2022 Vol. 39, No. 6

FORUM
Progresses in the Studies of Mud Loss Control with Polymer Gels
HAO Huijun, LIU PO, YAN Juntao, MA Chengyu, HE Bin, XUN Wenyun
2022, 39(6): 661-667, 676. doi: 10.12358/j.issn.1001-5620.2022.06.001
Abstract(809) HTML (364) PDF (2865KB)(104)
Abstract:
Polymer gel lost circulation materials (LCMs) have the advantages of high viscoelasticity and deformability in mud loss control. Generally, there are two kinds of polymer gel LCMs, one is the conventional polymer gel LCMs and the other, the so-called “intelligent” polymer gel LCMs. When use the conventional polymer gel LCMs to control mud losses, the gelling time of the polymer gel is not controllable, and therefore the losses of muds or other work fluids cannot be stopped efficiently and accurately. On the other hand, the “intelligent” polymer gel can be used to efficiently and accurately stop the mud losses based on many different mechanisms, and are therefore under investigation as a hotspot LCM. It can be expected that the stimuli-responsive polymer gel will become one of the important fields in which LCMs are studied.
DRILLING FLUID
Analyses of the Ballooning Effect and its Affecting Factors in Drilling Shallow Formations in Deep Water
LUO Ming, GAO Deli, HUANG Honglin, LI Jun, YANG Hongwei
2022, 39(6): 668-676. doi: 10.12358/j.issn.1001-5620.2022.06.002
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Abstract:
Ballooning effect encountered during drilling is easy to be taken as well kick and the well is then killed. This operation often results in severe mud losses, increasing the risks and costs and causing serious harm to the safety and efficiency of deep-water drilling. To solve this problem, the mechanisms of ballooning effect was studied, and the COMSOL software was used to simulate the whole process of ballooning during drilling in the shallow formations in deep water area. The effects of formation characteristics, drilling fluid properties and pressure differential on the ballooning effect were studied. The simulation results have shown that the ballooning effect taking place in the shallow formations in deep water area is a permeable mechanism. The permeable ballooning effect is very easy to happen in formations with low elastic modulus, low Poisson’s ratio, high porosity and high permeability. This kind of ballooning effect can be inhibited with high viscosity high yield point drilling fluids, and drilling with low pressure differentials (low density, low flow rate). Thus, when drilling formations with low elastic modulus, high Poisson’s ratio, low porosity and high permeability, measures should be ready in advance, for example, treating the mud with filter loss reducers, reducing pump rate, to minimize the impact of the ballooning effect. This study is of reference importance to the identification, prevention and plan for the controlling of ballooning effect encountered in shallow formations in deep water area.
Study and Application of Formation Environment Responsive Plugging Material
KONG Yong
2022, 39(6): 677-684. doi: 10.12358/j.issn.1001-5620.2022.06.003
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Abstract:
The borehole wall stabilizing materials presently in use have particle sizes that are unable to accurately match the sizes of micro-fractures in the formations drilled and lack the ability to identify the formation with fractures to plug and the required selective action. A technical clue for developing formation environment responsive borehole wall stabilizing materials is presented to solve these problems. A responsive mechanism based on driving factors that are formation-related is established for the purpose of optimizing the reaction form, the morphological change of the active components in formation environment and the assembling methods of the active components and the carrier materials. Based on these studies, a formation environment responsive plugging material, SMFG-1, was developed. SMFG-1 has excellent formation responsive performance and compatibility with other drilling fluid components, it remarkably improves the quality of mud cakes, and is environmentally friendly. The pH of SMFG-1 is 6 - 8. SMFG-1 can form sediments in formation through quick responsiveness, thereby plugging pore throats and microfractures. SMFG-1 can release particles to plug microfractures with great sensitivity under controllable manner. After six pH response cycles, the release rate is still as high as 99.55%. SMFG-1 has been successfully used in drilling the complex hole section of the well Bei-XY-HF. As a result of using the SMFG-1 plugging agent, the plugging capacity of the drilling fluid was improved, and the borehole wall was stabilized. The problems encountered in drilling the easy-to-collapse hard and brittle shales with fractures and cracks were avoided and the safety of drilling the complex hole section was achieved.
Development and Evaluation of a Self-Crosslinking Filter Loss Reducer for Oil Based Drilling Fluids
YANG Jun, JIANG Guancheng, WANG Guoshuai, HE Yinbo, YANG Lili, YUAN Xueqiang
2022, 39(6): 685-691. doi: 10.12358/j.issn.1001-5620.2022.06.004
Abstract(648) HTML (252) PDF (2834KB)(96)
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Conventional filter loss reducers for oil based drilling fluids have deficiencies such as low thermal stability and negative influence on mud rheology. To solve these problems, a new self-crosslinking filter loss reducer, BSN, for oil based drilling fluids was developed through emulsion polymerization with N-methylol acrylamide (a functional monomer), butyl acrylate and styrene. The main functional groups, micromorphology and self-crosslinking characteristics of BSN were characterized by infrared spectroscopy, laser particle size analyzer and transmission electron microscopy. It was found that BSN has self-crosslinking functional group of hydroxymethyl. The average particle size of BSN is 247 nm, and obvious particle-particle crosslinking structure can be seen. Thermalgravimetric test results have shown that BSN has good thermal stability, the initial decomposition temperature of which is 355 ℃, greatly higher than its non-self-crosslinking counterpart BS, which is 278 ℃. Addition of 1% BSN in an oil based drilling fluid not only had little effect on the rheology of the drilling fluid, but also improved the electrical stability of the drilling fluid. This oil based drilling fluid had HTHP filtration rate of only 4 mL, indicating that BSN was superior to BS and 3% other conventional filter loss reducers in controlling the filtration rate of oil based drilling fluids.
Study on Property Control of High Density Drilling Fluids Based on Modified Alferd Model
WANG Di, QIU Zhengsong, MIAO Hailong, GENG Tie, ZHONG Hanyi, ZHAO Xin, FAN Lijun
2022, 39(6): 692-699. doi: 10.12358/j.issn.1001-5620.2022.06.005
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Abstract:
The effect of barite particle sizing on the rheology and filtration property of a high density drilling fluid and the mechanisms of this effect are investigated to try to solve the difficulties encountered in controlling the performance of a high density drilling fluid used in drilling a deep high temperature well. Based on the fractal theory, the Alfred equation, which is generally used in powder packing calculation, was modified to establish a particle size distribution model suitable for weighting a drilling fluid with sized barite particles, the theoretical optimal quantity ratio of the sized barite particles was calculated, and the feasibility of the modified model was verified by experiment. Laboratory experiment shows that the modified Alferd model can be used to guide the design of the sizing of particles used to weight a drilling fluid and to determine the optimum quantity ratio of particles with different sizes. Weighting a drilling fluid with reasonably sized barite particles can reduce the probability of collision between particles in the drilling fluid and the storage modulus, weaken the network structure and the flow resistance of the system, and make the particle size distribution of barite more appropriate; it is beneficial to the formation of dense mud cakes, and to the improvement of drilling fluid rheology and filtration property.
Performance Optimization of Slim-Hole Drilling Fluids Under Hole Cleaning Condition
AN Jintao, LI Jun, HUANG Honglin, YANG Hongwei, ZHANG Geng, CHEN Wang
2022, 39(6): 700-706. doi: 10.12358/j.issn.1001-5620.2022.06.006
Abstract(644) HTML (269) PDF (2602KB)(111)
Abstract:
In Xinjiang Oilfield, part of the Mahu block is developed with long horizontal (exceeds 2000 m) slim holes. In drilling operation, pipe sticking resulted from poor hole cleaning and mud losses resulted from excessive wellbore pressure seriously restricted the efficient and economic development of the block. One of the key methods to solve these problems is the optimization of the drilling fluid properties. Using CFD numeric simulation method, a model describing the solid liquid two-phase flow in annular spaces was established, and the effects were investigated of different mud rheological parameters (Herschel-Bulkley rheological model) on the migration of the drilled cuttings and the annular pressure losses under different drilling parameters. Th numeric simulation results show that (1) an increase in drilling fluid density is beneficial to the carrying capacity of the drilling fluid; (2) the effects of the mud rheological parameters on the migration of drilled cuttings vary under different drilling parameters; (3) higher mud rheological parameters do not necessarily aid in cuttings migration; (4) an optimum mud rheology range was determined for the drilling operation in the Mahu block based on its characteristics, and the optimum mud rheology range has been successfully used in field operations.
Settling Behavior and Drag Coefficient Model of Rock Cuttings of Varied Shapes
WANG Gui, TAN Kai, CAO Cheng
2022, 39(6): 707-713. doi: 10.12358/j.issn.1001-5620.2022.06.007
Abstract(557) HTML (224) PDF (2624KB)(69)
Abstract:
In oil and gas drilling, free settling of drilled cuttings along the wellbore may cause pipe sticking. To investigate the settling behavior of the cuttings particles, laboratory experiment was performed to simulate the free settling of drilled cuttings. Using the data collected in the experiment and image processing technology, the final settling velocities and drag coefficients of 10 kinds of particles of varied shapes in 9 non-Newtonian fluids were calculated and the effects of the particle shape and rheology of the fluids on the settling behavior of the particles were investigated. The adaptability of the existing drag coefficient models to the settling of non-spherical particles in non-Newtonian fluids was also studied. The results of the studies show that the higher the non-sphericity of the particles, the more difficult for them to settle in the fluids. Increase in the viscosity of the fluid can effectively hinder the settling of the particles, and the stronger the non-Newtonian property of the fluids, the stronger the hindrance of the fluids on the settling of the particles. The existing drag coefficient models are not suitable for describing the settling behavior of non-spherical particles in non-Newtonian fluids. To solve this problem, a new shape factor is presented to build a new drag coefficient model. Results of the error analyses of the model show that the new model has excellent fit to the data measured in settling experiment; the coefficient of determination R2 is greater than 0.99. Compared with the existing model the prediction accuracy of the new model is increased by 50.5%, and errors in predicting the drag coefficient of real rock particles are less than 15%. This new model can be used to better describe the settling drag coefficient of rock particles of varied shapes, and has both theoretical and practical significance to improving the stability of rock particles in drilling fluid during drilling operation.
Synthesis and Performance Evaluation of Nano SiO2 /Acrylamide Flocculant
YANG Hao, YUE Qiansheng, ZHAO Qingmei
2022, 39(6): 714-720. doi: 10.12358/j.issn.1001-5620.2022.06.008
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Abstract:
SiO2 of different particle sizes were prepared through sol-gel method using tetraethyl orthosilicate (TEOS) as the raw material. The SiO2 particles, after surface modification, was in turn used as raw material to react with acrylamide (AM) and dimethyl diallyl ammonium chloride (DMDAAC) to produce nano SiO2/cationic polyacrylamide (SCPAM) through inverse emulsion polymerization. Characterization of the final product determines that it is the required product. Study on the effects of the SiO2 particle size and concentration on the molecular weight, water solubility, viscosifying performance and flocculating capacity of SCPAM shows that SCPAM made from 15 nm SiO2 at mass fraction of 0.9% of the whole reaction monomers has the best water solubility, viscosifying performance and flocculating capacity. Evaluation of a drilling fluid formulated with SCPAM as a flocculant shows that the drilling fluid has a final viscosity of about 30 mPa·s at salt concentration of 30%. After aging for 96 h, the viscosity of the drilling fluid is still about 33 mPa·s, meaning that the drilling fluid has good salt and high temperature resistance. It is also found that the drilling fluid works satisfactorily at drilled solids contents less than 5% and temperatures lower than 160 ℃.
CDF-DEM Simulation of the Formation and Failure Mechanisms of Plugging Layers Formed by Plugging Particles in Fractures at Mesoscale
LI Jie, FENG Qi, ZHANG Gaofeng, CUI Kaixiao, JIANG Guancheng, HE Yinbo
2022, 39(6): 721-729. doi: 10.12358/j.issn.1001-5620.2022.06.009
Abstract(625) HTML (247) PDF (6923KB)(79)
Abstract:
Plugging particles entering the formation fractures are generally expected to quickly form stable high strength plugging layers inside the channels through which mud is lost, thereby effectively isolating the borehole and the loss zones. This characteristic of the plugging particles is critical to controlling the severity of mud losses and strengthening the borehole walls. Presently, the general practice is to study the ability to reduce rate of mud losses and the pressure bearing capacity of a plugging layer from the macro point of view, in which the plugging layer as a whole is studied, and from the micro point of view, in which the properties of a single plugging particle are studied, while studies from the mesoscale point of view on the changing process of a plugging layer formed by the plugging particles inside a fracture are seldom conducted. To further reveal the formation and failure mechanisms of the plugging layers formed by the plugging particles inside formation fractures, based on computational fluid dynamics and discrete element coupling simulation method, the retention, bridging, plugging and destabilization of the plugging particles inside wedge-shaped fractures are studied, and the effects of the properties of the lost circulation materials and the drilling fluids on the formation of plugging layers at mesoscale level are analyzed. The study and the analyses show that after entering the fractures, the plugging particles form plugging layers through a series of processes: retention, accumulation and plugging, and the front end of the plugging layer is key to the stability of that plugging layer. The smaller the particle size is, the closer the plugging layer is to the outlet of the fracture. Increase in the concentration of the plugging particles effectively reduces the time for a plugging layer to form. When the concentration of the plugging particles is raised from 2% to 30%, the time for the plugging layer to initially form is reduced from 0.090 s to 0.036 s, or reduced by 60%. Furthermore, the geometry and physical properties of the plugging particles, as well as the mud properties all play important roles in the formation and failure of a plugging layer. The study results have certain reference values for optimizing plugging particles to rapidly form efficient plugging layers.
Study on an Acid Soluble LCM Used for Multi-Target Well in Tahe Oilfield
QI Biao, LI Yinting, YUE Ming, JIANG Xueqing, LIU Wentang
2022, 39(6): 730-737. doi: 10.12358/j.issn.1001-5620.2022.06.010
Abstract(538) HTML (213) PDF (3367KB)(91)
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The underdeveloped carbonate reservoirs in the Tahe Oilfield have fractures and vugs that are small scaled and production through a single well generally cannot realize its expected economy. Use multi-target well to penetrate multiple fractured reservoirs or reservoirs with vugs through one well, the production potential of a single well can be economically increased. The problem with the multi-target well drilling is mud losses in the complex fracture structures, which restrict the realization of fast and high efficiency drilling. By analyzing the characteristics of the mud losses taking place in fractured reservoirs and the difficulties encountered during drilling, an acid-soluble gel particle lost circulation material (LCM) was developed to solve the mud losses in reservoir drilling. Percent acid solubility of this LCM is 86%. After swelling, the volume of the LCM can be 3-5 times of its original volume, and the swollen LCM has good toughness and deformability. The acid soluble gel particle LCM, through orthogonal test, was mixed with an acid soluble flexible fiber and a flaky material to form a compound acid soluble LCM based on the mechanisms of mud loss control with gel particles. The compound LCM can be used at temperatures up to 150 ℃ and has percent acid solubility of 85%. It can used to stop mud losses through fractures of 0.1-3.0 mm in width and pores of 4-10 mesh. The pressure bearing capacity of the LCM layer is 9 MPa on the front side and 5 MPa on the opposite. Field application has shown that this compound acid soluble LCM can be used to solve mud losses into the complex fractures developed in carbonate rock reservoirs and should have broad application prospects.
Preparation and Performance Evaluation of Environment-friendly Anti-high Temperature Composite Anti-mud-bag Lubricant
CHEN Lei, ZHANG Xiaoping, JIA Jun
2022, 39(6): 738-742. doi: 10.12358/j.issn.1001-5620.2022.06.011
Abstract(550) HTML (226) PDF (2569KB)(58)
Abstract:
With the development of exploration and development in the direction of deep well, ultra-deep well and ultra-long horizontal section, the formation is complex during drilling. In view of the technical difficulties such as the formation with high mud content and strong hydration easily producing bit mud pack, as well as the high frictional resistance, high torque fluctuation and frequent supporting pressure during drilling in long horizontal section, which seriously affect the construction progress, a kind of copolymer with multiple recognition sites was synthesized by micellar copolymerization, and a new type of micro-nano graphite-polymer composite anti-mud-bag lubricant and drag reducer was developed by intercalating nano-graphite, the results of contact angle and x-ray photoelectron spectroscopy show that the lubricant adsorbs on the surface of the steel sheet preferentially than water, and has a stable coordination with Fe, to improve lubrication. The temperature resistance is more than 160 ℃, the fluorescence grade is less than 2, the lubricating coefficient of base mud with 0.5% lubricant is reduced by 80.0% , and the surface tension of filtrate of drilling fluid is lower than 25 mN/m.The product has significant potential application value in the exploration and development of deep oil and gas.
CEMENTING FLUID
Research and Field Test of Self-Healing Cement Slurry for Gas
HE Yingzhuang, BU Yuhuan, LIU Huajie
2022, 39(6): 743-747. doi: 10.12358/j.issn.1001-5620.2022.06.012
Abstract(560) HTML (245) PDF (2398KB)(69)
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The micro crack and micro annular gap are inevitable during the production of condensate gas reservoir in Shunbei oil & gas field, but the existing self-healing agent has low temperature resistance, and the evaluation method of self-healing ability is very different from the downhole working conditions. So it can not be applied to Shunbei oil & gas field. A self-healing emulsion in gas suitable for Shunbei oil & gas field is developed, with the volume expansion rate in gas reaches 30%. This agent can prepare self-healing cement slurry with density range of 1.45-2.20 g/cm3, which is suitable for 90-180 ℃, with low modulus of elasticity <7 GPa. At the same time, a reasonable evaluation method for the self-healing ability of cement in gas is devised. Through the first and second artificial fractures making, the self-healing ability of cement paste is 100% and 95.1% respectively. At present, the self-healing cement slurry for gas has been tested in 3 wells, and the high quality rate of cementing quality is 100%, which meets the needs of long-term sealing of HTHP gas wells in Shunbei oil & gas field.
Effects of Polymer Sidechains on Performance of Oil Well Cement Filter Loss Reducers and Studies on Mechanisms of the Effects
XIA Xiujian, LI Pengpeng, YU Yongjin, JIN Jianzhou, ZHANG Hang, HU Miaomiao, GUO Jintang
2022, 39(6): 748-753. doi: 10.12358/j.issn.1001-5620.2022.06.013
Abstract(561) HTML (217) PDF (2677KB)(47)
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To understand the relationship between the molecular structure and the performance of copolymers used as oil well cement filter loss reducers, as well as to guide the molecular structure design of new ultra-high temperature and salt resistant filter loss reducers, the effects of polymer sidechains on the filtration control performance of the copolymer filter loss reducer were studied through molecular kinetics simulation and laboratory experiment. The mechanisms of the copolymer’s ability to resist high temperature and salt contamination were also investigated. Laboratory experimental results show that the introduction of rigid benzene side groups into the final copolymer reduces the API filtration rate of a fresh water and a saturated saltwater cement slurry after being aged at 240 ℃, meaning that the copolymer has excellent ultra-high temperature and salt-resistant performance. Molecular kinetics simulation results show that the introduction of the rigid benzene side groups increases the gyration radius of the copolymer segments, weakens the dehydration effect of the large amount of counterions (Na+ and Ca2+) on the functional groups of the copolymer. This is beneficial to the adsorption and hydration of the filter loss reducer molecules on the surfaces of the cement particles, and gives full play to its original use efficiency.
Changes of Mechanics and Characteristics of Porosity and Permeability of Set Cement at High and Ultra-High Temperatures
DING Jianxin, XI Yan, JIANG Jiwei, WANG Haitao, LI Xuesong, LI Hui
2022, 39(6): 754-760. doi: 10.12358/j.issn.1001-5620.2022.06.014
Abstract(498) HTML (209) PDF (2932KB)(42)
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In shale oil production using in-situ thermal recovery method, the temperature in the borehole is high or even ultra-high, and it is easy to result in failure of the sealing integrity of the cement sheath. It is thus important to study the changes of the mechanical characteristics and the porosity and permeability of a set cement under high or ultra-high temperatures. Using digital image technology, changes of the failure mode of a set cement after high temperature treatment is analyzed. Using low field NMR, the changes of the porosity and permeability of a set cement after high temperature treatment are studied, and the correlation of porosity and permeability is analyzed. The study shows that for a high temperature treated set cement sample, as the temperature increases, the monoaxial compressive strength of the set cement first increases and then decreases. The porosity and the permeability of the set cement increase continuously; at first, the increase goes slowly and then goes fast. This is because at lower temperatures, there are only micro and small pores produced inside the cement and these pores are not inter-connected with each other. As the temperature increases, some micro and small pores combine into medium and large pores, and pores of different sizes begin to connect with each other, thereby increasing the permeability of the set cement. The achievements of the study have important reference significance for protecting the sealing integrity of cement sheath and optimizing cement slurry formulation in in-situ thermal recovery of shale oil.
Rule of Propagation of Fractures through the Bonding Interfaces of Cement Sheath in Horizontal Well Fracturing
LI Chengsong, LI Shekun, FAN Mingtao, CHEN Xubo, JIN Di, GAO Fei, WANG Xi
2022, 39(6): 761-766, 775. doi: 10.12358/j.issn.1001-5620.2022.06.015
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In fracturing a horizontal shale gas well, the injection of a high pressure fluid into the well may cause flow of the fracturing fluid along the interface between the casing and the cement sheath and the interface between the cement sheath and the borehole wall, and this imposes a serious challenge to the borehole integrity. A model describing the extension of fractures on both sides of cement sheath under constant injection pressure was established based on the CZM model, and the effects of cement sheath, formation mechanical parameters on the extension of the fractures on the cement sheath were analyzed. The study shows that increasing the cementing strengths of the two interfaces can simultaneously inhibit the extension of the fractures on both sides of the cement sheath. When the elastic modulus of the cement sheath is increased from 4 GPa to 9 GPa, the lengths of the fracture extension on the side of the cement sheath in contact with casing string and on the side of the cement sheath in contact with borehole wall will be reduced by 10 m and 19 m, respectively. When the elastic modulus exceeds 6 MPa, its effect on fracture extension on the side of the cement sheath in contact with borehole wall is becoming weakened. When the Poisson’s ratio is increased from 0.2 to 0.3, the lengths of the fracture extension on the side of the cement sheath in contact with casing string and on the side of the cement sheath in contact with borehole wall will be reduced by 10 m and 1 m, respectively, meaning that the Poisson’s ratio mainly affects the fracture extension on the side of the cement sheath in contact with casing. On the other hand, when the elastic modulus of the formation is increased from 25 GPa to 35 GPa, the lengths of the fracture extension on the side of the cement sheath in contact with casing string and on the side of the cement sheath in contact with borehole wall will be increased by 3 m and 9 m, respectively, meaning that a formation with low elastic modulus is beneficial to the controlling of the fracture extension. The achievements made in the study is of a certain guiding importance to the evaluation of the sealing integrity of the cement sheath in fracturing a horizontal well, and to the optimization of a cement slurry system.
FRACTUREING FLUID & ACIDIZING FLUID
Study on Supramolecular Gel Temporary Plugging Agent for Shale Gas Reservoir Fracturing
ZHANG Zhaoyang, CHEN Yuemei, BAO Jin, TANG Lei, TANG Jia, LAI Nanjun
2022, 39(6): 767-775. doi: 10.12358/j.issn.1001-5620.2022.06.016
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A supramolecular gel temporary plugging agent suitable for use in shale gas reservoirs of 90-110 ℃ was developed based on the principle of supramolecule chemistry. It has several advantages such as adjustable stable time, high strengths and ease of being removed. These advantages make it suitable for temporarily plugging micro-fractures and deep fractures.The new temperature-responsive supramolecular gel temporary plugging agent SCD12 was developed with β-CD as the host and SES as the guest, as well as other additives. Characterization of SCD12 shows that there is a supramolecular action among different components of the plugging agent. SCD12 was tested for the weight of residue after gel breaking, compatibility, rheology and temporary plugging performance. These experiments show that SCD12 is in a liquid form in room temperature and has low viscosity and hence good pumpability. At elevated temperatures, SCD12 can quickly plug fractures. SCD12 can effectively plug fractures in a certain temperature range even after gel breaking which results in viscosity reduction. The dynamic plugging capacity of SCD12 is 168.06 MPa·m-1. Percent permeability loss of a rock sample by SCD12 is 9.3%. These advantages of SCD12 satisfy the needs of temporary plugging in diverting fracturing of shale gas reservoirs, and make SCD12 a new promising temporary plugging agent.
Study on Aggregation Morphology and Resistance Reducing Properties of Drag Reducing Agents
SHI Yang, XU Ke, ZOU Cunhu, GUO Jianchun, DU Yurou, MA Yingxian, LI Yang
2022, 39(6): 776-786. doi: 10.12358/j.issn.1001-5620.2022.06.017
Abstract(393) HTML (227) PDF (8319KB)(51)
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In order to clarify the micro control mechanism of the macro drag reduction performance of slick-water drag reducer, a large number of micro characterization of the aggregate structure formed by different types of polymer drag reducing agents were carried out by environmental scanning electron microscope. Combined with the test of the drag reduction performance of the system, the micro mechanism of the effect of concentration on the drag reduction performance of different drag reducing agents systems was revealed from the level of polymer molecular aggregation structure. It was found that the slick-water drag reducer aggregated to form a filament structure at very low concentration. With the increasing concentration of the resistance reducer, these filament structures gradually entangled and connected to form a skeleton, and finally form a multi-level "spider net" aggregate network structure. At the same time, the network structure formed by different types of slick water resistance reducer had its own characteristics. Among them, emulsion and suspension type drag reducing agents had the most complete network structures, while powder type drag reducing agents had uneven distribution of aggregated network structures and low network strength due to slow dissolution speed. At low concentration, the average mesh wall thickness of the network structure formed by the three drag reducing agents was about 0.1-0.3 μm. With the increase of the concentration of drag reducing agents, the mesh shape of the system gradually changed from irregular to polygonal. Some drag reducing agents can form a circular network support structure with high strength and good stability. The mesh size decreased and the mesh wall thickness increased. When the concentration of drag reducing agents increased to 0.05%, the mesh wall thickness can reach 0.3-0.9 μm. The strength of network structure had been significantly improved. The aggregate network structure formed by the slick-water drag reducer will have an important impact on the resistance reducing performance of the system. The addition of the resistance reducing agent and the resistance reducing performance of the system did not show a simple linear relationship. Only an appropriate size aggregate network structure formed at a suitable concentration can closely interact with the water molecules in the system, stabilize the solution flow state, reduce the turbulence pulsation, and reduce the energy dissipation in the turbulent flow process, Finally, the effect of high-efficiency resistance reduction was realized.
COMPLETION FLUID
Study and Field Application of Calcium Sulfate Scaling in Fractured High Temperature Bedrock Gas Wells
HAO Shaojun, SHI Xiaowen, AN Xiaoxu, HE Honglin, GUAN Lu
2022, 39(6): 787-792. doi: 10.12358/j.issn.1001-5620.2022.06.018
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Abstract:
The reservoir temperature of Jianbei and Dongping gas fields in Qaidam Basin is 170 ℃, and the scale deposits are diverse, which poses a great challenge to the study of calcium sulfate scale dissolution, problems affecting gas well production and test operation. In this paper, through analyzing the composition of scale sample, defining the scaling mechanism, investigating the scale dissolving method, the scale dissolving research is carried out for the scale sample on the spot, the formula and technology of carbonate displacement scale dissolution and acid organic phosphoric acid scale dissolution were formed by distinguishing the deposit of Wellbore scale sample and reservoir scale formation respectively. The results show that the sample is composed of high-purity calcium sulfate and a small amount of carbonate and iron, and the source of the sample is the scaling ion in the formation water with high salinity The carbonate phase displacement scale dissolving method is suitable for calcium sulfate scale dissolving in wellbore. The high temperature of reservoir can reach the required reaction temperature and has no corrosion to wellbore string The acid organic phosphate chelating agent scale dissolving method is suitable for the calcium sulfate scale dissolving in the drill hole and near the well of the reservoir, and can be combined with the corresponding acidizing liquid system to develop the complex acidizing process at the same time, which can slow down the formation damage caused by the secondary precipitation. Finally, two sets of scale solubilizer formulation and corresponding scale dissolving process are formed, which can effectively dissolve reservoir calcium sulfate, solve the field technical problems, and make great contribution to increasing and stabilizing production of gas field.