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3 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
5 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
6 A New Fracturing Fluid with Temperature Resistance of 230℃
7 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
8 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
9 Progress in Studying Cement Sheath Failure in Perforated Wells
10 A Temperature Sensitive Expanding Microcapsule Anti-Gas-Channeling Cement Slurry
2 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
3 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
7 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
8 High Performance Water Base Drilling Fluid for Shale Gas Drilling
9 High Performance Water Base Drilling Fluid for Shale Gas Drilling
10 Study on Hydrophobic Nano Calcium Carbonate Drilling Fluid
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.
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.
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.
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.
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.
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.
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%.
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.
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.
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.
综述了国内外页岩气井井壁失稳机理、稳定井壁主要方法及水基钻井液技术研究与应用现状,讨论了当前中国页岩气井钻井液技术面临的主要技术难题,分析了美国页岩气井与中国主要页岩气产区井壁失稳机理的差异,指出了中国页岩气井水基钻井液技术研究存在的误区与不足,提出了中国页岩气井水基钻井液技术发展方向。
页岩具有极低的渗透率和极小的孔喉尺寸,传统封堵剂难以在页岩表面形成有效的泥饼,只有纳米级颗粒才能封堵页岩的孔喉,阻止液相侵入地层,维持井壁稳定,保护储层。以苯乙烯(St)、甲基丙烯酸甲酯(MMA)为单体,过硫酸钾(KPS)为引发剂,采用乳液聚合法制备了纳米聚合物微球封堵剂SD-seal。通过红外光谱、透射电镜、热重分析和激光粒度分析对产物进行了表征,通过龙马溪组岩样的压力传递实验研究了其封堵性能。结果表明,SD-seal纳米粒子分散性好,形状规则(基本为球形),粒度较均匀(20 nm左右),分解温度高达402.5℃,热稳定性好,阻缓压力传递效果显著,使龙马溪组页岩岩心渗透率降低95%。
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
通常在勘探开发油气过程中会发生不同程度的油气层损害,导致产量下降、甚至"枪毙"油气层等,钻井液是第一个与油气层相接触的外来流体,引起的油气层损害程度往往较大。为减轻或避免钻井液导致的油气层损害、提高单井产量,国内外学者们进行了长达半个世纪以上的研究工作,先后建立了"屏蔽暂堵、精细暂堵、物理化学膜暂堵"三代暂堵型保护油气层钻井液技术,使保护油气层效果逐步提高,经济效益明显。但是,与石油工程师们追求的"超低"损害目标仍存在一定差距,特别是随着非常规、复杂、超深层、超深水等类型油气层勘探开发力度的加大,以前的保护技术难以满足要求。为此,将仿生学引入保护油气层钻井液理论中,发展了适合不同油气层渗透率大小的"超双疏、生物膜、协同增效"仿生技术,并在各大油田得到推广应用,达到了"超低"损害目标,标志着第四代暂堵型保护油气层钻井液技术的建立。对上述4代暂堵型保护油气层技术的理论基础、实施方案、室内评价、现场应用效果与优缺点等进行了论述,并通过梳理阐明了将来的研究方向与发展趋势,对现场技术人员和科技工作者具有较大指导意义。
利用自主研发的水泥环密封性实验装置研究了套管内加卸压循环作用下水泥环的密封性,根据实验结果得出了循环应力作用下水泥环密封性失效的机理。实验结果显示,在较低套管内压循环作用下,水泥环保持密封性所能承受的应力循环次数较多;在较高循环应力作用下,水泥环密封性失效时循环次数较少。表明在套管内较低压力作用下,水泥环所受的应力较低,应力水平处于弹性状态,在加卸载的循环作用下,水泥环可随之弹性变形和弹性恢复;在较高应力作用下,水泥环内部固有的微裂纹和缺陷逐渐扩展和连通,除了发生弹性变形还产生了塑性变形;随着应力循环次数的增加,塑性变形也不断地累积。循环压力卸载时,套管弹性回缩而水泥环塑性变形不可完全恢复,2者在界面处的变形不协调而引起拉应力。当拉应力超过界面处的胶结强度时出现微环隙,导致水泥环密封性失效,水泥环发生循环应力作用的低周期密封性疲劳破坏。套管内压力越大,水泥环中产生的应力水平越高,产生的塑性变形越大,每次卸载时产生的残余应变和界面处拉应力也越大,因此引起密封性失效的应力循环次数越少。
分析了硬脆性泥页岩井壁失稳的原因,介绍了纳米材料特点及其应用,并概述了国内外钻井液用纳米封堵剂的研究进展,包括有机纳米封堵剂、无机纳米封堵剂、有机/无机纳米封堵剂,以及纳米封堵剂现场应用案例。笔者认为:利用无机纳米材料刚性特征以及有机聚合物可任意变形、支化成膜等特性,形成的一种核壳结构的无机/聚合物类纳米封堵剂,能够很好地分散到钻井液中,且对钻井液黏度和切力影响较小,这种类型的纳米封堵剂能够在低浓度下封堵泥页岩孔喉,建立一种疏水型且具有一定强度的泥页岩人工井壁,这不仅能够阻止钻井液侵入,而且还能提高地层承压能力,无机纳米材料与有机聚合物的结合是未来钻井液防塌剂的发展方向。
目前中国页岩气水平井定向段及水平段钻井均使用油基钻井液,但油基岩屑处理费用昂贵,急需开发和应用一种具有环境保护特性的高性能水基钻井液体系。介绍了2种高性能水基钻井液体系的室内实验和现场试验效果。在长宁H9-4井水平段、长宁H9-3和长宁H9-5井定向至完井段试验了GOF高性能水基钻井液体系,该体系采用的是聚合物封堵抑制方案,完全采用水基润滑方式;在昭通区块YS108H4-2井水平段试验了高润强抑制性水基钻井液体系,该体系采用的是有机、无机盐复合防膨方案以及润滑剂与柴油复合润滑方式。现场应用表明,定向段机械钻速提高50%~75%,水平段机械钻速提高75%~100%。通过实验数据及现场使用情况,对比分析了2种体系的优劣,找出了他们各自存在的问题,并提出了改进的思路,为高性能水基钻井液的进一步完善提供一些经验。
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现,存地液量越大,一年累积产量越高,与常规的返排率越高产量越高概念恰恰相反,可能与存地液的自发渗吸替油有关。核磁实验结果表明,渗吸替油不同于驱替作用,渗吸过程中小孔隙对采出程度贡献大,而驱替过程中大孔隙对采出程度贡献大,但从现场致密储层岩心孔隙度来看,储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素,探索影响压裂液油水置换的关键影响因素,得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明,各参数对渗吸速度的影响顺序为:界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大,渗吸采收率越大,但是增幅逐渐减小;原油黏度越小,渗吸采收率越大;渗吸液矿化度越大,渗吸采收率越大;当渗吸液中助排剂浓度在0.005%~5%,即界面张力在0.316~10.815 mN/m范围内时,浓度为0.5%(界面张力为0.869 mN/m)的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明:并不是界面张力越低,采收率越高,而是存在某一最佳界面张力,使地层中被绕流油的数量减少,渗吸采收率达到最高,为油田提高致密储层采收率提供实验指导。
针对顺南区块超深高温高压气井固井面临井底温度高、气层活跃难压稳的问题,研究了胶乳纳米液硅高温防气窜水泥体系。通过将纳米液硅防气窜剂与胶乳防气窜剂复配使用,协同增强水泥浆防气窜性能;不同粒径硅粉复配与加量优化,增强水泥石高温稳定性;无机纤维桥联阻裂堵漏,抑制裂缝延展,提高水泥浆防漏性能和水泥石抗冲击性能。该水泥浆体系具有流动性好、API失水量小于50 mL、直角稠化、SPN值小于1,水泥石具有高温强度稳定性好、胶结强度高、抗冲击能力强的特点。密度为1.92 g/cm3的水泥浆体系在190℃、21 MPa养护30 h后超声波强度逐渐平稳,一界面胶结强度达12.6 MPa;水泥石弹性模量较常规低失水水泥石降低52%,抗冲击强度增加了188%,且受霍普金森杆冲击后仅纵向出现几条未贯穿的裂纹。该高温防气窜水泥浆体系在顺南5-2井和顺南6井成功应用,较好地解决了顺南区块超深气井固井难题。
库车山前深部巨厚盐膏层地质特征复杂,层间超高压盐水普遍发育,纵横向规律性差,地层压力变化大,预测难度高。盐膏层钻井过程中超高压盐水侵入井筒后,钻井液性能恶化,导致喷、漏、卡等复杂事故频发,严重影响安全快速钻井。结合超高压盐水层钻井特征,通过分析超高压盐水赋存的圈闭特点及实钻情况,在钻井液的盐水污染容量限实验模拟和评价的基础上,开展了超高压盐水层控压排水技术的探索与实践,形成了控压排水配套新技术,通过控制节流阀调节井口回压和钻井液排量等手段,让地层盐水按一定比例均匀侵入到环空钻井液中,单次放水量不超过环空钻井液量的10%,多次放出盐水,降低高压盐水层的地层压力系数。解决了库车山前超深超高压盐水层安全钻井难题。现场试验表明,采取合理的控压排水方法能够降低盐水层的压力,在溢流与井漏的矛盾中找到压力平衡点,有利于井控安全的井筒状态。