2019 Vol. 36, No. 6

2019, 36(6)
2019, 36(6): 795-798.
Advances of Cuttings Transport Models During Oil Drilling
LIU Chengwen, LI Zhaomin
2019, 36(6): 663-671. doi: 10.3969/j.issn.1001-5620.2019.06.001
With the increasing number of inclined wells and horizontal wells, the hole cleaning has become one of the key technologies and difficulties in oil drilling. In the past 60 years, a lot of experiments and theoretical studies have been done on cuttings transport in drilling process, and more knowledge has been gained on this subject. Some models have been established, which provides an effective basis for the design of hydraulic parameters in actual drilling process. In this paper, the empirical models and layer theoretical models describing the cuttings transport rule are systematically summarized, and the models for cuttings transport with foam are summarized. On the basis of this, the development trend of the model is prospected. Finally, the research proposals are given, which will provide references for further research on cuttings transport in the future.
Status-quo of Study on the Methods of Evaluating Formation Damage by Shale Gas Reservoir Working Fluids
WANG Rui, WU Xinmin, MA Yun, ZHANG Ningsheng
2019, 36(6): 672-678. doi: 10.3969/j.issn.1001-5620.2019.06.002
Presently in shale gas development in China, little attention has been paid to the effects of working fluid on the production of shale gas, as well as the damage and protection of shale gas reservoirs. All these are closely related to the production evaluation and the R&D of fracturing techniques and high efficiency working fluids. This paper analyzes the following issues about shale gas development, such as how working fluids damage the transfusion of shale gas, the diffusion, adsorption and desorption of shale gas, the progresses made in studying the methods of evaluating damage to shale gas production. Types of shale gas reservoir damage include damage by the sensitivity of the reservoir formations, damage by the working fluids, damage removal during flowback and imbibition, damage of adsorption/desorption and diffusion of shale gas by the working fluids, as well as the damage to the mass transfer of shale gas by the working fluids. Further discussed in this paper is the parameters used in evaluating shale gas reservoir damage. Based on the analysis, problems waiting to be resolved in this field are presented.
Study on High Temperature Delayed Crosslinking PAM Gel LCM
YAN Bangchuan, JIANG Guancheng, HU Wenjun, XIANG Xiong, DENG Zhengqiang
2019, 36(6): 679-682. doi: 10.3969/j.issn.1001-5620.2019.06.003
A hot melt adhesive delayed initiator was developed making use of the thermoplastic property of hot melt adhesive. This delayered initiator was then used to develop a high temperature delayed crosslinking polyacrylamide (PAM) gel lost circulation material (LCM) using acrylamide and N,N'-methylene bisacrylamide as the monomers. The high temperature delayed crosslinking LCM was characterized by IR spectroscopy and SEM, and its gel-forming time, plugging capacity and high temperature resistance were all tested. The experimental results showed that the initiator was successfully coated with the hot melt adhesive. Compared with the blank sample, the high temperature delayed crosslinking LCM can effectively delay the gel forming time, making the gel forming time adjustable between 1 h and 4 h. The LCM has excellent plugging performance, it effectively plugged a fracture of 4 mm at elevated temperatures under 700 psi or higher pressure working on the fracture. The LCM also has high temperature resistance, after hot rolling 5 d at 150℃, only 5% of the gel was broken. This high temperature delayed crosslinking gel LCM can be used to effectively stop severe mud losses to fractured formations.
Calculation of the Rheological Parameters of Drilling Fluids with Particle Lost Circulation Materials
LIU Kecheng, XU Shengjiang, RONG Kesheng, WANG Gui, GONG Jiaqin, PU Xiaolin
2019, 36(6): 683-688. doi: 10.3969/j.issn.1001-5620.2019.06.004
Addition of lost circulation materials (LCMs) while drilling in a drilling fluid will inevitably affect the rheology of the drilling fluid in circulation. The clearance between the rotator and the stator of an API standard viscometer is too narrow to measure the rheology of a drilling fluid containing coarse LCMs. To address this problem, a method of calculating the rheological parameters of a drilling fluid containing particle LCMs was developed based on the combination of laboratory experiment and inverse problem mathematical model. Using the method, the viscometer readings and the rotational speeds can be turned into a relationship between shear stress and shear rate. Laboratory experimental results showed that the calculation method is reliable, a KCl-polymer mud containing particle LCMs had a rheological curve conforming to H-B model. Increasing the concentration of the LCMs in the drilling fluid significantly affected the rheological parameters of the drilling fluid. Attention should be paid to the fact that particle size and concentration of LCM both have significant effects on the rheology of the drilling fluid.
Synthesis and Evaluation of a Low Viscosity Gelling Agent for Water Base Drilling Fluids
CHU Qi, SHI Bingzhong, LI Tao, LI Sheng, TANG Wenquan
2019, 36(6): 689-693. doi: 10.3969/j.issn.1001-5620.2019.06.005
A new zwitterionic hydrophobically associating polymer PAADDC has been synthesized by radical polymerization using monomers such as acrylamide (AM), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), dimethyl diallyl ammonium chloride (DMDAAC), 3-dimethyl (methacryloyloxyethyl) ammonium propane sulfonate (DMAPS) and a cetyl monomer (C16-D). PAADDC was developed for improving the cuttings carrying capacity of water base drilling fluids at controlled viscosity. The PAADDC synthesized was characterized by FT-IR and 1HNMR, and its molecular weight was determined by static light scattering (SLS) method. Drilling fluids treated with 0.2% PAADDC, after aging 16 h at 100℃, had properties as follows:AV=18.5 mPa·s, PV=11.5 mPa·s, YP=7 Pa and YP/PV=0.61 Pa/mPa·s. This drilling fluid was resistant to high temperatures to 160℃. Compared with other filter loss reducers, PAADDC has better thermal stability and better suspending performance at controlled viscosity. In aging test at 60-180℃, the YP/PV ratio of the drilling fluid was decreasing with increase in the concentration of PAADDC. ESEM and AFM examination of the molecular behavior of PAADDC showed that in solution PAADDC forms a continuous 3D network structure, which is taken as the main factor of obviously increasing the shearing strength of the drilling fluids.
Preparation and Performance of a High Temperature Modified Starch Filter Loss Reducer
ZHANG Yaoyuan, MA Shuangzheng, CHEN Jinding, LAN Wenming, LI Huayong, WANG Guanxiang
2019, 36(6): 694-699. doi: 10.3969/j.issn.1001-5620.2019.06.006
A new modified starch, St-AANDP, has been developed to address the deficiency of high temperature resistance of modified starch presently in use. Aimed at enhancing the rigidity of the molecules, the new modified starch was synthesized with the following chemicals through enzyme catalysis reaction:acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), dimethyl diallyl ammonium chloride (DMDAAC), N-vinyl pyrrolidone (NVP), potassium 2,5-dihydroxy benzenesulfonate (PDHBS) as the monomers, and horseradish peroxide (HRP) as the catalyst. A reference modified starch with no benzene ring, St-AAND, was also synthesized at the same reaction conditions. Test on the filtration control performance of the two synthesized modified starches showed that a drilling fluid sample treated with 1.0% St-AANDP had API filter loss of only 5.2 mL and HTHP filter loss of 26.2 mL after aging 16 h at 140℃. The filtration rate of St-AANDP treated drilling fluids increased only when the aging temperature was increased to above 160℃. St-AANDP works normally in salt saturated drilling fluids, and has filtration control performance that is superior to St-AAND. The reason for st-AANDP to have better filtration control performance than St-AAND is, based on the measurement of adsorption capacity and on the observation of the micromorphology of mud cakes, the introduction of benzene rings into the backbone of the starch molecules.
Study on Bit Balling in Drilling with Silicate Drilling Fluid
YAO Qian, XU Mingbiao, YOU Fuchang
2019, 36(6): 700-705. doi: 10.3969/j.issn.1001-5620.2019.06.007
Silicate drilling fluid is always used to drill mudstone and shale formations because of its excellent inhibitive capacity. A drawback of the silicate drilling fluid is the ease of bit balling. By analyzing the causes of bit balling using silicate drilling fluid, a laboratory experiment was designed to study the factors affecting the bit balling tendency of using silicate drilling fluid. In the experiment, mud balls of 6-10 mesh, made from bentonite, were used to simulate drilled cuttings. Steel balls of 25 mm and aging cells were used to simulate the conditions prevailing downhole. Several factors, such as the concentration of silicate, the module of the silicate, bentonite concentration, KCl concentration and addition of different bit balling preventing agents were studied for their effects on the occurrence of bit balling. The experimental results showed that the effect of the module of the silicate on bit balling can be ignored. The likelihood of bit balling increased with increase in the concentration of silicate; when the concentration of silicate was more than 9%, the severity of bit balling did not change greatly anymore. The concentration of silicate was suggested to be between 3% and 5%. With the increase of the bentonite content, the diameters of the mud balls reduced first and then increased. When 1% bentonite was used in the mud, the diameter of the mud balls became minimum. KCl at certain range of concentration can mitigate the occurrence of bit balling; excessive use of KCl on the other hand accelerate the occurrence of bit balling. The optimum concentration of KCl was 3%-6%. 3% WETMINE (a bit balling preventing agent and fast drilling agent) in the silicate drilling fluid can effectively prevent the occurrence of bit balling on the surface of the steel balls. Taking into account the rheology of the drilling fluid, the concentrations of the key additives used in the silicate drilling fluid were determined to provide a reference for selecting suitable additives for the silicate drilling fluid.
The Environment Protection Property of a Natural Rock Asphaltene for Oil Base Drilling Fluids
TANG Lingjuan, LIU Chao, WU Weilin, WANG Min, LIU Haobing, LU Fuwei
2019, 36(6): 706-710. doi: 10.3969/j.issn.1001-5620.2019.06.008
To save the operation cost, some low-cost filter loss reducers such as natural rock asphalt have been used in environmentally friendly oil base drilling fluids. The environmental protection performance of these filter loss reducer has been evaluated by examining the polycyclic aromatic hydrocarbon contents and performing acute biotoxicity test. The evaluation showed that there are no carcinogenic polycyclic aromatic hydrocarbons in the natural rock asphalt. Drilled cuttings contaminated with a white oil base drilling fluid containing 3% natural rock asphalt has an EC50 of 104,751 mg/L, satisfying the environmental protection standards. Analyses of the composition of the asphalts showed that natural rock asphalts contain no low molecular weight saturates and aromatics; they contain 13.83% resins and rigid asphaltenes. All the components of the natural rock asphalt become part of the mud cakes to reduce filtrate rate. Oil base drilling fluids treated with natural rock asphalt have filtration rate that is less than 3.7 mL at 150℃ and less than 4.0 mL at 200℃. Natural rock asphalt is an environmentally friendly filter loss reducer with a stable capability of controlling the filtration rate of environment protection oil base drilling fluids.
How to Deal with High Concentrations of Barium Salt Encountered when Drilling with Oil Base Drilling Fluids
GE Lian, CHEN Huabing, XU Xinghua, SONG Fang, ZHANG Yaping
2019, 36(6): 711-715. doi: 10.3969/j.issn.1001-5620.2019.06.009
Crystal scales were found at the diameter changing spots inside drill strings in Sichuan Basin during drilling with oil base drilling fluids. The scales blocked the circulation channel, resulting in pump overpressure or even pipe sticking, lost circulation and blowout. The scales were studied with water analysis and EDS to determine the main elements in them, and it was found that barium ions and titanium ions are the main metal ions forming the scales. By comparing with the drilled formation rocks and barite used to increase the density of the mud, it was determined that soluble salts had been drilled. These salts dissolve at high temperatures downhole and crystalize and separate out of the drilling fluid at low temperatures when circulate out to the surface. A salt re-crystallization inhibitor and a scale inhibitor for high valence metal salt scaling were selected through laboratory experiment. These additives were used on the Well ST-6, and were found compatible with the oil base drilling fluid used. Drill string block by the scales was successfully resolved. As a new technology for ultra-deep natural gas exploration and development in Sichuan Basin, it is of field application value.
A High Density Undersaturated Saltwater Drilling Fluid for Salt and Gypsum Drilling in Well ZQ2
ZHU Xuefei, SUN Jun, SHU Yiyong, XU Sixu, ZHOU Huaan
2019, 36(6): 716-720. doi: 10.3969/j.issn.1001-5620.2019.06.010
Well ZQ2 is an exploratory well located at the Qiu-2 substructure of the Qiulitage Structure in the Kuche sag. This well penetrated the mudstone Jidike Formation-Kumugeliemu Group (N1j2 -E1-2km1) which are buried at depths from 4545 m to 5827 m. This section is characterized by long salt/gypsum formations, high content of gypsum, high formation pressure, soft mudstones embedded with salt and unconsolidated soft high argillaceous content high water content rocks. The diameter of the hole penetrating this section is φ333.375 mm. This section was previously designed to drill with oil base mud, and was then changed to water base mud. High-and low-pressure formations exist in the same interval. All these challenges demand more of the water base drilling fluid to be used. An undersaturated polymer sulfonate drilling fluid was prepared using a sodium polyallyl sulfonate filter loss reducer MYK, a modified plant gum encapsulating inhibitor NXX and an organic salt Weigh2 which was first used to improve the undersaturated sulfonate drilling fluid to high density undersaturated polymer sulfonate drilling fluid. This drilling fluid have shown itself strong inhibitive capacity, high resistance to salt and gypsum contamination, stable properties and simple maintenance of rheology. Drilled cuttings acquired by the mud loggers were accurately relevant to the formation being drilled. The rheology of this drilling fluid during drilling was also much easier to control than the rheology of the drilling fluids used nearby. Application of this drilling fluid in drilling the well ZQ2 was a success, without encountering problems encountered when using other undersaturated drilling fluids, such as the use of thinners which leads to "adding mud-dumping mud-adding mud again, viscosifying-thinning-viscosifying". Using this drilling fluid, the salt/gypsum formations were successfully and safely drilled through, borehole wall was stable during drilling, wireline logging and casing running were successful at the first try. This drilling fluid technology has provided the base for casing program optimization in the Kuche sag.
Drilling Fluid Technology for Long Open Section of the Third Interval of the Ultra-deep Well SHBP-1
LIU Xianghua, CHEN Xiaofei, LI Fan, JIN Junbin
2019, 36(6): 721-726. doi: 10.3969/j.issn.1001-5620.2019.06.011
Based on experiences obtained previously, downhole troubles such as borehole wall instability and mud losses may be encountered in drilling the well SHBP-1. By analyzing the roots of the downhole troubles and the technical difficulties, a set of measures to deal with the downhole troubles were formulated. A highly inhibitive drilling fluid was formulated with inhibitive agents KCl and SMJA, mosaic membrane forming agent SMNA-1, nanometer plugging agent SMNF-1. These additives greatly enhanced the inhibitive capacity, plugging performance and HTHP filtration control ability of the drilling fluid. Field operation showed that the rheology of this drilling fluid was easy to control, and the inhibitive capacity of the drilling fluid can be achieved by maintaining 0.5% SMJA, 3% KCl and 2.5% SMNA-1 in the drilling fluid. When drilling mud loss formations, 2% SMNF-1 and ultra-fine calcium carbonate were added into the mud to control mud losses while drilling. With these measures, mud losses were avoided and the drilling operation was successfully completed. Percent hole enlargement of the third interval was only 3.49%. Borehole wall instability and mud losses in the third interval of the well SHBP-1 were thus resolved, providing a technical clue for other similar wells to be drilled in this area.
Study on Deodorizing Thermally Desorbed Oil from Oil Cuttings
LI Jianlin, WANG Changjun, ZHENG Yancheng
2019, 36(6): 727-730. doi: 10.3969/j.issn.1001-5620.2019.06.012
Oil cuttings produced in drilling with oil base drilling fluids are generally cleaned by thermal desorption method which, when heating the cuttings at high temperatures, produces bad smelled oils, seriously affecting the recycling and reusing of the oils obtained from the cuttings. Generally speaking, the bad odor comes from the volatile components with bad odor in the oils. Using oil distillation, the low-boiling-point components of the oils desorbed from drilled cuttings (obtained from field diesel oil base mud) were obtained and were deodorized with various methods, such as acidolysis, adsorption-centrifuging and distillation. The components of the oils desorbed from drilled cuttings were ascertained with GLC-MS and the bad odor from the thermally desorbed oils was analyzed. It was found that the content of the fraction in the thermally desorbed oils with boiling point less than 150℃ was 2.5%, and it is this light fraction who produces the bad odor. By acidolyzing or adsorption-centrifuging, the thermally desorbed oils still contain some low boiling point olefins, making the bad odor very difficult to remove. Distillation can effectively remove the low boiling point components from the thermally desorbed oils. The high boiling point components can be reused to mix oil base mud. This method is effective and efficient and is easy to perform in field application.
Curing Method and Study on the Mechanical Performance of Set Cement in Cementing Thermal Production Wells
GAO Fei, LI Yonggang, SUN Hao, LIU Yingmin, ZHANG Xingguo, GUO Xiaoyang
2019, 36(6): 731-736. doi: 10.3969/j.issn.1001-5620.2019.06.013
Simulation of downhole conditions in thermally producing heavy oils is of great importance to the determination of weather the set cement is able to satisfy the needs of thermal production. In the past, set cement was cured in a dry muffle oven with ultra-high temperatures, and this curing environment is not conforming to the conditions encountered downhole a heavy oil thermal production well, such as ultra-high temperature with vapor, and the set cement is constrained by casing string and formation. A new apparatus and a new method have been developed to make the conditions of laboratory experiment more similar or equivalent to the conditions prevailing downhole. With this new apparatus and the new method, the effects of the sample size and rate of heating on the compressive strength and integrity of set cement were studied at ultra-high temperatures with and without vapors. It was found that set cement of small size, low rate of heating and vapor are favorable to the uniform heating of the sample, and this in turn is favorable to the prevention of set cement fracturing by uneven heating and the maintenance of higher compressive strength and integrity of the set cement. It is thus suggested that, based on the study as said above, laboratory simulation should consider the effects of experiment conditions on the simulation results. It is also suggested that the process and parameters of vapor injection be optimized to reduce the rate of heating of set cement by the injection of vapor and to minimize the adverse effects of vapor injection on the set cement.
A Dissolution Accelerator of Acid-soluble Cement
LI Xiumei, WANG Ye, REN Qiang, WANG Qi, LUO Wenli, MA Jun, YANG Yuhang, YU Dazhou
2019, 36(6): 737-741. doi: 10.3969/j.issn.1001-5620.2019.06.014
Acid soluble cement is generally used in controlling severe mud losses. This technology is presently not mature. Acid soluble cements presently in use are mainly composed of cement and carbonate. Acid soluble cements are unable to satisfy the need of field application, some of them have acid solubility of less than 90%, while others need a long time to dissolve. It was found from the evaluation and analysis of the main factors affecting the acid solubility of cement that by optimizing the concentration and particle sizes of the carbonate added to the cement, the solubility of cement in acid can be increased to above 90%, still it is very difficult to increase the acid solubility to above 95%. To further increase the acid solubility of cement, a dissolving accelerator has been developed, which, when used with organic foaming agents and saturated alkanes (as stabilizer), can decompose at alkaline condition and a certain temperature to produce some small gas bubbles. These bubbles can be dispersed uniformly into a cement slurry and generate small dissolution holes in the gelled cement which serve as channels for acid dissolution. In this way the percent dissolving of cement in acid is greatly increased; 96% of the set cement can be dissolved in 30 min. The properties of the cement slurry in field application was easy to adjust. The application of this cement slurry not only solved the problem of severe mud losses, it also helped protect the reservoir from being damaged.
Study and Application of a New Poly Carboxylic Acids Drag Reducer
LING Yong, LIU Wenming, WANG Xiangyu, QI Ben, LI Xiaolin, YAN Zhenfeng, LIN Zhihui, MA Ruran
2019, 36(6): 742-748. doi: 10.3969/j.issn.1001-5620.2019.06.015
Cement slurry mixed in Iraq has strong thixotropy and poor pumpability in summer, and the drag reducers presently in use are unable to render the cement slurries good dispersibility. These problems have seriously affected the safe performance of well cementing. To address these problems, a new poly carboxylic acids drag reducer, BH-D301L, has been developed with monomers such as polyethylene glycol diacrylate, methacrylic acid, 2-acrylamide-2-methylpropanesulfonic acid and aromatic sulphonic acid etc. Using orthogonal experiment, the optimum conditions for the reaction was determined to be as follows:molar ratio of the monomers of 1:4:1:1, reaction temperature of 80℃, reaction time of 2 h, and initiator concentration of 0.4%. The reaction product was characterized by IR spectroscopy and gel permeation chromatography, and was tested for its general performance in different cement slurries in accordance with API RP 10B. Experimental results showed that by adding 0.5% and 1.0% of the drag reducer into a cement slurry formulated with fresh water and a cement slurry formulated with saturated saltwater, the rheology of the cement slurries were obviously improved. The compressive strengths and thickening time of the cement slurries satisfied the requirements of industrial standards. At simulated temperatures of 45-65℃, a high-density salt-containing cement slurry treated with 1.0% drag reducer had flow index of greater than 0.7 and consistency factor of less than 0.58 Pa·sn. The thixotropy of the cement slurry treated with the new drag reducer had thixotropy increased less obviously. Gel strength of the cement slurry was less than 3 Pa and 24 h compressive strength exceeded 14 MPa. The cement slurry treated with the drag reducer had thickening property and settling stability all satisfied the needs of well cementing job, and was successfully used in field operations.
Study and Application of a Technology for Evaluating Pressure Loss of Cement Plug
LIU Yang, CHEN Min, SHI Fangfang, LI Yinxue, XIAN Ming
2019, 36(6): 749-753. doi: 10.3969/j.issn.1001-5620.2019.06.016
Pressure loss of cement column after cementing often results in reduction of pressure exerted on the gas zones by the liquid cement slurry column. This pressure loss may cause underbalance of pressure to happen and hence gas channeling at the early stage of cementing. Accurate evaluation of the pressure loss is a key to the formulation of techniques regarding the extent of pressurization and WOC and to the success of well killing and prevention of gas channeling. Empirical formulas for calculating pressure loss of cement slurry and results obtained from apparatus presently in use for measuring pressure loss of cement slurry do not reflect the pattern of pressure loss of cement slurry in downhole conditions. To address these problems, an apparatus for evaluating the pressure loss of cement slurry at HTHP conditions was developed by scaling down the sizes of existed apparatus. With this new apparatus, experiments have been performed on the typical pressure loss behavior of cement slurries in vertical and horizontal wells. It was found that at time of initial gelling, the pressure exerted by a column of cement slurry with poor stability was possibly less than the pressure exerted by a column of water of the same height. When designing the value of pressure exerted at the annulus using empirical formulas, the designed pressure may not be able to balance the pressure inside the annulus, thereby resulting in gas channeling, or the designed pressure may be higher than necessary to fracture the formations. A new method was developed to segmentally calculate the pressure loss of a cement slurry. This new method was used in calculating the pressure loss of a high-pressure gas well in the Block Moxi-Gaoshiti in Sichuan Basin, providing helpful guide to the pressurization in annulus and WOC operations. The job quality of well cementing was certified and no gas channeling happened after well cementing.
Application of Thixotropic Early-setting Expanding Cement Slurry in Cementing Liner String in Block TAMBOCOCHA, Ecuador
LIU Yulong
2019, 36(6): 754-758. doi: 10.3969/j.issn.1001-5620.2019.06.017
Block Tambococha, as an important part of the famous "ITT" project, is located near the center of the Amazon tropical rainforest in Ecuador. The major reservoir NAPOM1 is a high porosity high permeability reservoir with buried depth of about 1 500 m. Poor liner cementing job quality has been met previously. To resolve this problem, the composition of the cement slurry was modified by changing the density of lead slurry and the consistency of the cement slurry, reducing the concentration of filter loss reducers and latex, and adding early strength thixotropic additives into the slurry. The cement slurry with modified composition had its thickening time, initial and final gelling time slightly shortened, while the gel strength was increased, and the gel strength of the cement slurry developed faster than the gel strength of the cement slurry prior to modification. Eight times/wells of application of this improved cement slurry gave 100% success rate of cementing job, more than 95% of the liner cementing job had high quality. The use of the cement slurry with modified composition resolved the problems encountered during cementing operation, such as active in-situ oil and water in the reservoirs and shallow oil bearing zones, providing a sound technical support to subsequent liner cementing operation.
Normal Spotting and Reverse Squeezing of Low-density Cement Slurries in Wells with Narrow Safe Drilling Windows
DING Zhiwei, LI Jiaqi, ZHAO Jingying, ZHANG Minghui, YIN Changsheng, HE Li
2019, 36(6): 759-765. doi: 10.3969/j.issn.1001-5620.2019.06.018
The φ273.05 mm section of the well Yingbei-1 (Southwest Oilfield) penetrated formations with widely distributed thief zones and active oil and gas zones. Low density low temperature cement slurries used in previous cementing operations had low strength and slow hardness development. To address these problems encountered, a high strength low density (1.23 g/cm3) cement slurry with high toughness and the ability of anti-channeling has been developed. This cement slurry has thickening time that is adjustable and fast developed gel strength. The strength of the cement slurry develops after 440 min at 62℃, and reaches the maximum value of 14.5 MPa after 24 h. The elastic modulus of the cement is 5.8 GPa. Using this cement slurry with other technical measures, such as contaminationresistant flushing spacer, software simulation, optimization of the structure of the cement slurry column, and normal spotting/reverse squeezing etc., the φ273.05 mm casing string was successfully and safely cemented. Rate of certified job was 85% and rate of quality job was 65%. The technology used in cementing the well Yingbei-1 has provided a technical reference for cementing wells with narrow safe drilling windows in southwest oil and gas field.
Synthesis and Performance of a Polymeric Thickening Agent for Weighted Fracturing Fluids
DAI Xiulan, LIU Tongyi, WEI Jun, WANG Meng
2019, 36(6): 766-770. doi: 10.3969/j.issn.1001-5620.2019.06.019
Weighted fracturing fluid is one of the effective methods to deal with high formation pressure encountered during fracturing operation. In mixing weighted fracturing fluids, normal guar gum will leave high concentrations of residues in the fracturing fluids, causing high formation damage. The VES type fracturing fluid has low temperature stability, therefore is unable to be used in high temperature environment. To resolve these problems, a supramolecular polymer BC40 has been synthesized with AM/CnDMAAC/NVP through water solution polymerization. By evaluating the intrinsic viscosity and solubility of the synthesizing products, and through orthogonal experiment and single-factor method, the optimum synthesis condition was obtained, as follows:the total concentration of the monomers of 30%, concentration of the initiator of 0.12%, temperature for the polymerization of 35℃, time for exhausting oxygen by introducing nitrogen of 1 h, and reaction time of 5 h. In a water solution weighted with sodium formate, BC40 performed very well as a viscosifier. Fracturing fluids of different densities mixed at 120℃ and 170 s-1, had apparent viscosity of more than 30 mPa·s after being sheared for 2 h, showing good high temperature shearing performance. The gel structure formed in these weighted fracturing fluids can all get broken after treatment with gel breaking agent at 95℃. The fracturing fluids, after gel breaking, had low surface tension and low residue contents, and therefore had low damage to the formations fractured.
Study on the Mechanisms of In-depth Acid Job of Atomized Acids in Fractured and Vuggy Reservoirs
SU Xuhang, QI Ning, WANG Yiwei, PAN Lin, XU Zhipeng
2019, 36(6): 771-776. doi: 10.3969/j.issn.1001-5620.2019.06.020
Fractured and vuggy reservoirs are developed with large amount of karst caves and fractures, and are of high heterogeneity. During acidizing operation, acid fluids will preferentially flow into the caves and fractures, increasing the size of the caves and affecting the extension of wormholes inside the rocks. In this paper, an acidizing technique with atomized acids that can be used to effectively develop fractured and vuggy reservoirs is presented. Atomized acids can effectively communicate the disconnected fractured and vuggy reservoir spaces, helping form good oil and gas flow channel. To clearly define the boundary of stable flow of oil and/or gas in wells acidized with atomized acids, simulation experiments with mist flow were performed and it was found that the most stable mist flow can be obtained at the following conditions:20℃, standard atmospheric pressure, gas injection rate of 60 m3/h, liquid injection rate of 20 mL/min and concentration of mist stabilizing agent (sodium dodecyl benzene sulfonate) 0.5%. Kinetic experiment of acid -rock reaction showed that at 130℃, rotational speed of 110 RPM and initial acid concentration of 15%, the reaction rate of rock-normal acid was 20.12×10-6 mol/(cm2·s), while the reaction rate of rock-atomized acid was only 1.87×10-6 mol/(cm2·s), less than the reaction rate of normal acid by an order of magnitude, indicating that atomized acids have excellent retardation performance. The corrosion rate of normal acids to N80 steel is 572.16 mm/a, while that of atomized acids to N80 steel is only 40.08 mm/a, less than one tenth of the corrosion rate of normal acids, indicating that atomized acids are quite less corrosive to tubular goods than normal acids.
Study and Application of an Easy-to-flowback and Water Block Preventive Slick Water Fracturing Fluid for Tight Gas Reservoirs
LIU Peipei
2019, 36(6): 777-781,788. doi: 10.3969/j.issn.1001-5620.2019.06.021
The tight gas reservoir in Jilin Oilfield, a low porosity and low permeability gas reservoir, is full of micrometer-and nanometer-sized pores with narrow pore throats and poor connectivity. Long period of development of this gas reservoir has resulted in reduction of formation pressures and productivity. Water block of the reservoir formations is aggravating and making flow back after fracturing more and more difficult. Swelling and migration of clay particles inside the formation caused blocking of the flow channels, further reducing the effective permeability of the reservoir and restricting the increase of oil recovery. A slick water fracturing fluid has been developed to address these problems. This slick water fracturing fluid is able to prevent water block and is easy to be flowed back after fracturing job. It is mainly composed of the drag reducer XY-205, a nanometer micro emulsion cleanup additive and the clay stabilizer XY-63. Laboratory experiments showed that this fracturing fluid has the properties of instant dissolving and low viscosity, which are beneficial to fast and continuous mixing. Friction reduced using this fracturing fluid was at least 70%. This slick water fluid has surface tension that is 40% lower than the surface tension of the slick water fracturing fluids used in other gas wells, indicating that the slick water is beneficial to the clean-up of the well after fracturing job. The slick water fracturing fluid is also useful in inhibiting clay swelling, the permeability of cores tested with this slick water fracturing fluid was only reduced by 9.45%, and the recovery of the permeability of the cores 24 hours after test was nearly 90%. Application of this slick water fracturing fluid on 4 wells gave 100% rate of success. Fracturing fluid flowed back was increased by a factor of 2. In well test, gas production rate was increased remarkably. This slick water fracturing fluid has good prospects of large-scale promotion and application
Development and Application of a Temperature Enhanced Highly Elastic Liquid Gel Temporary Plugging Agent
LIU Wei, ZHU Fanghui, YU Shuzhen, LI Qiongwei, ZHANG Zhenyun, DONG Xiaohuan, LI Mingxing
2019, 36(6): 782-788. doi: 10.3969/j.issn.1001-5620.2019.06.022
To address mud loss problems in low pressure gas wells, an elastic liquid gel plug EGL-1 has been developed using polyethyleneimine (PEI) as crosslinking agent. EGL-1 is able to remarkably enhance the pressure bearing capacity of formations and completely stop loss of fracturing fluids to minimize formation damage. The basic composition of EGL-1 is:2% SPAM (a high temperature polymer)+(1%-1.6%)PEI+0.02% stabilizer+water. Test and evaluation of EGL-1 showed that the new EGL-1 solution, after being seared at 200 s-1, had apparent viscosity of less than 350 mPa·s, indicating that EGL-1 has good pumpability. Test on the crosslinked EGL-1 showed that it had elastic modulus between 100 Pa and 470 Pa, and viscous modulus between 10 Pa and 60 Pa. The strength of the gel plug increases with temperature. Physical simulation experiment results showed that the compressive strength of the gel plug in fractured cores was at least 9 MPa, and the breakthrough pressure of flowback test was less than 1 MPa. The permeability recovery of the cores tested with the gel plug was 90% and pore plugging caused by the gel plug can be removed naturally. This gel plug has been successfully used in killing a low-pressure gas well penetrating paleo-carbonate formation. The successful application of EGL-1 can be used to kill similar low pressure gas wells with potential of fluid losses.
A Differential Pressure Activated Sealant: Preparation, Sealing Performance and Working Mechanisms
XING Xuesong, XU Lin, FENG Huanzhi, LIU Shujie, XU Mingbiao, CHEN Kan
2019, 36(6): 789-794. doi: 10.3969/j.issn.1001-5620.2019.06.023
Differential pressure activated sealant is a kind of sealant with self-adaptive sealing capacity. The application of this sealant is both easy and cost effective. It can be used to fast repair the integrity of oil and gas well strings. Four-factor four-level orthogonal experiment has been performed in laboratory with raw materials such as carboxylated butadiene-acrylonitrile latex (XNBRL), MgCl2, OP-10, VIS-B, to study the effects of the concentration of the latex, concentration of the activator, agitating time and rest time on the growth of the differential pressure activator particles and the microstructure of the activator. The dynamic sealing performance of the activator was evaluated and the differential pressure activated sealing mechanisms were analyzed. It was found that the morphology of the differential pressure activated sealant particles is regular, having a tiered spatial structure. The particle size of the sealant is less than 400 μm. Factors affecting the growth of the particles are in the following order:rest time > concentration of the latex > concentration of the activator > shearing rate. The sealant prepared can successfully seal a microfracture of 0.5 mm×0.8 mm×10 mm at 50℃ and 7.5 MPa. Based on the morphology of the particles, the molecular aggregation structure and the shear deformation behavior of the aggregated molecules, a physical-chemical coupling structure-activity model has been presented to describe the liquid-solid conversion behavior of sealing fluids under the differential pressure from microfractures. The model preliminarily reveals the selfadaptive reparation mechanisms of the differential pressure activated sealants.