocks in drilling fluids often causes the surface morphology of the rocks to be damaged, which is probably related to the collapse of borehole walls. To reveal the relationship between the two phenomena, sandstone and shale samples were selected to test using 3D optical microscope for their surface morphology prior to and after soaking in drilling fluids at different temperatures. The characteristic parameters of the rocks were quantitatively analyzed and the effects on and damage to the surface morphology of the rocks by temperature investigated. It was found that as temperature increases, the characteristic parameters Sa, Sq and Sk also increase, while the characteristic parameter Sr decreases, resulting in increases in the roughness, discreteness and volatility of the morphologic contour of the rocks, reduction in the relief of the rocks and better symmetry of the rocks after soaking than before. In the temperature range of 30-120 ℃, the degree of morphology damage is gradually increasing with temperature, in the temperature range of 120-150 ℃, the degree of morphology damage is gradually decreasing with temperature. The Ts, which is the extreme value of the degree of morphology damage, lies between 120 ℃ and 150 ℃. Compared with sandstones, shale has a bigger relative degree of damage. Compared with the degree of damage of the rocks measured with texture characteristic parameters, degree of damage of the rocks measured with height characteristic parameters is bigger.
DENG Rong, LIU Jianping, LUO Minmin, et al.Effects of drilling fluid soaking on surface morphology of rocks at different temperatures[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：691-697, 704. doi: 10.12358/j.issn.1001-5620.2021.06.005.
Abstract: To accurately predict the annular ECD of high temperature high pressure (HTHP) wells, a model for calculating the density and rheology of drilling fluids was established through multielement nonlinear regression based on the rheological data of drilling fluids obtained under HTHP conditions. By coupling this model with the heat transfer model of wellbore, a precise prediction model for calculating the annular ECD of drilling fluids under HTHP conditions was established. Compared with the results obtained using the Drillbench software, this model gives results that are closer to the measured PWD data. Results from the model using actual operation data showed that during drilling operation, as the temperatures in the lower part of the annulus are continuously decreasing, the density and consistency index of the drilling fluid are continuously increasing, resulting in continuous increase in the annulus ECD. The flow rate of drilling fluid and the geothermal gradient are two key factors affecting annular ECD; the higher the flow rate, the higher the annular pressure losses, and hence the higher the annular ECD. Geothermal gradient directly affects the distribution of temperatures in the annulus, and increase in the geothermal gradient results in continuous decrease in annular ECD.
ZHANG Geng, LI Jun, LIU Gonghui, et al.A precise model for prediction of annular ECD in offshore HTHP wells[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：698-704. doi: 10.12358/j.issn.1001-5620.2021.06.006.
Abstract: The Chang 7 shale oil reservoir is tight but has good fluid fluidity, which has micron-scale pores and fracture structure, leading to frequent permeable loss, fractured loss and total loss during the drilling process. Conventional plugging materials cannot meet the drilling construction requirements, resulting in a significant increase in non-production time and costs, and severely restricting the exploration and development process. Based on the theory of supramolecular chemistry, this research developed a new type of supramolecular polymer plugging material through synthesis formula optimization, and characterized and tested its microstructure, shear thinning and loss mitigation and pressure-bearing plugging ability. The research results show that the supramolecular gel plugging material not only has excellent shear thinning properties and adherence abilities, but also has a strong pressure-bearing plugging effect in large pore loss zones simulated by two-layer steel ball beds (the steel ball diameters are 8 mm ～ 10 mm) and fractured loss zones simulated by longitudinal slotted plate (the fracture widths are 2 mm～6 mm), with a pressure-bearing capacity up to 6MPa. Its application of typical total loss well in Chang 7 shale oil block shows that supramolecular gel plugging technology can effectively improve the pressure-bearing capacity of fractured loss zones reducing loss volume and comprehensive plugging costs, and helps Chang 7 shale oil exploration and development. Thus, it is worthy of further research and promotion.
AI Lei, GONG Chenxing, XIE Jiangfeng, et al.Application of supramolecular polymer plugging technology in changqing oilfield[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：705-714. doi: 10.12358/j.issn.1001-5620.2021.06.007.
Abstract: Multinucleated amorphous microcapsule can be made by wrapping shell powders with a gel polymer. This gel polymer was developed through polymerization, with acrylic acid (AA), acrylamide (AM), 2-acrylamide-2-methyl propanesulfonic acid (AMPS), N-vinylpyrrolidone (NVP) as the polymeric monomers, N,N-methylene-bisacrylamide (MBA) as the crosslinking agent, dodecyl methacrylate (DM) as the functional monomer, and ammonium persulfate-sodium bisulfite as the redox initiator. Laboratory studies showed that the gel polymer has the optimum performance at a mass ratio of AA∶AM = 1∶3. The multinucleated amorphous microcapsule plugging agent has good self-adaptive performance and excellent plugging capacity. It has minor effect on the rheology of the drilling fluid, and is resistant to high temperatures and salt contamination. After aging at 180 ℃ for 16 hours, the structure of the plugging agent still remains intact, and the API filter loss is 11.4 mL. Test of the plugging agent in an environmentally friendly mud system after aging at 150 ℃ for 16 hours showed that the invasion depth of filtrate into the medium pressure sand-bed was 28.74% of the whole thickness. The plugging agent with particle sizes distributed between 30 mesh and 50 mesh can be used to plug simulated fractures of 0.5 mm (width) × 5 mm (depth), and can withstand pressures up to 4 MPa.
YU Wenke, LIN Ling, LUO Yunxiang, et al.A self-adaptive shell powder plugging agent[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：715-720. doi: 10.12358/j.issn.1001-5620.2021.06.008.
Abstract: A high temperature stiff foam drilling fluid was formulated on the basis of analyzing the factors affecting the stability of micro foam at elevated temperatures. This drilling fluid has strengthened plugging capacity. A high temperature low molecular weight foam stabilizer was used to form a rigid structural film at the interface of the foams. A wetting agent was used to improve the wettability and osmosis of the foam surfaces, thereby mitigating the evaporation of the micro foams at elevated temperatures. Meanwhile an optimized high temperature filter loss reducer and a low density plugging agent were used to strengthen the pressure bearing and plugging capacities of the micro foam drilling fluid. The density of the stiff micro foam drilling fluid can be adjusted between 0.6 g/cm3 and 1.0 g/cm3. The micro foam drilling fluid has a stable rheology. The half-life of the foam is at least 45 h at room temperatures, at least 35 h at 150 ℃, and at least 120 h at elevated temperatures after optimization of the formulation of the foam, all indicating that the micro foam has excellent stability. The plugging belt formed by this stiff foam is stable; in HTHP sand bed test, the invasion depth of the filtrate was reduced by 82.1%, and the invasion depth of drilling fluid was reduced by 73.8%. The micro foam is able to resist contamination by at least 15% crude oil. No special equipment is required in field application of the micro foam, and it is suitable for use in controlling mud losses in high temperature deep wells penetrating low pressure formations in which mud losses are prevailing. It can be long circulated between the surface and the borehole, and help stabilize the borehole walls. Using this stiff micro foam, drilling fluid costs both on materials and equipment are saved, and borehole walls stabilized.
YANG Qianyun, WANG Baotian, ZHANG Gaofeng, et al.Formulation of high temperature stiff micro foam drilling fluid with strengthened plugging capacity[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：721-727. doi: 10.12358/j.issn.1001-5620.2021.06.009.
Abstract: A new organic-inorganic compound gel plugging agent called CGPLUG was developed by adding sodium bentonite, sodium silicate, aluminum hydroxide, calcium oxide, magnesium hydroxide, ore powder, expansion agent, etc., and xanthan gum, konjac gum as Tackifier borax as cross-linking agent, and add with barite density adjustment. CGPLUG possesses good rheological properties at room temperature, especially excellente shear dilution and thixotropy, which is conducive to stay in the drilling loss channel. It can "stop" and is suitable for plugging different drilling loss channel. The gel strength of CGPLUG can reach more than 5000 g/cm2 at 80～200 ℃ temperatures, and the temperature resistance can reach 240 ℃ .CGPLUG has good plugging effect for quartz sand beds of different particle sizes (4～10 mesh, 10～20 mesh, 20～40 mesh) is good, and the Bearing Strength can reach more than 8.0 MPa.
BA Wenxuan, WANG Zhengliang, WANG Changjun.Study on high temperature resistant compound gel plugging agent[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：728-731. doi: 10.12358/j.issn.1001-5620.2021.06.010.
Abstract: Two organophilic clay samples (1# and 2#) were taken to study the factors affecting the colloid fraction of the clays. Factors studied include type of base oil, type and concentration of polar solvent (activator), shear rate and time of shearing. It was found that the colloid fraction (expressed as percentage) of organophilic clay 1# was 100% in 0# diesel oil, and 20% in 5# diesel oil. When different polar solvents were added to the 5# diesel oil, the colloid fraction can be increased to 100%. The colloid fractions of the organophilic clay 2# in the 0#, 3# and 5# diesels were all less than 10%. After adding polar solvent in the three diesel oils, the colloid fractions of the organophilic clay in the three diesel oils were increased at different levels. When the stirring speed of the agitator was increased from 3000 r/min to 13,000 r/min, the colloid fractions of the organophilic clays were increased from 18% to 29%. When the time of shearing was increased from 5 min to 40 min, the colloid fractions of the organophilic clays were increased from 22% to 40%. Analysis of the experimental data has revealed the mechanism on which how activator affects the colloid fraction of organophilic clays. It is suggested in this paper that the conditions under which the colloid fraction test is performed should be specified, for example, the time of shearing, stirring speed and temperature etc. These factors also affect the colloid fraction of the organophilic clay.
YANG Xin, HU Ya’nan, YAO Rugang, et al.Factors affecting colloid fraction of organophilic clay used in oil based drilling fluids[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：732-737. doi: 10.12358/j.issn.1001-5620.2021.06.011.
Abstract: The high temperature and high pressure oil-based drilling fluid emulsion stability evaluation instrument is mainly composed of high temperature and high pressure stainless steel chamber, test electrode, temperature control system, pressure control system and test system. The high temperature electrode is made of PEEK material. The test electrode distance is designed to be 1.55 mm. The maximum discharge voltage is designed to be 2000 V, and the voltage change rate is 150±10V persecond. The temperature control system is based on the T89C51 single-chip microcomputer. The cast aluminum electric heater is used to wrap the outside of the test vessel for heating. The pressure control system uses hydraulic pressure. The stability test of the instrument and the comparison test with the electrical stability tester under normal temperature and pressure are carried out. The results show that the instrument can realize the evaluation of the emulsion stability of oil-based drilling fluid at high temperature and high pressure, and the test data is stable and reliable, with measurement errors ≤5%. The emulsification stability of oil-based drilling fluid under high temperature and high pressure conditions is studied. When the pressure is kept constant, the demulsification voltage decreases with the increase of temperature. When the temperature is below 120 ℃, the demulsification voltage decreases with the increase of pressure. When the temperature reaches above 120 ℃, the demulsification voltage does not change with the pressure.
LONG Huaiyuan, CHEN Wu, LIU Gang, et al.Research on evaluation device and method of emulsification stability of high temperature and high pressure oil-based drilling fluid[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：738-742. doi: 10.12358/j.issn.1001-5620.2021.06.012.
Abstract: Osmotic hydration of shale is one of the important factors for borehole wall instability. Based on the activity equilibrium theory of drilling, a new idea of “moderate reduction of the activity of drilling fluid” has been presented. In this paper, the theoretical basis of this idea is analyzed. The idea was verified in laboratory through hydration and disintegration experiments, and as a result of the research work, a new method of determining the activity of the drilling fluids was established. It was found in the laboratory experiment that a cylindrical core can still retain its stability when the activity of the drilling fluid is moderately higher than the activity of the water in the core. The “moderate reduction of the activity of the drilling fluid” technology has been applied in the drilling operation in several blocks in Jiyang Depression, and it was found that “moderate reduction of activity” can be used to solve the borehole wall destabilization problem which is a result of collapse and caving of shale formations in these blocks. The wells were successfully drilled and completed, and downhole troubles were avoided, greatly saving the drilling time and drilling cost.
LI Gongrang, YU Lei, WANG Zhiwei, et al.New understanding about technology of balanced drilling fluid activity and its field application[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：743-747. doi: 10.12358/j.issn.1001-5620.2021.06.013.
Abstract: A 3D flower-shaped BiOBr photocatalytic material has been produced through hydrolysis reaction at room temperature to deal with the deficiencies in the harmless disposal of various waste water based polymer muds. The composition, morphology and optical performance of BiOBr were characterized. The photocatalytic activity under visible light was examined using Rhodamine B (RhB) as the target degradant, and the BiOBr was for the first time used in the degradation of water based polymer muds. Laboratory study showed that BiOBr can be excited under visible light; the rate of degradation of RhB in 10 min can be as high as 58.3%. BiOBr also has good effect on the degradation of water based polymer muds. It was proved, through capture of active species, that BiOBr degrades polymers by producing active O2− and H+ ions. This study has provided a new clue for the degradation of waste water based polymer muds.
DONG Tengfei, JIANG Guancheng, LI Yizheng, et al.Biobr photocatalyzed polymer water based drilling fluid[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：748-753. doi: 10.12358/j.issn.1001-5620.2021.06.014.
Abstract: In field operations, the set cement with sand in downhole conditions will experience huff-n-puff and steam flooding, followed by transitional stage and fire flooding. To accurately understand the high temperature resistance of the set cement with sand, NMR, XRD and SEM were used to investigate the porosity, permeability, chemical structure and microstructure of the hydration products of the set cement with sand under cumulative working conditions. Laboratory experimental results demonstrated that after curing at room temperature for 14 d, the compressive strength of set cement was 31.8 MPa, which is 90.86% of the compressive strength of the set cement after curing in the same conditions for 28 d. Meanwhile, this set cement had low porosity and low permeability. After fire flooding, the compressive strength of the set cement was reduced by 67.92%, and the porosity and permeability of the set cement were both increased by 53.85% and 77.31% respectively, apparently unable to satisfy the needs of heavy oil production. The reason for the decrease in compressive strength and increase in porosity and permeability of the set cement is that at high temperatures, part of the hydrated calcium silicate with “network” structure or “chain” structure in the set cement is converted into “granular” wollastonite, thereby resulting in increased porosity and permeability and decreased compressive strength of the set cement. Meanwhile, de-hydroxylation of Ca(OH)2 produces CaO and plenty of big pores and cracks, failing the materials which are beneficial for the set cement to maintain its mechanical performance.
XU Xinli.High temperature resistance of conventional set sand cement under cumulative working conditions[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：754-759. doi: 10.12358/j.issn.1001-5620.2021.06.015.
Abstract: Experiment on the gas channeling in different setting states of cement slurry was designed and conducted to deal with gas channeling. In the experiment, the gas channeling was observed, the gas channeling pressure measured, the form and path of gas channeling analyzed, and the pattern of gas channeling studied. The study results have shown that when the cement slurry sets in a short time (120 min and 180 min), the gas channeling pressure is low (<0.05 MPa), the gas channels slowly through the interior of the cement slurry, and the diameter of the channel is small but increases from the bottom to the top of the cement column. When the cement slurry sets in a longer time, say, 200 min and 220 min, the gas channeling pressure is increased to 0.15 MPa and 0.20 MPa, the gas channels abruptly in a high flow rate through the interior of the cement slurry, and the channel is in a shape of “serial bubbles” and “fractures” with big sizes. When the cement slurry sets in 240 min, the gas channeling pressure is increased to 0.22 MPa, and the gas can no longer channel through the interior of the cement slurry, it can only channel through the interface between the cement slurry and the borehole wall. It is thus recommended that anti-channeling measures should be designed in according with different setting states of the cement slurry.
HAN Jinliang, GUO Xinyang, SONG Yuyuan , et al.Gas channeling experiment of cement slurry in different solidification state[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：760-764. doi: 10.12358/j.issn.1001-5620.2021.06.016.
Abstract: High pressure natural gas well cementing in the piedmont structure in Kuche, Tarim Basin has encountered problems such as coexistence of well kick and mud losses in the salt-gypsum stratum, and narrow safe drilling windows etc. To deal with these problems, some functional monomers were selected and used to produce a fluid loss additive FL-A with high temperature tolerance, salt resistance and good dispersibility. IR analysis showed that the monomers all took part in the polymerization reaction. Thermogravimetric analysis showed that FL-A has good thermal stability; it functions normally at 300 ℃. In laboratory evaluation, cement slurries treated with FL-A has good filtration control capacity, and can be used in salt-saturated cement slurries. FL-A has good compatibility with other additives and normal thickening curve. Several cement slurries, with their densities between 2.3 g/cm3 and 2.6 g/cm3, were formulated with saturated saltwater and treated with FL-A. These cement slurries have low liquid/solid ratios, low filtration rate, good settling stability, excellent rheology and fast-developing strengths. They have been used more than 10 times in cementing wells penetrating salt-gypsum stratum, the job quality was satisfactory and the high pressure formation saltwater was effectively isolated.
ZOU Shuang, XIONG Yudan, ZHANG Tianyi, et al.Study and application of fluid loss additive used in cement slurries for cementing salt-gypsum stratum[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：765-770. doi: 10.12358/j.issn.1001-5620.2021.06.017.
Abstract: The south rim of the Junggar Basin is a key block for reserve increase of the Xinjiang oilfield. Wells drilled in this area are 6,000-8,000 m in depth, the bottom hole temperature and pressure of which are 160 ℃ and 170 MPa respectively, typical “three high” wells. Studies were conducted on the basic properties of the high temperature high pressure and ultra-high density cement slurries used in this area as well as the mechanical performance of the ultra-high density set cement under high temperature high pressure. In general laboratory studies, the strength development of a cement slurry is always quite different than the strength development of the same cement slurry in field operation. To understand the causes for this phenomenon, set cement test samples made from the typical cement slurry compositions used in this area were tested at 120 ℃ and 160 ℃, respectively under simulated actual downhole pressures and the pressure specified in the standard GB/T 19139—2012, which is 20.7 MPa. The tests include compressive strength test, flexural strength test and uniaxial compression test at room temperatures and triaxial compression test at actual downhole temperatures. Through these tests, the effects of pressure on the compressive strength and flexural strength of ultra-high density set cement, as well as the mechanical characteristics (deformation, failure mode etc.) of the set cement samples were investigated. The test results showed that pressure is one of the key factors affecting the development of the early strength of ultra-high density set cement. As the curing pressure increases, the compressive strengths of the top and bottom of the set cement were increased by 61.53% and 120%, respectively, the flexural strength of the top and bottom of the set cement were increased by 65.2% and 62.8%, respectively. Set cement tested in uniaxial compressive test at room temperatures showed obvious brittleness. After curing under 20.7 MPa, the ends of the set cement samples were obviously damaged. As the curing pressure was increased, the peak stress and elastic modulus were both increased, and the ability of the set cement samples to resist deformation failure was improved. High temperature triaxial compression test results showed that all mechanical parameters of ultra-high density set cement were greatly increased compared with the mechanical parameters obtained in uniaxial compression test, and the deformation of the set cement was mainly in a form of axial compression deformation, no obvious macro cracks were ever developed in the set cement, indicating that the set cement performed very well in resisting deformation failure, and was more like a linear-elastic – ideal plastic material. It is suggested that in laboratory examination and simulation experiment, the effects of actual downhole conditions on the mechanical performance of set cement be taken into account.
SONG He, YANG Wei, TANG Junfeng, et al.Mechanical performance of high density set cement for hthp applications[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：771-777. doi: 10.12358/j.issn.1001-5620.2021.06.018.
Abstract: In order to meet the needs of instant prepared process and solve the problem of viscosity of high density isolating fluid, an integrated treatment agent DQ-SA for spacer was developed, which is mainly composed of surfactant modified biological glue. The weak hydrogen bond of biological glue molecules is broken and the surfactant micelles are arranged directionally when stressed, The base solution of spacer prepared with DQ-SA has obvious shear dilution characteristics. The viscosity of Markovian funnel is only 31s and shows excellent flow performance. At the same time, the simulation experiment of instant prepared is carried out with indoor equipment, the mixing capacity of cementing truck is concluded, and the specific parameters of indoor simulating equipment are determined． Through the laboratory experiment, the balance between the fluidity and stability of the spacer was achieved, and the optimum dosage of the integrated agent was determined. By controlling the proportion of weighting agent, the density of the spacer can be adjusted in a wide range up to 2.40 g/cm3. The evaluation shows that instant prepared spacer has good fluidity, stability, compatibility and temperature resistance. The ground and field tests show that the instant prepared process is easy to operate, the spacer prepared is excellent, and the problems of high density isolating liquid are well solved.
CHEN Debao, KANG Jufeng.An instantly prepared cementing spacer of high density[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：778-781. doi: 10.12358/j.issn.1001-5620.2021.06.019.
Abstract: To optimize the techniques and operational parameters of well fracturing with supercritical CO2 fracturing fluid, a mathematical model coupling the pressure drawdown and heat transfer of a well fractured with CO2 fracturing fluid is established based on the physical properties of CO2, taking into account the mutual influence and interaction between the changes in temperature and pressure of the well and the properties of CO2. The accuracy of the model is verified with data collected from field fracturing operations. Using this model, the effect of coupled temperature and pressure is calculated, and heat transfer pattern in the wellbore analyzed. Laboratory studies have shown that the temperature distribution inside the tubing is significantly lower than the in-situ formation temperature at different flow rates of the fracturing fluid. With the increase in flow rate, the wellbore temperature is first decreasing and then increasing. The bottomhole temperature is increasing with the increase in the temperature of the injected fluid, and the change in the bottomhole temperature becomes more significant with the temperature of the injected fluid at higher flow rates. Increase in the wellhead pressure has little, if any, influence on the bottomhole temperature, and its effect can be ignored in engineering calculations. The bottom hole temperature is always decreasing with time at different flow rates, and the amplitude of this temperature decrease is gradually decreasing with time. The tubing temperature can be significantly reduced if drag reducer is added into the fracturing fluid. At any flow rate, the changes in the wellbore temperatures are becoming smaller in a wellbore fractured with a fracturing fluid containing drag reducers. This research has important guiding significance to CO2 fracturing design optimization and field operations.
GUO Xing, SUN Xiao, MU Jingfu, et al.Heat transfer in wellbores fractured with supercritical CO2 fracturing fluid[J]. Drilling Fluid & Completion Fluid，2021, 38（6）：782-789. doi: 10.12358/j.issn.1001-5620.2021.06.020.
Abstract: To improve the movement of sand carrying guar gum fracturing fluids in fracturing operation, a nanometer ZrO2 crosslinking agent TCL was developed using nanometer ZrO2 and 3,5-dihydroxy pentanoic acid. The effects of the concentrations of TCL, guar gum, 3,5- dihydroxy pentanoic acid and proppant on the static suspending stability of particles were investigated. It was found that after shearing at 180 °C and 190 s−1 for 80 min, the mass of particles settled in a fracturing fluid treated with 0.4% TCL and 0.3% guar gum can be limited to 0.3 g, much less than the 2.6 g particles settled in a fracturing fluid treated with the commercially available ZAB crosslinking agent. Higher treatment of the crosslinking agent TCL and guar gum as well as higher density hydroxide groups on the side chain of the crosslinking agent are all beneficial to the suspending capacity of the fracturing fluid, while the amount of the 3,5- dihydroxy pentanoic acid greater than 38 g does not have a great impact on the sand suspension of the fracturing fluid. The content of TCL in a fracturing fluid has the greatest impact on the suspension of the proppant particles in that fracturing fluid, reducing the mass of the settled sands by 6.6 g, indicating that TCL has excellent sand suspension capacity.
PU Jun, HUANG Ting, LI Jianhui, et al.Preparation of crosslinking agent for guar gum fracturing fluids and study on its performance in statically suspending sands [J]. Drilling Fluid & Completion Fluid，2021, 38（6）：790-794. doi: 10.12358/j.issn.1001-5620.2021.06.021.
Competent Authorities：China National Petroleum Corporation Ltd
Sponsored by：CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
Address： Editorial Department of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province