High temperature and high pressure rheological properties of high-density water-based drilling fluids for deep wells

To maintain tight control over rheological properties of high-density water-based drilling fluids, it is essential to understand the factors influencing the theology of water-based drilling fluids. This paper examines temperature effects on the rheological properties of two types of high-density water-based drilling fluids （fresh water-based and brine-based） under high temperature and high pressure （HTHP） with a Fann 50SL rheometer. On the basis of the water-based drilling fluid systems formulated in laboratory, this paper mainly describes the influences of different types and concentration of clay, the content of a colloid stabilizer named GHJ-1 and fluid density on the rheological parameters such as viscosity and shear stress. In addition, the effects of aging temperature and aging time of the drilling fluid on these parameters were also examined. Clay content and proportions for different densities of brine-based fluids were recommended to effectively regulate the rheological properties. Four theological models, the Bingham, power law, Casson and H-B models, were employed to fit the rheological parameters. It turns out that the H-B model was the best one to describe the rheological properties of the high-density drilling fluid under HTHP conditions and power law model produced the worst fit. In addition, a new mathematical model that describes the apparent viscosity as a function of temperature and pressure was established and has been applied on site.

Gas-hydrate formation,agglomeration and inhibition in oil-based drilling fluids for deep-water drilling

One of the main challenges in deep-water drilling is gas-hydrate plugs,which make the drilling unsafe.Some oil-based drilling fluids（OBDF） that would be used for deep-water drilling in the South China Sea were tested to investigate the characteristics of gas-hydrate formation,agglomeration and inhibition by an experimental system under the temperature of 4 ？C and pressure of 20 MPa,which would be similar to the case of 2000 m water depth.The results validate the hydrate shell formation model and show that the water cut can greatly influence hydrate formation and agglomeration behaviors in the OBDF.The oleophobic effect enhanced by hydrate shell formation which weakens or destroys the interfacial films effect and the hydrophilic effect are the dominant agglomeration mechanism of hydrate particles.The formation of gas hydrates in OBDF is easier and quicker than in water-based drilling fluids in deep-water conditions of low temperature and high pressure because the former is a W/O dispersive emulsion which means much more gas-water interfaces and nucleation sites than the later.Higher ethylene glycol concentrations can inhibit the formation of gas hydrates and to some extent also act as an anti-agglomerant to inhibit hydrates agglomeration in the OBDF.

Rheological properties of oil-based drilling fluids at high temperature and high pressure

The rheological properties of two kinds of oil-based drilling fluids with typically composition were studied at pressures up to 138 MPa and temperatures up to 204 ℃ using the RheoChan 7400 Rheometer.The experimental results show that the apparent viscosity,plastic viscosity and yield point decrease with the increase of temperature,and increase with the increase of pressure.The effect of pressure on the apparent viscosity,plastic viscosity and yield point is considerable at ambient temperature.However,this effect gradually reduces with the increase of temperature.The major factor influencing the rheological properties of oil-based drilling fluids is temperature instead of pressure in the deep sections of oil wells.On the basis of numerous experiments,the model for predict the apparent viscosity,plastic viscosity and yield point of oil-based drilling fluids at high temperature and pressure was established using the method of regressive analysis.It is confirmed that the calculated data are in good agreement with the measured data,and the correlation coefficients are more than 0.98.The model is convenient for use and suitable for the application in drilling operations.

Compact intense electron-beam accelerators based on high energy density liquid pulse forming lines

This paper provides a review of the compact intense electron-beam accelerators (IEBAs) based on liquid pulse forming lines (PFLs) that havebeen developed at the National University of Defense Technology (NUDT) in China. The history and roadmap of the compact IEBAs used todrive high-power microwave (HPM) devices at NUDT are reviewed. The properties of both de-ionized water and glycerin as energy storagemedia are presented. Research into the breakdown properties of liquid dielectrics and the desire to maximize energy storage have resulted in theinvention of several coaxial PFLs with different electromagnetic structures, which are detailed in this paper. These high energy density liquidPFLs have been used to increase the performance of IEBA subsystems, based on which the SPARK (Single Pulse Accelerator with spark gaps)and HEART (High Energy-density Accelerator with Repetitive Transformer) series of IEBAs were constructed. This paper also discusses howthese compact IEBAs have been used to drive typical HPM devices and concludes by summarizing the associated achievements and theconclusions that can be drawn from the results.

Influence of monoethanolamine on thermal stability of starch in water based drilling fluid system

To improve the thermal stability of starch in water-based drilling fluid,monoethanolamine(MEA)was added,and the effect was investigated by laboratory experiment.The experimental results show that the addition of monoethanolamine(MEA)increases the apparent viscosity,plastic viscosity,dynamic shear force,and static shear force of the drilling fluid,and reduces the filtration rate of drilling fluid and thickness of mud cake apparently.By creating hydrogen bonds with starch polymer,the monoethanolamine can prevent hydrolysis of starch at high temperature.Starch,as a natural polymer,is able to improve the rheological properties and reduce filtration of drilling fluid,but it works only below 121℃.The MEA will increase the thermal stability of starch up to 160℃.There is a optimum concentration of MEA,when higher than this concentration,its effect declines.

Development and Performance Evaluation of a Deep Water Synthetic Based Drilling Fluid System

With the enhancement of environmental protection awareness, the requirements on drilling fluid are increasingly strict, and the use of ordinary oil-based drilling fluid has been strictly restricted. In order to solve the environmental protection and oil-gas reservoir protection problems of offshore oil drilling, a new synthetic basic drilling fluid system is developed. The basic formula is as follows: a basic fluid (80% Linear a-olefin + 20% Simulated seawater) + 2.5% nano organobentonite + 3.5% emulsifier RHJ-5# + 2.5% fluid loss agent SDJ-1 + 1.5% CaO + the right amount of oil wetting barite to adjust the density, and a multifunctional oil and gas formation protective agent YRZ has been developed. The performance was evaluated using a high-low-high-temperature rheometer, a high-temperature and high-pressure demulsification voltage tester, and a high-temperature and high-pressure dynamic fluid loss meter. The results show that the developed synthetic based drilling fluid has good rheological property, demulsification voltage ≥ 500 V, temperature resistance up to 160°C, high temperature and high pressure filtration loss < 3.5 mL. After adding 2% - 5% YRZ into the basic formula of synthetic based drilling fluid, the permeability recovery value exceeds 90% and the reservoir protection effect is excellent. The new synthetic deepwater drilling fluid is expected to have a good application prospect in offshore deepwater drilling.

Development of a High Temperature and High Pressure Oil-Based Drilling Fluid Emulsion Stability Tester

When drilling deep wells and ultra-deep wells, the downhole high temperature and high pressure environment will affect the emulsion stability of oil-based drilling fluids. Moreover, neither the demulsification voltage method nor the centrifugal method currently used to evaluate the stability of oil-based drilling fluids can reflect the emulsification stability of drilling fluids under high temperature and high pressure on site. Therefore, a high-temperature and high-pressure oil-based drilling fluid emulsion stability evaluation instrument is studied, which is mainly composed of a high-temperature autoclave body, a test electrode, a temperature control system, a pressure control system, and a test system. The stability test results of the instrument show that the instrument can achieve stable testing and the test data has high reliability. This instrument is used to analyze the factors affecting the emulsion stability of oil-based drilling fluids. The experimental results show that under the same conditions, the higher the stirring speed, the better the emulsion stability of the drilling fluid;the longer the stirring time, the better the emulsion stability of the drilling fluid;the greater the oil-water ratio, the better the emulsion stability of the drilling fluid. And the test results of the emulsification stability of oil-based drilling fluids at high temperature and high pressure show that under the same pressure, as the temperature rises, the emulsion stability of oil-based drilling fluids is significantly reduced;at the same temperature, the With the increase in pressure, the emulsion stability of oil-based drilling fluids is in a downward trend, but the decline is not large. Relatively speaking, the influence of temperature on the emulsion stability of oil-based drilling fluids is greater than that of pressure.

Preparation and Performance of the Hyperbranched Polyamine as an Effective Shale Inhibitor for Water-Based Drilling Fluid

Seeking effective solutions to control and mitigate the interaction between drilling fluids and clay formations has been a challenge for many years, and various shale inhibitors have shown excellent results in problematic shale formations around the world. Herein, the hyperbranched polyamine (HBPA) inhibitor with a higher ratio of amine groups and obvious tendentiousness in protonation was successfully synthesized from ethylenediamine, acryloyl chloride and aziridine by five steps, in which the metal-organic framework (MOF) was employed as a catalyst for ring-open polycondensation (ROP). The structure and purity were confirmed by nuclear magnetic resonance hydrogen spectroscopy and high-performance liquid chromatography (HPLC) respectively. The HBPA displays more excellent performance than EDA and KCl widely applied in the oil field. After aging at 80°C and 180°C, the YP of a slurry system containing 25 wt.% bentonite and 2 wt.% HBPA are just 8.5 Pa and 5.5 Pa (wt.%: percentage of mass), respectively. The swelling lengths of 2 wt.% HBPA are estimated to be 1.78 mm, which falls by 70% compared with that of freshwater. Under a hot rolling aging temperature of 180°C, the HBPA system demonstrates a significant inhibition with more than 85% shale cuttings recovery rate and is superior to conventional EDA and KCl. Mechanism analysis further validates that the HBPA can help to increase the zeta potential.

Study on a Polyamine-Based Anti-Collapse Drilling Fluid System

In complex strata, oil-based drilling fluid is the preferred drilling fluid system, but its preparation cost is high, and there are hidden safety risks. Therefore, the new progress of high-performance anti-collapse water-based drilling fluid at home and abroad is analyzed. It is difficult to prevent and control the well collapse. Once the well wall instability problem occurs, it will often bring huge economic losses to the enterprises, and the underground safety accidents will occur. In order to ensure the stability of the well wall and improve the downhole safety, the key treatment agent of water-based collapse drilling fluid is selected, the anti-collapse drilling fluid system is formulated, the evaluation method of drilling fluid prevention performance is established, and a set of water-based drilling fluid system suitable for easy to collapse strata in China is selected to ensure the downhole safety. The development trend of high performance anti-collapse water-based drilling fluid is expected to provide a reference for the research of high performance anti-collapse water-based drilling fluid system and key treatment agent.

一种新型钾基磷酸盐无固相高密度封隔液

高温高密度封隔液是高温高压井完井关键技术之一,目前密度超过1.60 g/cm 3无固相盐水封隔液只有溴盐、锌盐或者甲酸铯溶液,溴盐毒性大,锌盐高温腐蚀性难以控制,而甲酸铯价格昂贵,难以满足高温高压井完井技术要求,开发针对高温高压井的新型无固相高密度清洁盐水封隔液势在必行。以磷酸三钾TKP为主剂并添加其他处理剂优化而成可溶性盐SW4,研发了一种新型钾基磷酸盐无固相高密度封隔液,测试了其密度调节能力、水溶液的流变性和流变模式、金属腐蚀性、高温稳定性、生物毒性等性能。结果表明,SW4封隔液常温条件下最大密度可达1.90 g/cm 3;随密度增大,其水溶液黏度上升,其流变模式为牛顿流体;密度1.85 g/cm 3的封隔液在150℃、7 d条件下对A3钢、N80钢、TN110Cr13S和TN110Cr13M钢的腐蚀速率均小于0.076 mm/a,N80钢在1.80 g/cm 3 SW4封隔液中的腐蚀性明显低于同等条件下的溴化钠、溴化钙和溴化锌,与甲酸铯相当;在同等加量条件下,SW4能够提供更多的K+,具有更优异的防膨性;高温稳定性强,能够满足高温高压井完井工况需求;生物毒性低,具有环境可接受性,可以满足作为无固相高密度封隔液加重剂的技术要求。

页岩油储层环保型高性能水基钻井液体系研究及应用

为了满足页岩油储层钻井对钻井液环保性能的要求,以环保型页岩抑制剂HBY-S和环保型复合润滑剂HBR-L为主要处理剂,并结合其他环保型处理剂,研制出了一种适合页岩油储层钻井的环保型高性能水基钻井液体系。室内对钻井液体系的耐温性能、抗污染性能和环保性能进行了评价,结果表明:体系具有良好的耐温性能,经过160℃老化后钻井液体系的高温高压滤失量为9.6mL,岩屑滚动回收率可以达到90.6%,润滑系数为0.089;体系具有较强的抗污染能力,钻井液中加入10%NaCl、1.0%CaCl_(2)或者15%岩屑粉时流变性能和滤失性能均比较稳定;体系的环保性能优良,钻井液的EC_(50)值为85000(无毒),BOD_(5)/COD值为26.5%(易降解),重金属含量均低于行业标准值。环保型高性能水基钻井液在某页岩油区块水平井钻井过程中进行了成功应用,其中DG-1井钻井期间未出现井下复杂事故,现场钻井液性能稳定,环保性能达标,实现了安全高效钻井的目标,在页岩油水平井钻井中具有良好的推广应用前景。

超深缝洞型碳酸盐岩储层超低密度钻井液技术

塔里木油田压力系数低于1.0的超深井碳酸盐岩低压储层常发生钻井液失返性井漏,其平均井深超过6000 m,井控风险极大,除了强钻再无更好手段,往往只能提前完井。为提升超深井水平段延伸能力,研究人员研发了高强度空心玻璃微珠,可配制密度为0.93~1.07 g/cm^(3)的超低密度水基钻井液。详述了中古262-H4C井井漏失返后利用低密度水基钻井液重建井筒循环、恢复常规定向钻进的施工过程。现场钻井液密度最低降至0.98 g/cm^(3),井漏失返后多钻373 m,实现了一井钻穿两个缝洞体的地质目的,保障了该井井漏失返后钻至设计井深,开创了空心玻璃微珠超低密度钻井液在国内垂深超6000 m的超深井应用先例,为我国类似老区低压地层应用提供了技术参考。

准噶尔盆地中部永进油田超深井井壁稳定钻井液技术

永进油田位于准噶尔盆地中部Ⅲ区块,储层为侏罗系西山窑组,油气埋藏深,地质构造复杂。前期勘探中采用四开制井身结构,随后调整为三开制,二开及以下地层钻进过程中复杂情况频发,井壁稳定性差,钻完井时效低,且前期已完钻井储层污染严重,制约了永进油田勘探与开发进程。为此,基于对该区超深井钻井液技术难点的分析,制定了相应的稳定井壁技术对策,据此针对二开长裸眼井段,研选聚胺强抑制钻井液体系;针对三开复杂地层,研选合成基强封堵钻井液体系。两种钻井液体系经过评价实验与现场应用,均获良好结果。评价实验结果表明,两种钻井液体系均具备较强的抑制性能、封堵性能,针对三开复杂地层的合成基强封堵钻井液体系兼具储层保护性能。两种钻井液体系在永进油田9口井的现场试验应用结果表明:(1)两种钻井液体系辅以现场施工工艺,所形成的超深井井壁稳定钻井液技术切实可行,能够保证应用井在二开长裸眼井段及三开复杂地层钻进过程中井壁稳定,起下钻通畅,中完及完井作业顺利;(2)对比前期完钻的8口井,应用超深井井壁稳定钻井液技术顺利完钻的9口井,井身质量明显提高,钻井、完井时效显著提升(平均钻井周期缩短69.61%,平均完井周期缩短65.29%,平均机械钻速提高80.88%),取得了良好的优快钻井效果;(3)钻井液对储层的污染性小,取得了良好的储层保护效果,应用井完井试油获得稳定高产工业油气流,首次实现了对永进油田油气储量的有效动用。结论认为,井壁稳定钻井液技术在永进油田超深井钻井中的成功应用,为该区块的后续勘探开发提供了有力保障,对其他区块超深井或存在井壁失稳问题井的钻井液技术研究亦有参考意义。

纳米流体和两性表面活性剂改善钻井液性能实验研究

本文研究了碳化硅纳米流体和表面活性剂对水基钻井液物理和化学性质(热稳定性、黏度、表面张力和滤失特性)的影响。将碳化硅纳米流体、表面活性剂溶液和水基钻井液混合形成表面活性剂——碳化硅(Si C)钻井液,分别用流变仪、张力仪和压滤机对混合钻井液的黏度、表面张力和滤失性等性质进行了研究。实验结果表明,与常规表面活性剂相比,两性表面活性剂对钻井液黏度的增量最大,此外,混合钻井液具有更好的热稳定性,随着温度的升高,黏度平均变化率为9%,表面张力和滤失性分别下降了31.0%和22.2%。

一种抗超高温配位键合型低聚物降黏剂

针对高密度水基钻井液高温增稠引发的滤失量大、ECD与内耗高、流动性下降甚至完全丧失难题,在AAAMPS聚有机酸降黏剂分子中引入富含大量邻苯二酚基团的单宁酸,采用自由基聚合法研制了一种抗超高温配位键合型低聚物降黏剂AA-AMPS-TA,并通过正交实验明确了PAAT的最优合成条件。表征并评价了PAAT的降黏性能,结果表明:引入TA后,PAAT的红外光谱出现了源于酚羟基的分子内氢键吸收峰,且因其分子结构中引入了大量苯酚基团,显著提升了热稳定性,分解温度接近500℃;PAAT可降低低浓度膨润土浆和7%膨润土+8%高岭土的高浓度混合黏土浆黏度,在高密度水基钻井液体系中降黏率达26.5%,240℃热滚后降黏率达44.4%。采用Zeta电位与粒径分析验证了PAAT的吸附降黏机理,并在蓬深101井中现场应用,控制了井浆高温下黏度、切力增涨,降黏效果良好。

海上某盆地胶结型防漏堵漏钻井液技术

分析了我国海上某盆地地质特征和历史井漏情况,明确了该盆地钻井防漏堵漏难点:地层裂缝发育且存在微米级至毫米级的多尺度裂缝,甚至裂缝和孔、洞并存,导致堵漏材料选配难、一次堵漏成功率低;地层发育大段风化壳、部分地层破碎严重、钻井中裂缝极易二次发育等,导致恶性漏失甚至失返性漏失等复杂情况。针对上述难点,以聚乙烯醇、聚丙烯酸以及含邻苯二酚结构的有机物为原料,合成了一种胶结型堵漏剂BFD-1。实验结果表明,人造疏松岩心在加有4%BFD-1的水溶液中浸泡后,岩心抗压强度提高率达19.34%。以BFD-1为核心,复配现场常用堵漏材料,构建了适用于不同尺寸范围漏失通道的防漏堵漏钻井液体系,具良好的防漏堵漏性、胶结性,并可有效阻止压力传递。研究成果可为该地区钻井井漏防治提供有力技术支撑。

海陆过渡相页岩储层液岩作用机理及钻井液体系构建

我国海陆过渡相页岩地质储量大、资源丰度高,开发前景广阔。但钻井过程中井壁极易发生掉块、坍塌,导致井壁失稳影响钻井安全。本文通过钻井岩心观察、电镜和CT扫描、X射线衍射分析等相关实验,得到储层岩样矿物组分及微观结构等特征,结果表明:页岩气储层全岩主要含石英和黏土矿物,地层黏土矿物含量高达45.7%,且黏土矿物中不含蒙脱石,高岭石含量为35%,伊/蒙混层含量为26%;岩样表面纳微米孔隙和微裂缝发育,裂缝宽度在微米级并连通多条窄裂缝;通过岩液作用后晶层间距、表面张力、线性膨胀率和裂缝扩展变化分析,海陆过渡相页岩仅发生表面水化,揭示了海陆过渡相页岩气储层岩液作用机理。优选了水基钻井液抑制剂、封堵剂与润滑剂,构建了一套海陆过渡相页岩气储层的高性能水基钻井液体系,并对其展开了室内评价。钻井液常规性能、抑制性、封堵性、润滑性评价实验结果表明,该钻井液体系抗温100℃,高温高压失水6 mL,泥页岩膨胀率为1.03%,钻井液润滑系数整体小于0.15,体系30 min的API滤失量较基浆降低40%,可对地层微裂缝实现有效封堵,且生物毒性EC50值为37260 mg/L,属于无毒级别,能够满足海陆过渡相页岩气钻井作业施工对钻井液性能的要求并进行了现场应用,封堵防塌效果良好,可有效解决海陆过渡相泥页岩井壁失稳的技术难题。

高分子纳米复合材料在水基钻井液中的研究进展

传统高分子聚合物材料难以满足日益复杂的井下环境要求,而无机纳米材料又存在分散性不足的缺陷,将纳米材料接枝到聚合物链上或将聚合物嵌入纳米材料中形成高分子纳米复合材料,可发挥两种材料的协同增效作用,进而提升水基钻井液的综合性能。文章介绍了高分子纳米复合材料在改善水基钻井液流变性、优化封堵降滤失性、增强封堵防塌性方面的应用,总结了其作用效果及作用机理。高分子纳米复合材料改善钻井液流变性的机理包括聚合物增强固体纳米颗粒在钻井液中的分散性、增加流体层间内摩擦力、通过聚合物与黏土颗粒之间的氢键和静电相互作用形成空间网络结构等。优化钻井液封堵降滤失性的机理包括利用无机纳米材料对微孔进行封堵,形成致密的泥饼,利用聚合物的强吸附性和两亲性,在泥饼表面形成疏水膜等。增强钻井液封堵防塌作用的机理包括纳米颗粒桥接和堵塞页岩纳米孔隙,形成致密屏障,阻止水分子侵入页岩;聚合物链上的多功能基团在黏土表面形成竞争吸附,降低黏土对水分子的吸附;成熟聚胺类聚合物的氨基嵌入和阳离子压缩双电层的综合作用,强化页岩水化抑制性能。提出了高分子纳米复合材料面临的挑战,如大规模生产过程中无机纳米颗粒在聚合物基质中可能出现的分散不均匀问题。最后,从降磨减阻、储层保护和可持续性3个方面对高分子纳米复合材料的研究方向进行了展望。

改性二氧化硅封堵剂的制备及性能评价

为了降低水基钻井液滤液对储层的扰动,以丙烯酰胺、苯乙烯、乙烯基三甲氧基硅烷对纳米SiO_(2)进行表面改性,将柔性链聚合物接枝在纳米刚性SiO_(2)粒子表面,形成一种新型的有机-无机复合封堵剂。实验结果发现:该封堵剂提高了泥饼的致密性和封堵性能,并对岩心孔隙进行了有效封堵,有效抑制岩屑水化现象,为水基钻井液在低渗-致密储层开发过程中的应用提供技术支持。

溱潼凹陷红页201井组钻完井关键技术研究与应用

溱潼凹陷红页201井组以定向井方式开发页岩油,通过井身结构优化,形成二开制(变径)井身结构,优选高效钻头复合钻井技术(PDC)钻头实现钻井提速,使用偏心扩眼器应对上部井段缩径问题,优选高性能水基钻井液体系维持井壁稳定,实现红页201井组高效钻完井。