2023 Vol. 40, No. 6

Study on Polymer Microspheres for Their Action in Enhancing Rheology Stability of Drilling Fluids Through Molecular Simulation
XU Lin, XU Li, WU Shuqi, BAO Yu, WANG Xiaotang, SHEN Jiamin, MENG shuang, WANG Lang
2023, 40(6): 693-702. doi: 10.12358/j.issn.1001-5620.2023.06.001
Abstract(408) HTML (104) PDF (3323KB)(131)
The spatial configuration transformation of polymer molecules from linear one-dimension to spatial three-dimension is a new clue for the molecular design of oilfield chemical additives through modification of conventional oilfield chemicals, and this method is beneficial to the development of new multi-functional polymeric water-based drilling fluid additives. To illuminate the morphological characteristics of the spatial polymers and the effective functions of these polymers as drilling fluid additives, studies on strengthening the stability of water based drilling fluids with polymer microsphere PAA-AM-AMPS are systematically conducted using methods such as experimental synthesis, structure characterization, performance evaluation and molecular simulation. First, the polymer microsphere PAA-AM-AMPS is synthesized. The microstructure of the polymer microsphere as well as the core role that the polymer microsphere plays in constant-rheology and ultra-high-temperature water based drilling fluids are examined. Then, based on the model of the “compensation effect” prevailed in the spaces of the spatial polymer groups, the strengthening effect of the spatial configuration on the adsorption of polymer molecules onto the bentonite layers is revealed from molecular point of view. The study shows that the synthesized spatial polymer PAA-AM-AMPS is spherical with a core-shell structure, with an average particle size of 198.3 nm. Its thermal degradation includes 5 steps, and the spatial configuration shows good thermal stability. The polymer microsphere molecule has a spatial configuration of “internal compactness and external sparsity”. The distribution of the active groups such as —COOH, —CO(NH2) and —SO3H on the shell of the microsphere determines the active position of the spatial structure. In these groups, the carboxyl group C=O is the dominant active group. Comparison of the chain and spheric structure shows that the spheric structure has smaller gyrational radius Rg and bigger radial distribution function g(r), indicating that the spheric configuration not only improve the thermal resistance of the structure, it also is beneficial to the retention of the number of the active groups on the surface of the shell, thereby ensuring the adsorption and association between the polymer molecules and the clay particles, and thus improving the stability of the macro-properties of the water based drilling fluid.
Synthesis and Evaluation of a High Temperature Salt-Resistant Chain Polymer Filter Loss Reducer
XING Linzhuang, YUAN Yuehui, YE Cheng, QU Yuanzhi, SUN Xiaorui, GAO Shifeng, REN Han
2023, 40(6): 703-710. doi: 10.12358/j.issn.1001-5620.2023.06.002
Abstract(301) HTML (100) PDF (2513KB)(117)
A branched polymer filter loss reducer PAANDA has been developed to deal with the problems of poor high-temperature stability and poor salt resistance encountered in deep well drilling. Monomers used for the synthesis include acrylamide (AM), 2-acrylamide-2-methyl propane sulfonic acid (AMPS), N-vinyl caprolactam (NVCL), dimethyl diallyl ammonium chloride (DMDAAC) and allyl alcohol polyoxyethylene ether (APEG). Potassium persulphate and sodium bisulphite was used as a redox system for the radical polymerization reaction. Laboratory experiment was conducted to determine the optimum ratio of the raw reaction materials and optimum reaction conditions ad follows:n (AM)∶ n (AMPS)∶ n (NVCL)∶ n (DMDAAC)∶ n (APEG) = 50 : 20 : 5 : 10 : 15, reaction temperature = 50 °C, reaction time = 4 hours, concentration of the initiator = 0.3%. Using FTIR and 1H-NMR, the molecular structure of the polymerization product was determined. TGA analysis showed that the PAANDA filter loss reducer degrades at above 300 °C, indicating that the product has excellent thermal stability. The filtration control property of PAANDA was evaluated in water-based drilling fluids. It was found that at a water-based drilling fluid treated with 2.0% PAANDA has API filter loss of 4.0 mL and HTHP filter loss of 22.6 mL tested at 180 °C after aging the fluid at 180 °C. The PAANDA also performed better than Driscal D in resisting contamination from compound salts and calcium.
A Polymeric Microsphere OBM-1 for Oil Based Drilling Fluids
ZHANG Wei, QIU Shixin, ZHANG Shuo, MA Jiaying, WANG Longyan, YANG Lili, JIANG Guancheng
2023, 40(6): 711-717. doi: 10.12358/j.issn.1001-5620.2023.06.003
Abstract(278) HTML (105) PDF (2602KB)(90)
Serious losses of oil based drilling fluids during drilling greatly affect the time efficiency of the drilling operation and the economic benefits of oil and gas development. Lost circulation materials presently in use are almost all developed for use in water based drilling fluids and thus have deficiencies for use in oil based drilling fluids. A polymeric microsphere OBM-1 for oil based drilling fluids was synthesized through inverse emulsion polymerization and organophilic groups were introduced into the molecules of the final product. OBM-1, a basically spherical material, has particle sizes between 1 μm and 100 μm, and disperses very well in oil based drilling fluids. An oil based drilling fluids treated with 3% OBM-1 has stable rheology and reduced medium pressure filtration rate and high temperature high pressure filtration rate. High temperature high pressure test results show that the higher the temperature, the better the filtration control performance of OBM-1. Test results of plugging under pressure with OBM-1 show that OBM-1 can plug the fractures of 5-40 μm under 15 MPa. Lost circulation test results show that OBM-1 can plug quartz sand-beds of 20-40 mech under 15 MPa. In field application, OBM-1 can effectively reduce the volume of mud lost, the well drilled with an oil based drilling fluid treated with OBM-1 has mud consumption that was reduced by 30.3%, greatly saved the drilling cost. This study has provided a strong technical support for safe and efficient drilling with oil based drilling fluids.
Optimization of Sulfur-Resistant Drilling Fluid Techniques and Its Application in Drilling High Sulfur Content Reservoirs in Northeast Sichuan
XIAO Jinyu, ZHOU Huaan, BAO Dan, FENG Xuerong, LU Hao, YANG Lanping, WANG Wei
2023, 40(6): 718-724. doi: 10.12358/j.issn.1001-5620.2023.06.004
Reservoirs in the Tieshanpo formation, the Luojiazhai formation, the Dukouhe formation, the Qilixia formation, the Zhengba formation and the Feixianguan formation in the Pushadan gas field in northeastern Sichuan are those with high or extra-high sulfur content gas reservoirs. This paper discusses the optimization of sulfur-resistant drilling fluid techniques for the drilling of these high sulfur content reservoirs based on the analyses of the reservoir formation geology and of the difficulties in drilling fluid operation. A drilling fluid with sulfur resistance was formulated through laboratory experiment. Laboratory evaluation of the effects of mud viscosity, pH value, alkalinity and oil/water ratio on the absorption of H2S has shown that the optimized water-based drilling fluid and the oil-based drilling fluid have good sulfur resistance. The sulfur-resistant drilling fluid formulated has been very successfully used on the well Po-002-H4 and the well Luojia-24; the drilling time was greatly shortened, the rate of penetration obviously increased, the average hole enlargement reduced, and the drilling fluid showed good sulfur-resistance and sulfur-removal during drilling. This drilling fluid has satisfied the requirements of drilling wells with high sulfur content, and has broad development and application prospects in drilling the high sulfur content formations in the lower east Sichuan area.
Drilling Fluid Technology for Stabilizing the Borehole Penetrating the Shasanyi Sub-member in Block NP-280 in Jidong Oilfield
WU Xiaohong, CHEN Jinxia, WANG Xianbo, KAN Yanna, DING Yi, LUO Pingya
2023, 40(6): 725-732. doi: 10.12358/j.issn.1001-5620.2023.06.005
Abstract(282) HTML (130) PDF (4536KB)(123)
Borehole wall collapse has been encountered when drilling the Shasanyi sub-member in many wells in the NP-280 block in Jidong Oilfield. Study has shown that the shales in the block are easy to hydrate when in contact with water. Microfractures with medium and high angles are developed in the thief zones. These microfractures, with original widths of 0.1 μm – 100 μm, become widened under pressure and hence further become fractures through which drilling fluids are lost. This in turn induces large-scale sloughing of the borehole walls and borehole collapse has thus occurred. In this paper, the studies on the mechanisms of borehole wall stabilization in the broken formations in the NP-280 block and the methods of borehole wall instability evaluation are described. Using the high temperature inhibitive drilling fluid, which was used to drill the third interval of the wells, a new inhibitive drilling fluid with high plugging capacity is developed thorough laboratory optimization. This drilling fluid is suitable for drilling formations with induced microfractures. Field application shows that it can be used to effectively prevent the borehole wall collapse problems encountered in drilling the Shasanyi sub-member, and this technology is worth applying in future drilling operation in this area.
Study on Methods of Evaluating Plugging Capacity of Nanometer and Micrometer Sized Plugging Agents for Shale Formations
DAI Feng, YI Gang, ZHANG Jing, WANG Rui, WU Shenyao, HUANG Weian
2023, 40(6): 733-741. doi: 10.12358/j.issn.1001-5620.2023.06.006
Abstract(286) HTML (91) PDF (4329KB)(134)
Methods presently in use for evaluating the performance of many kinds of plugging agents in nanometer and micrometer levels still lack the required accuracy and effectiveness, and no commonly followed standards are available. To deal with these problems, a mesoporous membrane and a dense sand-bed are selected as the media to simulate the microfractures in shale formations, and the filtration rate and the wetted depth of the sand-bed are used as the indices for evaluating the performance of a nanometer or micrometer plugging agents. The mesoporous membrane method uses a filter membrane with pore sizes between 100 nm and 450 nm, the fitting lines of the parallel experimental data have minimal fluctuations, and this method is thus suitable for evaluating the performance of the plugging agents with particle sizes distributed between 35 nm and 450 nm. The dense sand-bed method uses 200-mesh quartz sands as the packing material, and the variance of several experimental data is 0.2131, meaning that the parallelism of the experiments is good. This method is suitable for evaluating plugging agents with particle sizes distributed between 500 nm and 24.6 μm. Using this method, three ultra-fine plugging agents with big differences in particle sizes, which are ultra-fine calcium carbonate, emulsified rubber MORLF and ULIA, were evaluated for their performance, and the MORLF with deformability, was finally selected as the most suitable nanometer plugging agent. The evaluation methods presented and the nanometer-sized plugging agents have been applied on 7 wells drilled in the Changning block. Compared with other wells drilled with conventional oil based drilling fluids, the average percent hole washout of the 7 wells is reduced by 12.74%, and average drilling time reduced by 12 d, further proving that the methods presented have good parallelism and high accuracy.
Preparation and Affecting Effects of a Slow-Releasing Organic Microemulsified Acid Pipe-Freeing Agent
CHEN Ming, LAN Qiang, JIA Jianghong, HUANG Weian, WANG Xuechen, LI Xiuling
2023, 40(6): 742-748. doi: 10.12358/j.issn.1001-5620.2023.06.007
Drilling pipe-freeing agents presently in use have some problems that need to be solved, for example, the reaction rate of the pipe-freeing agents is too high which is easy to result in loss of the spotting fluids into formations and thus failures of the pipe-freeing operation. A slow-releasing organic microemulsified acid pipe-freeing agent has been developed to deal with this problem. Surfactants and acids were carefully selected to prepare the pipe-freeing agent. The optimized composition of the pipe-freeing agent is as follows: AQAS∶NP = 2∶1, n-butanol∶n-octanol = 1∶1, water phase ∶oil phase = 23∶77, secondary surfactant∶primary surfactant = 1∶3, and acetic acid∶hydrogen fluoric acid = 3∶1. The pipe-freeing agent is a water-in-oil (W/O) microemulsified acid, and the embedding rate of this pipe-freeing agent is 23%. Formation factors remarkably affecting the performance of the pipe-freeing agent is temperature. At high pressure high temperature, the release rate of the acid is increasing. Drilling fluid factors greatly affecting the performance of the pipe-freeing agent include weighting agent, clay and ultra-fine calcium carbonate. The microemulsified acid can completely lose its emulsion stability and turn into a suspension by the weighting agent, clay and ultra-fine calcium carbonate used in the drilling fluid. Field application of this pipe-freeing agent on five wells has shown that it can be used to free stuck pipes of many types such as pressure-differential pipe sticking, pipe sticking by settling drilled cuttings and bridging etc., and the success rate of first try in freeing the stuck pipes is 100%.
Application and Mechanisms of Dopa Biomimetic Lubricant in Water Based Drilling Fluids
YANG Xukun, JIANG Guancheng, HE Yinbo, DONG Tengfei
2023, 40(6): 749-755, 764. doi: 10.12358/j.issn.1001-5620.2023.06.008
Abstract(285) HTML (111) PDF (4396KB)(94)
A Dopa biomimetic lubricant L2,3 for water based drilling fluids was developed with Dopa which has strong adhesive capacity in water environment, and this new lubricant is expected to be able to solve the problem of poor lubrication performance of ester lubricants in water because of the poor adhesivity of the esters on the surfaces of drilling tools in water. Another lubricant L2,5 with phenolic hydroxyl groups on different positions in the molecules of the lubricant was also synthesized and characterized by FT-IR and 1H NMR. The lubricity and wear resistance of the two lubricants were evaluated using extreme pressure lubricity tester, mud cake adhesion coefficient tester, four-ball friction tester and SEM. L2,3 in sodium bentonite (Na-BT) based fluid has the best lubricity, the coefficient of friction (COF) of an Na-BT based fluid treated with 1% L2,3 is as low as 0.07, a percent reduction of COF of 87.7%, and the wear scar diameter (WSD) is 0.587 mm. At temperatures less than 210 °C, the base fluid has good lubricity and does not foam. The L2,5 lubricant, on the other hand, has goo lubricity in fresh water, with COF of 0.1, while in Na-BT based fluid, the lubrication film of the lubricant is unable to resist the shear of the clay particles and is damaged, and the COF is 0.57, a value close to the COF of the blank base fluid. Analyses of the components and thickness of the lubrication film with XPS show that the phenolic hydroxyl groups help enhance the adhesion ability of the lubricant on the surfaces of the metals, hence improving the lubricity and wear resistance of the lubricant. The performance of the lubricants has a relation to the type of the phenolic hydroxyls. The L2,3, which contains catechol structure, can form a dense organic film of 80 nm in thickness on the surfaces of a metal through bidentate metal coordination bonds, while L2,5 containing para-hydroxyl groups can only form a film of less than 20 nm on the surfaces of the metal. Compared with the L2,5 lubricant, the L2,3 lubricant has better lubricity and wear resistance because it can form more stable bidentate metal coordination bonds on the surfaces of metals.
Study on Downhole Drilling Fluid Colling Technology Based on Surface Cooling
LIU He, YU Guowei, YU Chen, ZHENG Feng, CHEN Wenbo, WANG Chao, ZHENG Shuangjin
2023, 40(6): 756-764. doi: 10.12358/j.issn.1001-5620.2023.06.009
Abstract(248) HTML (101) PDF (3204KB)(111)
Presently there are two core problems existed in downhole drilling fluid colling technology, i.e., the necessities of performing drilling fluid cooling and the real time control of the temperature of the downhole drilling fluid. Based on the borehole heat transfer model, the effects of drilling fluid cooling parameters on the downhole temperature are investigated. Based on the non-dominated sorting generic algorithm with elitest strategy, a drilling fluid cooling parameter optimization model is established, and a method for calculating the cooling limit of downhole drilling fluids is constructed. Using the model and the method, the necessity of performing cooling operation can be evaluated. Then, based on the borehole heat transfer model, the quantitative relationship between surface cooling and downhole cooling is investigated, and it is found that a simple linear relationship exists between the change of downhole temperature and the change of surface injection temperature. Based on these relations obtained and the PID control algorithm, a method for real-time control of downhole drilling fluid temperature is developed. The aforementioned models and methods are then verified using data obtained from an example well. The verification shows that using the optimized model of cooling parameters, the downhole cooling limit obtained is 17 ℃ lower than the cooling limit obtained from the non-optimized model. Also, the downhole temperature control method based on PID control can be used to quantitatively control downhole temperature in a real-time manner., thereby minimizing energy consumption of the surface cooling equipment and ensuring the downhole temperature to quickly reach the designed level.
Study on Prediction Model for Drilling Fluid Classification Based on XGBoost
HUA Lulu, CAO Xiaochun, WANG Jincao, WANG Jin, JIAO Yuxuan
2023, 40(6): 765-770. doi: 10.12358/j.issn.1001-5620.2023.06.010
Abstract(230) HTML (105) PDF (2666KB)(71)
A model for predicting the type of a drilling fluid system was established using a new machine learning method based on the principles of mud system design and by referencing the actual drilling fluid designs. By one-hot coding of the data concerning the classification of drilling fluid systems, twenty parameters for predicting the type of a drilling fluid were selected through grey relation analysis. Of these parameters pressure has the highest correlation degree, which is 0.8233. The selected geological parameters and engineering design parameters were used based on an extreme gradient boost (XGBoost) algorithm to predict the types of 4 drilling fluids. The results show that the accuracy of the training sets of the 4 drilling fluids are all 100%, the average percent accuracy of the test sets is 99.89%, the precision 99.97%, the recall rate 98.89%, and the F1 value 0.98. Applying this model to the M block in the Shengli Oilfield, the classification results met the drilling requirements, and was of help in selecting the suitable drilling fluids. This study has provided a help to the intelligent design of drilling fluid.
Identifying Types and Analyzing Main Controlling Factors of Mud Losses Using a Method Integrating LightGBM Algorithm and SHAP
CHEN Lin, LU Haiying, WANG Zehua, LI Chengli, YANG Heng, ZHANG Maoxin, XU Tongtai
2023, 40(6): 771-777. doi: 10.12358/j.issn.1001-5620.2023.06.011
In the Kuche piedmont structure in the Tarim Basin where complex geological conditions prevail, frequent mud losses into the salt/gypsum formations and the target zones cause huge economic losses. To identity the types of the mud losses, a judgement model is established using the LightGBM algorithm. The LightGBM model, with good discriminative performance, has average recall rate of 85%, precision of 91% and F1-Score of 86.7%. In analyzing the types of mud losses, the interpretable machine learning techniques based on SHAP values are adopted to analyze a single mud loss event and all mud loss events as a whole. The SHAP value method, which is based on Cooperative Game Theory, breaks down the occurrence of mud loss events into contribution values of different features, and explains the effects of each feature on the mud loss event. Studies show that the main factors affecting mud losses include the difference between the mud density and the equivalent density calculated from the fracture pressure of the formation, the flow rate of mud, the well depth and the formation drilled. For the geology of the salt/gypsum formations and the target zones in the Kuche piedmont structure, the effects of the formation geology and the vertical distribution of the interlayer are in depth analyzed. This study enables the field engineers to fast and accurately determine the types of mud losses, and provides a strong support to the design of measures for preventing and controlling mud losses.
A Cement Slurry for Large Temperature Difference in Wells of Ten Thousand Meter Depth
LIU Jingli, LIU Pingjiang, REN Qiang, LIU Yan, PENG Song, CAO Hongchang, ZHANG Wenyang, CHENG Xiaowei
2023, 40(6): 778-786. doi: 10.12358/j.issn.1001-5620.2023.06.012
Abstract(411) HTML (176) PDF (3445KB)(74)
In cementing operation in ultradeep wells with long cementing sections, there is a large difference between the temperature at the top of the cement slurry and that at the bottom of the cement slurry. The low temperature at the top of the cement slurry retards the development of the strength of the set cement. To solve this problem, an early strength additive named EDTA-LDH (EDTA intercalated hydrotalcite) was developed through water solution polymerization. A cement slurry for working at big temperature difference conditions was formulated with EDTA-LDH. Laboratory experimental results show that this early strength additive has retarding effect to some extent; at a concentration of 2.0% EDTA-LDH and 4.0% retarder, a cement slurry has thickening time of 509 min at 240 ℃. After aging at 60 ℃ for 1 d or at 30 ℃ for 6 d, the cement slurry has compressive strengths of both greater than 7 MPa, and experiences maximum temperature difference of 210 ℃. The use of EDTA-LDH is beneficial to the development of the strength of the cement slurry column in low temperature without affecting the adjustability of the thickening time of the cement slurry. This early strength additive can work normally at temperatures above 300 ℃, and is suitable for cementing wells with large temperature differences.
Effects of Thermal Physical Parameters on Circulation Temperature of Cement Slurries
ZHENG Rui, GUO Yuchao, ZHANG Chunhui, ZHANG Hua, WANG Guifu
2023, 40(6): 787-792. doi: 10.12358/j.issn.1001-5620.2023.06.013
Abstract(381) HTML (150) PDF (2823KB)(62)
In well cementing operation, to ensure that the cement slurry is safely pumped int the hole, the cement slurry shall have an appropriate thickening time. The circulating temperature of the cement slurry is one of the important factors affecting the thickening time of the cement slurry. The methods for calculating the circulating temperature of a cement slurry in the API Recommended Practice do not satisfy the need for calculating the circulating temperature in different areas and different borehole conditions. Thus, an unsteady state flow heat transfer model is established. By measuring the thermal physical parameters, the coefficients of heat conductivity and specific heat capacities of the drilling fluid, the casing strings, the rocks and the cement slurry are determined, and the temperature field of the cement slurry during injection and displacement is thus simulated. The simulation results show that increasing the coefficients of heat conductivity of the cement slurry and the spacer fluid reduces the circulating temperature of the cement slurry. Decreasing the coefficients of heat conductivity of the casing string and the rocks, the circulating temperature of the cement slurry changes in less than 1 ℃. Data acquired from the Zhejiang Oilfield and the Tarim Oilfield show that the difference between the measured well cementing temperatures and the simulated well cementing temperatures is less than 5 ℃, indicating that the simulated data is accurate and has good consistency with the measured data. Studies on the factors affecting the circulating temperatures of a cement slurry during injection and displacement in well cementing operations provide theoretical supports to the design of the properties of the cement slurry, thereby ensuring the efficient and safe well cementing operations.
Method of Evaluating the Capacity of Gas Channeling Prevention of a Cement Slurry in Gelling Transition-State
ZHU Haijin, GAO Jichao, ZOU Shuang, WANG Shengming, LI Pengxiao, ZOU Jianlong
2023, 40(6): 793-797, 805. doi: 10.12358/j.issn.1001-5620.2023.06.014
Gas channeling in annular space is one of the technical difficulties encountered in oil/gas well cementing. Based on the theory of cement slurry weightlessness, the relationship among the effective fluid column pressure of the cement slurry, the internal structural resistance and the formation fluid pressure is analyzed to determine the timing of channeling detection. By continuously collecting data on the changes of the pore pressure in the cement slurry, it can be determined whether the gas has overcome the internal structural resistance of the cement slurry to cause gas channeling, and this leads to the invention of a new method for evaluating the anti-gas-channeling capacity of a cement slurry in transitional gelling state by direct observation. Using this method, the channeling of several cement slurries is studied. The study results show that: 1) bare cement slurry is almost unable to resist gas channeling; 2) by introducing appropriate amount of filter loss reducers, the anti-channeling capacity of a cement slurry can be slightly improved, with only limited effect; the cement slurry can only resist gas channeling pressure of 50 psi (0.344 MPa); 3) changes in the type and concentration of the anti-gas-channeling agent lead to different anti-channeling capacity of a cement slurry. Generally speaking, cement slurries treated with different anti-channeling agents can stand channeling pressures in a range of 100 – 200 psi (0.689–1.379 MPa). Some anti-channeling agents exhibit higher capacities of anti-channeling by increasing their concentrations in the cement slurries, with limits of performance based on their inherent characteristics. The method described in this paper is easy and simple, and has good practicality and repeatability. It can be used to compare the performances of different anti-channeling agents, and to provide reference to the design of anti-gas channeling cement slurries.
A Lost Circulation Control Slurry with Solidifying and Bridging Functions
JIANG Xu, LIU Huajie, MA Xiaolong, ZHAO Jiansheng, SU Qianrong, BU Yuhuan, GUO Shenglai
2023, 40(6): 798-805. doi: 10.12358/j.issn.1001-5620.2023.06.015
Bridging lost circulation control slurries are difficult to be bonded with the walls of leaking channels during mud loss control, and are therefore generally squeezed back into the borehole. Thixotropic cement slurries as a kind of lost circulation material, have low fracture pressure, and are thus incapable of controlling severe mud losses. Based on the studies performed on the thixotropic cement slurries and bridging lost circulation control materials, the two kinds of lost circulation control materials are compounded together to form a new lost circulation control material with the advantages of both. By carefully selecting other additives, a new thixotropic cement slurry with good rheology and thixotropy is formulated. In the new cement slurry, the addition of a new thixotropic agent LTA-1 has only weak effect on the thickening time of the cement slurry, and LTA-1 can improve the compressive strength of the cement slurry. The composition of the bridging lost circulation control slurry is determined through “experiment on a slit”. Based on the requirement of thickening time and strength, the final composition of the lost circulation control slurry is determined to be thixotropic cement slurry∶bridging slurry = 2∶1. This lost circulation control slurry can be used to control mud losses through 3 – 5 mm artificial fractures simulating fractured formations and control mud losses through large pores simulated with 6 mm roller balls. The lost circulation control slurry can form a layer of barrier on the surface of the simulated formations with a pressure bearing capacity of greater than 14 MPa. The use with of this lost circulation control slurry satisfies the need of safe operations. The good thixotropy and lost circulation control capacity of this lost circulation control slurry are of great help to the control of mud losses in drilling complex formations.
Effects of Rock Asphalt with Surface Grafted C—S—H on Mechanical Properties of Set Cement in High Temperature Wells
WANG Jia, ZHANG Chunmei, ZHANG Ye, CHENG Xiaowei, MEI Kaiyuan
2023, 40(6): 806-814. doi: 10.12358/j.issn.1001-5620.2023.06.016
This paper discusses the studies conducted on the effects of rock asphalt with surface grafted C—S—H on the mechanical property and microstructure of set cement used to seal high temperature oil wells. Measurement of the mechanical property and characterization of the microstructure of set cement samples were done with pressure testing machine and XRD, TG, SEM and EDS, respectively. Study results obtained in laboratory experiments show that compared with pure set cement, the set cement containing 1% nonmodified rock asphalt had its 3-day compressive strength reduced by 2.98%, while the set cement containing 1% rock asphalt which surface grafted C—S—H had its 3-day compressive strength increased by 4.26%. Phase analysis and TGA experiment results show that the addition of the rock asphalt with surface grafted C—S—H into the cement slurry does not cause change of the type of the hydrational products. The weight loss of a set cement containing 3% rock asphalt with surface grafted C—S—H is 1.01% higher than the weight loss of the pure set cement after aging for 3 days, indicating that rock asphalt with surface grafted C—S—H has accelerated the hydration process of the cement. Analyses of the micromorphology and element composition of the set cement indicate that the nonmodified rock asphalt thermally disintegrated at 180 ℃ and the particles of the asphalt were broken into pieces, while the rock asphalt with surface grafted C—S—H has formed an Si-rich layer around its surface, protecting the rock asphalt from generating air holes inside it and the asphalt particles are therefore not easy to break down. Furthermore, comparing the set cement containing nonmodified rock asphalt and the set cement containing rock asphalt with surface grafted C—S—H, it is found that the C element content at the interfaces of the former is 29.14% higher than that of the latter, and the C element content in the body of the former is 13.76% higher than that of the latter.
Study on the Imbibition Law and Mechanism of Strong Emulsification System Based on the Experimental and Numerical Assessment
HOU Xiaoyu, ZHOU Fujian, YAO Erdong, WANG Xiukun
2023, 40(6): 815-826. doi: 10.12358/j.issn.1001-5620.2023.06.017
Surfactants are usually added to the fracturing fluids to enhance the imbibition between fractures and matrix, which is an important measure to improve oil recovery. The popular perspective believes that altering water-wet conditions and keeping a relatively high IFT value are the keys to achieving the imbibition process. Recently, both indoor experiments and oilfield practice have shown that the surfactant systems with ultra-low IFT can also achieve imbibition and effectively recover oil from the matrix. For the problem that the imbibition mechanism of ultra-low IFT system is still unclear, the wettability alteration system, ultra-low IFT system, and emulsification system are constructed, the characteristics of imbibition systems and imbibition recovery are clarified, the oil-water transport patterns and dominant mechanisms of wettability alteration system and ultra-low IFT system with excellent emulsification are revealed by using mathematical models. The results show that the applicability range of the wettability alteration system and ultra-low IFT system with excellent emulsification is different. The wettability alteration system has better imbibition effects under 0.1 mD, but the ultra-low IFT system with excellent emulsification performs better under 0.01 mD and 0.001 mD. The imbibition process of the wettability alteration system is a layer flow pattern dominated by capillary force, the rate at which the wetted phase fills the pores decreases rapidly with the decrease of permeability, and the imbibition recovery decreases significantly from about 45% to 18%. The micro-nano emulsions can be formed by the ultra-low IFT system with excellent emulsification, which has a special emulsification and diffusion mechanism. In the early stage, oil is mainly recovered by emulsification and diffusion, in the late stage, the layer flow pattern of IFT reduction and wettability alteration gradually works, and the imbibition recovery decreases from about 38% to 23%. The emulsification and diffusion mechanism of the ultra-low IFT system with excellent emulsification is suitable for the imbibition of tighter reservoirs, and has a broad application in fracturing and stimulation of tight reservoirs.
The Development and Characterization of a High Efficiency Pyrimidine Derivatives Corrosion Inhibitor for Acid Jobs
XIA Yulei, LAN Jianping, YAO Wei
2023, 40(6): 827-834. doi: 10.12358/j.issn.1001-5620.2023.06.018
Using the environmentally friendly biomaterial 4-amino-6-hydroxy-2-mercaptopyrimidine (AMSN) and the anhydrous N,N-dimethylformamide (DMF), a high performance pyrimidine derivative ASMF, which is a corrosion inhibitor for acid job, has been developed through one-step reaction. Characterization by IR spectroscopy and element analysis show that the reaction gave high purity product. Studies on the factors affecting the yield of ASMF show that the optimum molar ratio of AMSN and DMF is 1:1, the reaction temperature should not be higher than 170 °C, and the reaction time should be at least 4 h. The yield of ASMF is relatively high under these conditions. An ASMF sample produced in an experimental production showed excellent corrosion inhibitive capacity in high concentration (>20%) acid solutions, and it functioned at temperatures as high as 170 °C. ASMF shows superior corrosion inhibitive performance even at concentrations less than 0.2%. The electrochemical polarization curve of ASMF shows that ASMF can effectively inhibit the electrode reactions taken place at the cathode and anode during a corrosion process, and it is a mixed corrosion inhibitor which shows cathode inhibition property. Impedance test results show that ASMF has good corrosion inhibition efficiency, at a concentration of 0.2%, the corrosion inhibition efficiency of ASMF is 99.85%. Core damage evaluation test results show that ASMF shows only weak damage to the permeability of cores flooded with the ASMF solution, and ASMF is environmentally friendly. It can be concluded that the product developed is an environmentally friendly high performance pyrimidine derivative corrosion inhibitor for acid jobs