Abstract: The rheology of an oil based drilling fluid is a key factor affecting the downhole safety and penetration rate of a well. Oil based drilling fluids generally have lower gel strengths and yield point, resulting in poor sand carrying and suspending capacity of the muds. This paper describes several problems encountered in the development of gel strength additives for oil based muds, such as the difficulties in controlling the plastic viscosity, poor applicability, and poor thermal stability of the products. The research status-quo of oil based mud gel strength additives, such as organophilic clays, fatty acid amides, oil-soluble polymers as well as nanophase compound materials is systematically summarized. It is elaborated in detail that the gel strength additives for oil based muds function through hydrogen bond, coordination bond and molecular association. It is presented in this paper that to overcome the problems encountered in the development of gel strength additives for oil based muds, star polymers, dendrimers, organophilic clay modified with long-chain quaternary ammonium, as well as nanophase materials can be used to develop new gel strength additives for oil based muds.
HUANG Ning, LYU Kaihe, SUN Jinsheng, et al.Research status-quo and development trend of gel strength additives for oil based drilling fluids[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：397-405. doi: 10.12358/j.issn.1001-5620.2022.04.001.
Abstract: High temperature high pressure (HTHP) filtration rate as one of the important properties of a drilling fluid plays a key role in the safety and stability of downhole conditions. It is worthwhile to find an effective and reasonable way to reduce the HTHP filtration rate of a drilling fluid to less than 8 mL. Based on the inquiry and analysis of the papers published in recent years on low HTHP filtration rate drilling fluid systems, an idea of reducing the HTHP filtration rate of drilling fluids is presented. This paper also analyzes the status quo of the high temperature filter loss reducers and plugging agents, and discusses the methods of controlling low HTHP filtration rate, which include the study on the working mechanisms and compatibility of HTHP filter loss reduces and plugging agents for the purpose of using as less and efficient as possible additives to reduce mud cost and workloads. By reasonably using SMP, lignite additives, sulfonated asphalt, SPX resin or polymers whose molecules contain AMPS groups, the HTHP filtration rate of a drilling fluid can be effectively brought under control.
ZHANG Gaobo, LI Peihai, QIAO Han, et al.Methods of controlling low HTHP filtration rate of water based drilling fluids[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：406-414. doi: 10.12358/j.issn.1001-5620.2022.04.002.
Abstract: Large amount of montmorillonite is generally encountered when drilling in salt/gypsum-containing or shale formations. Montmorillonite, as a typical easily hydrated and swelling clay, when in contact with filtrates from water based drilling fluids, will cause borehole wall instability, stuck pipe, tight hole and borehole collapse etc. Formate water based drilling fluid containing potassium formate, a strongly inhibitive additive, is becoming an important water based mud for drilling complex formations. In laboratory studies, a molecular dynamics method was adopted to further reveal, from the molecular point of view, the mechanisms of potassium formate to inhibit the hydration of montmorillonite. The interaction of potassium formate and montmorillonite was calculated by establishing the models of the two. It was found from the studies that the ionized formate in the potassium formate solution mainly interacts with water molecules existed in between the montmorillonite layers and can form hydrogen bonds with the water molecules. The ionized potassium, on the other hand, is adsorbed on the surfaces of the montmorillonite particles, thereby reducing the zeta-potential of the montmorillonite particles by reacting with the surfaces of the particles. At a concentration that is above a certain level, the number of potassium ions adsorbed onto the surfaces of the montmorillonite particles reaches saturation, and the redundant potassium ions begin to diffuse into the spaces between two montmorillonite layers. Simulation experiments showed that low concentration potassium formate solution is beneficial to stabilizing the mechanical property of montmorillonite; as the concentration of potassium formate increases, it inhibits the diffusion of water molecules, and the mechanical property of the montmorillonite is deteriorated to some extent. When the concentration exceeds a certain level, the inhibitive capacity of potassium formate becomes stabilized, so does the mechanical property of the montmorillonite. The simulation results show that the optimum concentration of potassium formate in water based drilling fluids is 32.57% – 34.92%.
LIU Xingyu, MA Chao, XIE Longlong, et al.Molecular dynamics simulation of potassium formate’s ability to inhibit hydration of montmorillonite[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：415-422. doi: 10.12358/j.issn.1001-5620.2022.04.003.
Abstract: The conventional plugging slurry is easy to be diluted、replaced or washed away by formation water, so plugging in containing water formation is a worldwide problem. Therefore, a concentration responsive water thixotropic plugging agent has been developed, which including concentration responsive treatment agent SMF and solubilizer SMZ. The solution of water thixotropic agent has good fluidity, has a certain limition for the mixed water, and can still maintain good rheology and stability within the tolerance limition. However, when the water exceeds the tolerance limition, SMF will change to three dimensional network structure semisolid gels which has certain hardness、viscosity by self polymerize. Concentration response range and Limition of water can be adjusted by adjusting the ratio and dosage of SMF and SMZ, and a new water thixotropic plugging technology is developed. The water thixotropic bridging plugging slurry can be retained under flowing water, and the adhesion of the retained material in water reaches 1.166 MPa. Water thixotropic consolidation plugging slurry is not diluted by formation water and can be solidified in water. The plugging technology has applicated in SHB5-15H well,and successfully blocks the water bearing leakage layer. The plugging technology is simple preparated, and has good safety and strong underwater retention capacity. It provides a convenient、safe and efficient new plugging technology to solve the plugging problem of water bearing leakage layer, and has a good application prospect.
ZHAO Suli.Study on concentration responsive water thixotropic material and plugging technology of water bearing leakage layer[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：423-429. doi: 10.12358/j.issn.1001-5620.2022.04.004.
Abstract: A compound borehole wall strengthening agent WSC-1 was developed to deal with the borehole wall instability frequently encountered in shale oil development with water based drilling fluids. The WSC-1 additive was synthesized through esterification reaction with a zwitterionic polymer AM-AA-DMDAAC (acrylamide-acrylic acid-dimethyl diallyl ammonium chloride) and polyvinyl alcohol. WSC-1 possesses cationic groups and poly hydroxy groups which make it easy for the WSC-1 to be adsorbed onto the surfaces of the borehole walls. In laboratory evaluation, the point load strength of an artificial core was increased by 26.90% with the help of WSC-1, and the cohesion of the core after soaking was maintained at 71.3%. The linear expansion of shale cores can be reduced by 63.22% tested with a 3% WSC-1 solution. In hot rolling test, the percent recovery of shale cuttings after hot rolling at 150 ℃ was 87.2%, a recovery higher than the results tested with commonly used borehole wall stabilizers such as polyetheramine and polyglycol. WSC-1 also showed some filtration control capacity in the test. Using IR and SEM analyses, it was found that WSC-1 can be adsorbed on the surfaces of the rocks through ionic bonding and hydrogen bonding, thereby inhibiting the hydration and dispersion of clay minerals. WSC-1 can also form an adsorption film through the “multi-point adsorption” of the polyvinyl alcohol, the film can seal off the fractures in the formation rocks, thus minimizing the filtration of free water into the formation and strengthening the borehole walls.
JING Minjia, YUAN Zhiping, WANG Xingyuan, et al.The development and function mechanisms of an zwitterionic polymer/polyol borehole wall strengthening additive[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：430-434. doi: 10.12358/j.issn.1001-5620.2022.04.005.
Abstract: A comb polymer filter loss reducer, WA-1, was synthesized with different monomers in a specific ratio. Comparative experiments were designed, and the optimum reaction program selected for the synthesis reaction. Monomers used in the synthesis of WA-1 included 2-acrylamido-2-methylpropanesulfonic acid (AMPS), dimethyl diallyl ammonium chloride (DMDAAC), N-vinyl pyrrolidone (NVP) and N, N-dimethyl acrylamide (DMAA) in a mass ratio of AMPS∶DMDAAC∶NVP∶DMAA = 5∶3∶1∶1. The total concentration of the monomers was 19.8%. Potassium persulphate of 2‰ was used as the reaction initiator. The monomers were allowed to react for 5 hours at 60 ℃ and pH of 7. Evaluation of the final product has shown that WA-1 can be used at temperatures up to 180 ℃. Drilling fluids treated with WA-1 have good rheology, filtration property and calcium contamination resistance. In laboratory experiment, a base mud containing 2%CaCl2 was treated with 2%WA-1. The mud was aged at 180 ℃ for 16 hours and then tested. The API filtration rate of the mud was 11.2 mL, which was less than the filtration rate of the mud treated with linear polymers. Infrared spectroscopy characterization, thermogravimetric analysis, Zeta-potential measurement and particle size distribution analysis of drilling fluids treated with WA-1 have shown that, as a comb polymer filter loss reducer, WA-1 is able to resist the adverse effects of high temperature and high calcium, and to improve the stability of drilling fluids.
ZHANG Wandong, WANG Aijia, GUO Hao, et al.Development and application of comb-like polymer filter loss reducer with high temperature and high calcium contamination resistance[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：435-440. doi: 10.12358/j.issn.1001-5620.2022.04.006.
Abstract: In order to improve the anti-viscosity and environmental performance of the extractant used for water-based drilling fluid, LVHY-1 was synthesized by using low viscosity anionic cellulose sodium salt (PAC-LV) and hexadecyl isocyanate as raw materials, and dibutyltin dilaurate (DBTDL) as catalyst. The optimum synthesis conditions were determined by orthogonal experiment: mass ratio of PAC-LV to cetyl isocyanate 4:1, reaction temperature 60 ℃, reaction time 12 h, DBTDL concentration 0.4%. The molecular structure was characterized by 1H-NMR. Rheological property test results showed that the dynamic plastic ratio (RYP) increased with the increase of LVHY-1 after hot aging test at 120 ℃. After hot aging at 170 ℃ for 16 h, the RYP of 0.2% LVHY-1 drilling fluid still reached 0.5 Pa/mPa·s, and kept good effect after hot aging for 64 h, showing excellent temperature and weather resistance. Transmission electron microscopy (TEM) observation showed that LVHY-1 could form a three-dimensional network structure in solution, which was the reason for the effect of LVHY-1. The test structure of environmental performance showed that the semi-maximum effective concentration (EC50) of LVHY-1 was 30 100 mg/L, and the biodegradability evaluation index (Y) was 18.25, which met the emission standard and was easy to be degraded by microorganisms.
CUI Peng, YANG Zhishu, MA Shuangzheng.Synthesis and properties of high temperature resistant environmental protection shear strength improving agent[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：441-445. doi: 10.12358/j.issn.1001-5620.2022.04.007.
Abstract: Mechanisms of loss of oil based drilling fluids were analyzed taking the shale oil development in the Jiyang Depression as an example to solve the frequent occurrence of mud losses in shale oil development. The analytical results have shown that natural fractures are highly developed in shale oil reservoir formations, and this is one reason why the mud is easy to lose in shale oil drilling. The shales drilled are very brittle, and their surfaces are oil wet, pressure losses in long horizontal sections are therefore high, resulting in induced fractures into which the mud is lost. Lost circulation materials (LCM) in oil based drilling fluids have low friction coefficients, making it difficult to control the mud losses. Based on the studies on the mechanisms of mud losses occurred in shale oil drilling, a one-bag lost circulation material made from a surface-modified elastic mesh material and an optimized filling material. Laboratory long-fracture sealing and plugging experiment and field application have shown that the one-bag LCM has good sealing and plugging capacity; fractures of 2 mm × 1 mm has pressure bearing capacity of 10 MPa after being plugged with the LCM. Mud losses in field operations were brought under control in the first try of the LCM. The application of the one-bag LCM helped solve the losses of oil based drilling fluids in shale oil drilling, providing a technical support to the safe and fast drilling in shale oil reservoirs.
LI Ke, JIA Jianghong, YU Lei, et al.Mechanisms of lost circulation and technologies for mud loss prevention and control in shale oil drilling[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：446-450. doi: 10.12358/j.issn.1001-5620.2022.04.008.
Abstract: Whole rock mineral analysis, clay mineral analysis and microstructure analysis of rock have been performed on rock samples taken from different formations to find the root causes of borehole wall instability encountered in the Fukang sag block. The analyses results indicated that it is the high content of kaolinite and large amount of micro pores and fractures developed in the formations that cause the borehole wall to loss its stability. Base on these borehole wall instability mechanisms, the oil based drilling fluid used to drill the well F49 was selected to determine the direction of mud property optimization. FD-FK, an amphiphilic polyacrylic acid resin, was synthesized as a cementitious plugging agent, and TQ-FK, a poly fatty acid was developed as a gelling agent, were developed for use in oil based drilling fluids. The oil based drilling fluid used in drilling the well F49, after treatment with FD-FK and TQ-FK, had its low-shear-rate viscosity and YP/PV ratio greatly increased, and the sizes of fractures that can be plugged by the drilling fluid were increased from 2～90 μm to 2～380 μm. The plugged fractures had pressure bearing capacity increased to 8 MPa, indicating that the oil based drilling fluid had good plugging capacity. The 3rd interval of the well Fu-47 was drilled with the oil based drilling fluid optimized with FD-FK and TQ-FK, the average percent hole enlargement of the problematic sections was only 3.35%. The application of this optimized oil based drilling fluid has provided a effective technical support to the safe and efficient drilling operation in the Fukang sag.
LIU Kecheng, ZHOU Jun, CUI Xin, et al.Mechanisms of borehole wall instability in Fukang sag block and an oil based drilling fluid with plugging and inhibitive capacities[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：451-458. doi: 10.12358/j.issn.1001-5620.2022.04.009.
Abstract: Polymer-sulfonate drilling fluids, which have good resistance to high temperatures, are generally used to drill deep and ultra-deep wells. Chemicals used in these drilling fluids, such as sulfonated lignite and sulfonated methyl phenolic resin, have biotoxicity and poor degradability, resulting in difficulties in the disposal of the polymer sulfonate drilling fluids and high cost. In a laboratory study an applicable evaluation practice for testing the environmental friendliness of drilling fluids was recommended for testing the effects of polymer sulfonate drilling fluids and the main additives on the protection of environment. A new non-sulfonate drilling fluid with a balance between the functionality of the drilling fluid and environment protection was developed. This drilling fluid, with low friction coefficient, was successfully used in drilling the well TK4120 in Tahe block. Polymer sulfonate drilling fluids used in this block have moderate toxicity, poor degradability, and the contents of some heavy metals exceed the national standards. These problems come from the poor biodegradability and toxicity of the sulfonates and the crude oil used. Compared with the polymer sulfonate drilling fluids, the non-sulfonate drilling fluid developed has strong inhibitive capacity, plugging capacity and the ability to prevent the borehole wall from collapsing. It is nontoxic, easy to biologically degrade and environmentally friendly. Field application of this non-sulfonate drilling fluid indicated that this drilling fluid had stable property, good high-temperature resistance, strong ability to prevent borehole wall from collapsing, and good lubricity. The average rate of hole enlargement in the easy-to-collapse formations was only 4.39%. Wireline logging and running casing into a long open hole of 4,209 m were done successfully in the first try.
WANG Weiji, GAO Wei, FAN Sheng, et al.The development and application of a new environmentally friendly low friction non-sulfonate drilling fluid[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：459-465. doi: 10.12358/j.issn.1001-5620.2022.04.010.
Abstract: Silica flour is commonly used in oil well cement to prevent the strength retrogression of hardened cement paste at high temperature and high pressure. In this study, a class G cement slurry was mixed with 35% silica flour of different sizes and cured at high temperature and high pressure (240 ℃ and 21 MPa) for 180 d to study the effects of the silica flour particle size on the high temperature mechanical properties of the hardened cement paste. The compressive strength and permeability of the hardened cement paste containing silica flour of different particle sizes were measured, and the hydration products and pore structure were analyzed. It was found that silica flour prevented the strength retrogression of the hardened cement paste at high temperature, and the compressive strength of the hardened cement paste decreased with the decrease of silica flour particle size. Silica flour reduced the permeability of the hardened cement paste. The smaller the particle size of the silica flour, the lower the permeability. The cement slurry mixed with larger particle size silica flour produced longer needle-like xonotlite, which was the main reason why the hardened cemlent paste had high compressive strength. A high temperature and high pressure cement slurry containing 35% 300-mesh silica flour and other additives was used to cement the well DX-11-2 in the Nanhai oilfield. The well cementing operation was smoothly performed, and the 24 h CBL and VDL wireline logging showed that the cementing quality was excellent.
ZHANG Guoguang, WANG Chunyu, DAI Dan, et al.The effects of particle size of silica flour on the performance of oil well cement at high temperature and high pressuree[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：466-471. doi: 10.12358/j.issn.1001-5620.2022.04.011.
Abstract: In deep and ultra-deep well cementing, the viscous force of the liquid phase of a cement slurry decreases at elevated temperatures, resulting in settling of solid phase and even lamination of the cement slurry. To solve these problems, a high temperature suspending agent GX was developed through radical solution polymerization with acrylamide (AM), sodium p-styrene sulphonate (SSS), N,N-diethylacrylamide (DEAA) as the monomers and ammonium persulphate (APS) as the initiator. GX is a terpolymer resistant to 200 ℃. Characterization of the molecular weight, molecular structure and morphology of GX with GPC, FTIR, 1H-NMR and SEM have shown that the three monomers all take part in the polymerization reaction to produce the AM/SSS/DEAA terpolymer. TG, FTIR and SEM analyses have shown that the high temperature suspending agent GX has excellent thermal stability, it is resistant to 318.6 ℃. High temperature settling stability evaluation has shown that GX functions normally at temperatures as high as 200 ℃, a cement slurry treated with GX has density difference of less than 0.02 g/cm3 at 200 ℃. GX can be used to improve the settling stability of cement slurries, and it has no negative effects on the rheology, thickening time of the cement slurry, and on the strengths of the set cement.
LUO Min, HUANG Sheng, HE Xusheng, et al.The preparation and performance characterization of a cement suspending agent resistant to 200 ℃[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：472-480. doi: 10.12358/j.issn.1001-5620.2022.04.012.
Abstract: In oil and gas well drilling, the low bond strength between the cement sheath and the borehole wall (mud cakes) is an important factor causing gas channeling along the interfaces between the cement sheath and the borehole wall. In laboratory experiment, a low viscosity high penetrating capacity epoxy resin (HP epoxy resin) containing reactive thinner was mixed with a cement slurry. The epoxy resin in the mixed cement slurry can penetrate and diffuse into the mud cakes under high pressures. The epoxy resin, after becoming consolidated, greatly improved the bond strength between the cement sheath and the mud cakes. The experimental results have shown that the consolidated epoxy resin have high compressive strength and can be uniformly mixed with cement slurry with the aid of Tween-80, a surfactant. The properties of the cement slurry modified with the HP epoxy resin meet the requirements of field operations. By contact angle measurement and SEM analysis, it was found that the epoxy resin improved the bond strength between the cement sheath and the borehole wall through a “penetration-diffusion-bonding” process. A cement slurry containing 5% HP epoxy resin had 1 d compressive strength of 24.3 MPa. When this cement slurry was bonded with mud cakes, the bond strength of the solidified mud cake of 1 mm in thickness can be as high as 0.45 MPa. When the content of the HP epoxy resin in the cement slurry was increased to 10%, the bond strength was raised to 0.55 MPa accordingly. From the micromorphology of the consolidated mud cakes it was found that the HP epoxy resin penetrated and diffused into the mud cakes from the cement slurry, making the surface of the mud cakes denser, hence improving the bond strength of the interfaces between the modified cement slurry and the mud cakes.
YU Bin, WANG Youwei, MA Tianlong, et al.Penetrating consolidating epoxy-based oil and gas well cementing additives for use at ambient temperature[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：481-487. doi: 10.12358/j.issn.1001-5620.2022.04.013.
Abstract: Cementing of ultra-long horizontal section of Sulige Tight Gas Reservoir in Changqing Oilfield has long open-hole sections, small annulus gaps, high flow friction and pressure loss, high construction pressure, and easy leakage, resulting in poor cementing quality and later annular pressure. A series of complex issues have seriously affected subsequent mining and single well production. Therefore, low friction low density cement slurry and low friction high strength and toughness cement slurry are developed to improve the fluidity of cement slurry and reduce the flow friction pressure consumption, and reduce the construction pressure and the risk of leakage.Low-friction low-density cement slurry adopts hollow glass beads with good pressure resistance as the main reducing material to improve the pressure resistance of the system, and maintain a higher roundness of the structure after entering the well, effectively reducing the friction and pressure loss.Low-friction high-strength and toughness cement slurry is based on conventional cement slurry, introducing solid glass microspheres and composite high-efficiency reinforcing agents to improve the fluidity of the cement slurry and reduce friction pressure loss on the basis of ensuring the mechanical properties of the cement stone. The experimental results show that the Fanning friction coefficient of low-friction and pressure-resistant hollow glass microbead cement slurry is reduced from 0.0593 to 0.0295, which is 50.25% lower than that of conventional low-density cement slurry . The friction coefficient of low friction high strength toughness cement slurry is reduced from 0.07 to 0.0414, 40.86% lower than the conventional high strength toughness cement slurry. The preliminary pilot test shows that the low friction cement slurry can reduce the friction pressure and the construction pressure effectively. The adoption of low-friction cement slurry and the segmented gradient sand carrying design of low-friction high-strength and high-toughness cement slurry helped the cement construction of 5256 m ultra-long horizontal section in tight gas reservoir to be successfully completed, and the cementing quality was qualified, providing strong technical support for the ultra-long horizontal section in Changqing tight gas reservoir.
WANG Ding, CHEN Caizheng, DU Songtao.Low friction cement slurry cementing technology in ultra-long horizontal section of tight gas reservoir[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：488-494. doi: 10.12358/j.issn.1001-5620.2022.04.014.
Abstract: The performance of temporary plugging materials largely determines the effect of temporary plugging transformation, while conventional temporary plugging materials often cannot meet the needs of ultra-deep, ultra-high temperature, ultra-high pressure and deficit reservoir construction. In view of the above problems, with the goal of temperature resistance reaching 160 ℃, strength higher than 30 MPa, and gel breaking time reaching 10 h,this paper proposes to synthesis of thermosensitive gel and all-degradable fiber into fiber reinforced gel.The technical principle is that the chemical network structure of thermosensitive gel and the physical network structure of fiber form a three-dimensional composite network framework, which greatly improves the strength of temporary plugging materials.The performance evaluation showed that the gelation time of the fiber-reinforced gel could be controlled within 5-26 min at 80-100 ℃ ; the temporary plugging time was also greatly improved, and the gel was completely broken at 160 ℃ for nearly 10 h.In the experiment, under the condition of 2 mm fracture width, the bearing pressure ability is more than 30 MPa, and the larger the fracture width is, the higher the bearing capacity is. Under the condition of 6 mm fracture width, the bearing capacity can reach 40 MPa, which is suitable for the temporary plugging and steering transformation of the “three excesses” depleted reservoir, and can meet the needs of field construction.
JI Cheng, HE Tianshu, ZHAO Bing, et al.Synthesis and performance evaluation of fiber reinforced gel[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：495-500. doi: 10.12358/j.issn.1001-5620.2022.04.015.
Abstract: Different pay zones in the BZ oilfield have big permeability differences among them and high heterogeneity, resulting in preferential flow of block removing fluids into zones with high permeabilities during pumping which in turn further increasing the permeability differences among different zones. This is quite unsatisfactory to the removal of the blockage existing in the reservoir formations. Furthermore, the conventional VES diverting fluids are only sensitive to divalent cations, and are thus behaving poorly in offshore sandstone reservoirs which lack divalent cations. To solve this problem, a viscoelastic surfactant LD-VES, a K+ sensitive diverting fluid, were selected to combine with a block removing fluid to form a diverting block removing fluid for offshore sandstone reservoir operation. In laboratory experiment, the diverting fluid was evaluated for its viscosifying capacity, gel breaking performance, high temperature tolerance, shearing property and compatibility with the block removing fluid. The viscosifying, gel breaking and flowback mechanisms of the diverting fluid were analyzed. Field application of the diverting block removing fluid has shown that the fluid has the best viscosifying effect at KCl mass fraction of 7%. At 120 ℃, the viscosity of the fluid was 1, 680 mPa∙s at shearing rate of 50 r/min. After being sheared for 2 hours at 170 s−1, the viscosity was still 1,750 mPa∙s, indicating that the fluid had excellent viscosifying capacity, high temperature tolerance and shearing property. The mixture of the diverting fluid and the block removing fluid produced no precipitation and residue, indicating that they had good compatibility with each other. After mixing kerosene with the diverting block removing fluid in 1 : 1 volume ratio, the gel of the diverting block removing fluid was soon broken. Field application of this diverting block removing fluid produced liquid of 27.92 m3/d, a production rate 3.49 times higher than that before the application (which was only 8 m3/d), and oil of 16.75 m3/d, 4.05 times of the production rate before the application.
LIU Changqing, ZHANG Ning, MA Liang, et al.Study and application of a K+ sensitive ves diverting block removing fluid[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：501-507. doi: 10.12358/j.issn.1001-5620.2022.04.016.
Abstract: Formation damage has long been a problem existed in producing through fracturing the conglomerate reservoir in the upper Wuerhe formation in Mahu sag, Dzungar basin. Based on the analysis of the basic characteristics of the upper Wuerhe conglomerate reservoirs in the Mahu-1 block in Dzungar basin, laboratory experiments were performed to evaluate 1) the compatibility between the fluid from fracturing fluid after gel breaking and the formation water, as well as the plugging of reservoir formations by solid particles; 2) the sensitivity of the reservoir to various damaging factors; and 3) capillary imbibition and the swelling of clay minerals though hydration. Main factors contributing to the reservoir damage were analyzed. In the laboratory evaluation experiments, the clay swelling inhibitor and the biomimetic amphiphobic fracturing fluid cleanup additives were selected. In addition, an intelligent quantitative prediction technology for reservoir sensitivity damage was also established. The study results showed that the main factors contributing to the damage of the sandy conglomerate upper Wuerhe formation in the Mahu-1 block in Dzungar basin include swelling of the montmorillonite caused by water absorption, strong capillary imbibition, solid particle blocking, water sensitivity and weak acid sensitivity. In laboratory swelling test with 4% polyetheramine solution, the cores only swelled by 1.28 mm, the cleanup efficiency of the biomimetic amphiphobic cleanup additive was at least 88.54%. The amount of the fluid (2% polyetheramine plus 2% amphiphobic fracturing fluid) absorbed by the cores was 1.38 mL, resulting in a length of swelling of 1.42 mm, and the ratio of the back flowed fracturing fluid was 86.2%. Using the intelligent quantitative prediction technology, the precision of the sensitivity prediction can be as high as more than 85%. All these study results together formed a set of technology for protecting the conglomerate reservoirs in the Mahu block in Dzungar basin.
WEI Yun, SHEN Xiulun, ZHOU Wei, et al.Damage of sandy conglomerate reservoirs in Dzungar basin by fracturing fluids and measures for protection of the reservoir damage[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：508-515. doi: 10.12358/j.issn.1001-5620.2022.04.017.
Abstract: Conventional acid block removing systems generally are formulated with common liquid acids such as hydrochloric acid or nitric acid. These liquid acids have high costs and safety risks in storing, transportation and operation. To solve these problems, three solid acids, which are sulfamic acid, citric acid and diethyl triamine penta-acetic acid, are selected to study their dissolution capacity and capability of stabilizing iron ions. By adjusting the ratio of the three acids, the optimum ratio was determined to be∶m(sulfamic acid)∶m(citric acid)∶m(diethyl triamine penta-acetic acid) = 8∶1∶1. A solid acid block removing system was formulated using the compound solid acid as the main additive, coupled with corrosion inhibitor, penetrant and clay swelling inhibitor. This solid acid block removing system has the ability to dissolve calcium carbonate; a percent rate of dissolution of 27.65% of marble was obtained with the solid acid block removing system. The solid acid block removing system has iron ion complex capacity of 643.71 mg/L, a good iron ion stabilizing performance. Core flow experimental results showed that when the solid acid block removing system was injected into the core by 10 PV, the permeability of the core was increased by at least 20%. Field operation has shown that the application of this solid acid block removing system resulted in higher production rate of hydrocarbons.
LI Jiyong, SUN Yuhai, LU Zhanguo, et al. a solid acid block removing system for carbonate reservoirs[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：516-521. doi: 10.12358/j.issn.1001-5620.2022.04.018.
Abstract: Clay minerals often pollute and block oil reservoirs. Chlorite is one of the main components of clay minerals. The strong acid as plugging remover in feature of high corrosivity and high efficiency was commonly used in the oilfields. When the protons are consumed, the efficiency of the plugging remover system is greatly reduced. To solve the problem of oilfield blockage material, this paper compares the physical properties of chlorite from various producing areas, and purposefully develops a weak acid plugging remover with a strong chelating ability to metal in clay minerals and buffering ability. The experimental research displays that under the conditions of 4% mass concentration of main plugging removal agent and pH = 5, the dissolution rate of chlorite reaches 25% under 24 h, indicating that the plugging remover has the advantages of high dissolution rate, good plugging removal effect, weak corrosion, and good compatibility. The mechanism study shows that the effective combination of plugging remover and buffer system to continuously and stably provide a certain concentration of protons is the key to the efficient plugging removal of chlorite under weak acidic conditions. During the exploitation of well WZ-X, clay swelling and migration damage were caused by drilling and completion fluid immersion into the formation. Chlorite plugging agent was used to remove pollution. After the operation, the fluid production of the well increased from 55.5 m3/d to 98 m3/d. The successful application of this technology provides a new direction for oilfield plugging removal.
PAN Dingcheng, WEI Huiying, ZHANG Hongjing, et al.Development and performance evaluation of weak acid plugging removal agent for chlorite[J]. Drilling Fluid & Completion Fluid，2022, 39（4）：522-528. doi: 10.12358/j.issn.1001-5620.2022.04.019.
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