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.

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.

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.

Comparison and application of different empirical correlations for estimating the hydrate safety margin of oil-based drilling fluids containing ethylene glycol

As the oil and gas industries continue to increase their activity in deep water, gas hydrate hazards will become more serious and challenging, both at present and in the future. Accurate predictions of the hydrate-free zone and the suitable addition of salts and/or alcohols in preparing drilling fluids are particularly important both in preventing hydrate problems and decreasing the cost of drilling operations. In this paper, we compared several empirical correlations commonly used to estimate the hydrate inhibition effect of aqueous organic and electrolyte solutions using experiments with ethylene glycol （EG） as a hydrate inhibitor. The results show that the Najibi et al. correlation （for single and mixed thermodynamic inhibitors） and the Ostergaard et al. empirical correlation （for single thermodynamic inhibitors） are suitable for estimating the hydrate safety margin of oil-based drilling fluids （OBDFs） in the presence of thermodynamic hydrate inhibitors. According to the two correlations, the OBDF, composed of 1.6 L vaporizing oil, 2% emulsifying agent, 1% organobentonite, 0.5% SP-1, 1% LP-1, 10% water and 40% EG, can be safely used at a water depth of up to 1900 m. However, for more accurate predictions for drilling fluids, the effects of the solid phase, especially bentonite, on hydrate inhibition need to be considered and included in the application of these two empirical correlations.

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.

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.

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.

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.

BIODRILL S合成基钻井液在垦利区块首次应用

渤海油田垦利9-1区块地层岩性复杂,且存在断层带,钻井过程中易发生泥岩水化分散和砂岩层井眼缩径等问题,井壁垮塌风险极大。针对该区块地层岩性特点和技术难题并结合环保要求,制备了一种复合型封堵材料PFMOSHIELD,构建了BIODRILL S合成基钻井液体系。该体系流变性能良好,抗钙、抗岩屑污染达26%和15%,封堵性、沉降稳定性、润滑性优异,高温高压砂盘滤失量3.2 mL,静置7 d沉降因子为0.53,极压润滑系数0.082。BIODRILL S首次在渤海湾垦利9-1区块进行了现场应用,结果表明:该体系解决了垦利9-1区块泥页岩水化和砂岩层井眼缩径问题,垦利9-1北-3定向探井三开井段上部地层钻屑完整,钻屑达4~7 cm;井眼清洁性能良好,钻井液动塑比超过0.59 Pa/mPa·s,φ6和φ3读数均超过9,剪切稀释性强,提高了井眼净化效率,有效避免形成“岩屑床”;润滑性能优异,在大井斜段(55°、70°、67°)可实现直接起钻。

BUILDING OF THE PETROLEUM DRILLING FLUID ENGINEERING DESIGN EXPERT SYSTEM

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Development of key additives for organoclay-free oil-based drilling mud and system performance evaluation

Traditional oil-based drilling muds(OBMs) have a relatively high solid content, which is detrimental to penetration rate increase and reservoir protection. Aimed at solving this problem, an organoclay-free OBM system was studied, the synthesis methods and functioning mechanism of key additives were introduced, and performance evaluation of the system was performed. The rheology modifier was prepared by reacting a dimer fatty acid with diethanolamine, the primary emulsifier was made by oxidation and addition reaction of fatty acids, the secondary emulsifier was made by amidation of a fatty acid, and finally the fluid loss additive of water-soluble acrylic resin was synthesized by introducing acrylic acid into styrene/butyl acrylate polymerization. The rheology modifier could enhance the attraction between droplets, particles in the emulsion via intermolecular hydrogen bonding and improve the shear stress by forming a three-dimensional network structure in the emulsion. Lab experimental results show that the organoclay-free OBM could tolerate temperatures up to 220 ?C and HTHP filtration is less than 5 m L. Compared with the traditional OBMs, the organoclay-free OBM has low plastic viscosity, high shear stress, high ratio of dynamic shear force to plastic viscosity and high permeability recovery, which are beneficial to penetration rate increase, hole cleaning and reservoir protection.

井研地区筇竹寺组页岩储层水平井钻井井壁稳定性评价

川西南井研区块筇竹寺组页岩气具有良好的开发前景,但由于对其岩矿组分、力学性质、水化特征等认识程度较低,钻井井壁稳定性认识不清,导致出现掉块、阻卡等复杂情况。为了充分认识该区寒武系筇竹寺组地层的井壁稳定性,明确粉砂质页岩水化作用及其对坍塌压力的影响规律,在岩石力学实验的基础上,研究不同钻井液浸泡时间对岩石力学参数的影响规律,建立考虑水化作用的井壁稳定性预测模型,分析不同井斜方位下坍塌压力的差异。研究结果表明:筇竹寺组伊蒙混层含量高,具有一定膨胀性,水化作用后导致岩石强度降低,对井壁稳定性有较大影响;不同钻井液体系对井壁稳定性的影响有差异,总体上油基钻井液更有利于井壁稳定;考虑了水化作用的井壁稳定预测模型更加符合实际,以此为依据,通过优化钻井液设计可以有效降低井壁失稳风险,提高钻井时效。

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。

亲油水泥浆界面封隔性能评价研究

页岩气井油基钻井液条件下固井时,套管与井壁表面附着油膜或油基钻井液易导致水泥环界面封隔能力下降,形成窜流通道,影响后期增产改造作业。虽然前置液能有效提高界面润湿反转,但受用量、冲洗效率等因素限制,界面仍会出现油膜附着情况。为此,在水泥浆中加入亲油表面活性剂,制备形成亲油水泥浆,赋予水泥环亲油能力。采用接触角、剪切胶结强度、界面水力封隔测试等评价了亲油水泥石的亲油能力及界面封隔效果。研究发现,非极性溶剂在亲油水泥石表面接触角远低于常规水泥石表面,具备良好的亲油性能;亲油水泥石与含白油、油基钻井液的套管、页岩岩芯胶结后,一、二界面抗流体窜流压力分别提升500%和400%,胶结强度分别提高205%和122%;亲油表面活性剂的加入不会对水泥水化程度、水泥浆工程性能及水泥石力学性能产生负面影响。结果表明,亲油表面活性剂掺入后可有效提高水泥环与含油界面的封隔能力,具备提高油基钻井液条件下水泥环套管地层界面胶结与封隔性能的潜力。

有机层状硅酸盐改善油基钻井液沉降稳定性室内评价

基于油基钻井液有机土有机改性剂阳离子受高温易分解脱附,引起钻井液性能变差、加重材料沉降等问题,利用六水合氯化镁和十六烷基三甲氧基硅烷等为原料,合成了一种适用于柴油基钻井液体系的有机土(有机层状硅酸盐),用于改善油基钻井液的沉降稳定性;通过傅里叶红外光谱、X-射线衍射以及室内钻井液沉降实验进行结构表征和沉降稳定性评价。结果表明:该有机硅酸盐材料具备2∶1层状硅酸盐结构和以Si—C共价键连接的不对称链状有机官能团结构,且300℃无明显热分解;相比于大庆油田常用油基钻井液,该有机层状硅酸盐提高了油基钻井液的动切力、动塑比和储能模量,明显改善了1.4~2.0 g·cm^(-3)密度范围、150℃以下老化温度油基钻井液的悬浮性能和沉降稳定性能。

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%。

增效型无土相仿生油基钻井液技术的研究与应用

针对深井超深井钻井过程中钻遇高温高压、井壁失稳及井下复杂情况的难题,基于仿生学、超分子化学以及岩石表面润湿性理论,通过优选仿生增效剂、仿生提切剂及仿生降滤失剂,配套相关处理剂,最终形成了一套适用于深井、超深井地层钻探的增效型无土相仿生油基钻井液体系。研究发现,建立的增效型无土相仿生油基钻井液体系可抗220℃高温,配制密度为2.4 g/cm^(3),破乳电压大于400 V,高温高压滤失量为3.2 mL,人造岩心在该体系中220℃下老化后的抗压强度达到7.1 MPa,平均渗透率恢复值为93.9%。现场应用情况表明,体系流变性能稳定,平均机械钻速比邻井提高16%,平均井径扩大率仅为1.25%,可有效解决深井超深井钻井过程中出现的井壁失稳难题,为我国深井超深井的钻探提供了技术保障。

钻井利器的故事之“护壁堵漏材料”

近年来,作为入地最为关键手段的钻探所面临的地层越来越复杂,钻孔垮塌、掉块、缩径和超径等事故发生概率增加,严重制约了钻探工程质量与效率的提升。护壁堵漏材料是钻探工程不可或缺的关键性工程材料,护壁堵漏技术则是保证钻进工作安全、快速以及持续进行的重要技术环节,是复杂地层钻孔处理的主要内容。本文从科普的角度介绍了护壁堵漏材料的基本概念与组成、冲洗液护壁堵漏作用、水泥基材料护壁堵漏作用、护壁堵漏材料的进一步发展空间等,以期加深对护壁堵漏材料的认识,促进新型护壁堵漏材料的研发和应用。