Distribution and treatment of harmful gas from heavy oil production in the Liaohe Oilfield, Northeast China

The distribution and treatment of harmful gas （H2S） in the Liaohe Oilfield, Northeast China, were investigated in this study. It was found that abundant toxic gas （H2S） is generated in thermal recovery of heavy oil. The H2S gas is mainly formed during thermochemical sulfate reduction （TSR） occurring in oil reservoirs or the thermal decomposition of sulfocompounds （TDS） in crude oil. H2S generation is controlled by thermal recovery time, temperature and the injected chemical compounds. The quantity of SO4^2- in the injected compounds is the most influencing factor for the rate of TSR reaction. Therefore, for prevention of H2S formation, periodic and effective monitoring should be undertaken and adequate H2S absorbent should also be provided during thermal recovery of heavy oil. The result suggests that great efforts should be made to reduce the SO4^2- source in heavy oil recovery, so as to restrain H2S generation in reservoirs. In situ burning or desulfurizer adsorption are suggested to reduce H2S levels. Prediction and prevention of H2S are important in heavy oil production. This will minimize environmental and human health risks, as well as equipment corrosion.

Investigation of feasibility of alkali-cosolvent flooding in heavy oil reservoirs

Cold production is a challenge in the case of heavy oil because of its high viscosity and poor fluidity in reservoir conditions.Alkali-cosolvent-polymer flooding is a type of microemulsion flooding with low costs and possible potential for heavy oil reservoirs.However,the addition of polymer may cause problems with injection in the case of highly viscous oil.Hence,in this study the feasibility of alkali-cosolvent(AC)flooding in heavy oil reservoirs was investigated via several groups of experiments.The interfacial tension between various AC formulations and heavy crude oil was measured to select appropriate formulations.Phase behavior tests were performed to determine the most appropriate formulation and conditions for the generation of a microemulsion.Sandpack flooding experiments were carried out to investigate the displacement efficiency of the selected Ac formulation.The results showed that the interfacial tension between an AC formulation and heavy oil could be reduced to below 1o-3 mN/m but differed greatly between different types of cosolvent.A butanol random polyether series displayed good performance in reducing the water-oil interfacial tension,which made it possible to form a Type Il microemulsion in reservoir conditions.According to the results of the phase behavior tests,the optimal salinity for different formulations with four cosolvent concentrations(0.5 wt%,1 wt%,2 wt%,and 3 wt%)was 4000,8000,14000,and 20000 ppm,respectively.The results of rheological measurements showed that Type Ill microemulsion had a viscosity that was ten times that of water.The results of sandpack flooding experiments showed that,in comparison with waterflooding,the injection of a certain Ac formulation slug could reduce the injection pressure.The pressure gradient during waterflooding and AC flooding was around 870 and 30-57 kPa/m,respectively.With the addition of an AC slug,the displacement efficiency was 30%-50%higher than in the case of waterflooding.

Development Strategies for Achieving High Production with Fewer Wells in Conventional Offshore Heavy Oil Fields in Bohai Bay,China

Development strategy for heavy-oil reservoirs is one of the important research interests in China National Offshore Oil Corp. （CNOOC） that plans a highly effective development for heavy oil fields in multilayered fluvial reservoirs because of their significant influence on marine oil and even on China＇s petroleum production. The characteristics analysis of multilayered fluvial reservoirs in the heavy oil fields in Bohai Bay indicates that large amounts ofoil were trapped in the channel, point bar and channel bar sands. The reserves distribution of 8 oilfields illustrates that the reserves trapped in the main sands, which is 20%-40% of all of the sand bodies, account for 70%-90% of total reserves of the heavy oil fields. The cumulative production from high productivity wells （50% of the total wells） was 75%-90% of the production of the overall oilfield, while only 3%-10% of the total production was from the low productivity wells （30% of the total wells）. And the high productivity wells were drilled in the sands with high reserves abundance. Based on the above information the development strategy was proposed, which includes reserves production planning, selection of well configuration, productivity design, and development modification at different stages.

Lag times in toe-to-heel air injection(THAI)operations explain underlying heavy oil production mechanisms

From a time value of revenue point of view,it is preferred that the time between reservoir stimulation and oil production response is small.Heavy oil combustion processes have a lag time between air injection and liquid production,but the common practice in production data analysis uses simultaneous injection and production data when seeking a relationship between them.In this research,the time scales of production for the Kerrobert toe-to-heel air injection(THAI)heavy oil project in Saskatchewan,Canada,is analyzed by using cross correlation analysis,i.e.time delay analysis between air injection and oil production.The results reveal two time scales with respect to production response with two distinctive recovery mechanisms:(1)a short time scale response(nearly instantaneous)where oil production peaks right after air injection(directly after opening production well)reflecting cold heavy oil production mechanisms,and(2)a longer time scale(of order of 100-300 days)response where peak production occurs associated with the collective phenomena of air injection,heat generating reactions,heat transfer,and finally,heated mobilized heavy oil drainage to the production well.This understanding of the two time scales and associated production mechanisms provides a basis for improving the performance of THAI.

Heavy Oil and Oil Sands:Global Distribution and Resource Assessment

Global recoverable resources of heavy oil and oil sands have been assessed by CNPC using a geology-based assessment method combined with the traditional volumetric method, spatial interpolation method, parametric-probability method etc. The most favourable areas for exploration have been selected in accordance with a comprehensive scoring system. The results show:(1) For geological resources, CNPC estimate 991.18 billion tonnes of heavy oil and 501.26 billion tonnes of oil sands globally, of which technically recoverable resources of heavy oil and oil sands comprise 126.74 billion tonnes and 64.13 billion tonnes respectively. More than 80% of the resources occur within Tertiary and Cretaceous reservoirs distributed across 69 heavy oil basins and 32 oil sands basins. 99% of recoverable resources of heavy oil and oil sands occur within foreland basins, passive continental-margin basins and cratonic basins.(2) Since residual hydrocarbon resources remain following large-scale hydrocarbon migration and destruction, heavy oil and oil sands are characterized most commonly by late hydrocarbon accumulation, the same basin types and source-reservoir conditions as for conventional hydrocarbon resources, shallow burial depth and stratabound reservoirs.(3) Three accumulation models are recognised, depending on basin type: degradation along slope; destruction by uplift; and migration along faults.(4) In addition to mature exploration regions such as Canada and Venezuela, the Volga-Ural Basin and the Pre-Caspian Basin are less well-explored and have good potential for oil-sand discoveries, and it is predicted that the Middle East will be an important region for heavy oil development.

Quantitative Characterization and Dynamic Law of Interlayer Interference for Multilayer Commingled Production in Heavy Oil Reservoirs by Numerical Simulation

This paper moves one step forward to build?a?numerical model to research quantitative characterization and dynamic law for interlayer interference factor (IIF) in the multilayer reservoir which was heavy oil reservoirs and produced by directional wells. There are mainly four contributions of this paper to the existing body of literature. Firstly, an equivalent simulation method of the pseudo start pressure gradient (PSPG) is developed to quantitatively predict the value of?IIF?under different geological reservoir conditions. Secondly, the interlayer interference is extended in time, and the time period of the study extends from a water cut stage to the whole process from the oil well open to produce?a?high water cut. Thirdly, besides the conventional productivity interlayer interference factor (PIIF), a new parameter, that is, the oil recovery interlayer interference factor (RIIF) is put forward.?RIIF?can be used to evaluate the technical indexes of stratified development and multilayer co-production effectively. Fourthly,?the?effectsof various geological reservoir parameters such as reservoir permeability and crude oil viscosity, etc. on the?PIIF?and?RIIF’s?type curves?are?discussed in detail and the typical plate?is?plotted. The research results provide a foundation for the effective development of multilayer heavy oil reservoirs.

Steam Flooding after Steam Soak in Heavy Oil Reservoirs through Extended-reach Horizontal Wells

This paper presents a new development scheme of simultaneous injection and production in a single horizontal well drilled for developing small block reservoirs or offshore reservoirs. It is possible to set special packers within the long completion horizontal interval to establish an injection zone and a production zone. This method can also be used in steam flooding after steam soak through a horizontal well. Simulation results showed that it was desirable to start steam flooding after six steam soaking cycles and at this time the oil/steam ratio was 0.25 and oil recovery efficiency was 23.48%. Steam flooding performance was affected by separation interval and steam injection rate. Reservoir numerical simulation indicated that maximum oil recovery would be achieved at a separation section of 40-50 m at steam injection rate of 100-180 t/d; and the larger the steam injection rate, the greater the water cut and pressure difference between injection zone and production zone. A steam injection rate of 120 t/d was suitable for steam flooding under practical injection-production conditions. All the results could be useful for the guidance of steam flooding projects.

Study on Productivity Model of Herringbone-Like Laterals Wells and Optimization of Morphological Parameters Considering Threshold Pressure Gradient in Heavy Oil Reservoirs

Compared with conventional well, herringbone-like laterals wells can increase the area of oil release, and can reduce the number of wellhead slots of platforms,?and?also can greatly improve the development efficiency. Based on threshold pressure gradient in heavy oil reservoir,?and?the applied principle of mirror reflection and superposition, the pressure distribution equation of herringbone-like laterals wells is obtained in heavy oil reservoir. Productivity model of herringbone-like laterals wells is proposed by reservoir-wellbore steady seepage. The example shows that the productivity model is great accuracy?to?predict the productivity of herringbone-like laterals wells. The model is used to analyze the branching length, branching angle, branching symmetry, branching position and spacing and their effects on productivity of herringbone-like laterals wells. The principle of optimizing the well shape of herringbone-like laterals wells is proposed.

Heavy Oil Reservoir Seismic Characteristics during Thermal Production:A Case Study

Most production methods of heavy oil involve thermal production.However,it is challenging to delineate the thermal-affected zone due to complex reservoir conditions.With steam injected,the heavy oil viscosity drops;the reservoir density and velocity decrease accordingly,causing changes to seismic impedance.Moreover,the oil-and-water viscosity ratio and permeability show the difference with changing temperature,indicating that the reservoir’s ability to transmit seismic waves would also be temperature-dependent.Therefore,the seismic responses and attenuation characteristics of the steam chamber can be helpful to monitor the steam-affected zone.We introduce an improved viscoelastic model to approximate the heavy oil reservoir during thermal production,and use the frequency-space domain finite difference algorithm to simulate the seismic wave-fields.Numerical results demonstrate that this model is applicable to a wide temperature range,and can effectively reveal the seismic characteristics of the steam chamber.Through analyzing the propagation differences of seismic waves under different temperatures,it is concluded that the attenuation coefficient,root-meansquare amplitude difference and amplitude ratio of PP-wave and PS-wave under different conditions can reveal the temperature variation in the steam chamber,with which it is possible to detect the steam chamber spatial distribution.

Numerical simulation investigations of the applicability of THAI in situ combustion process in heavy oil reservoirs underlain by bottom water

The presence of a bottom water(BW)layer in heavy oil reservoirs can present substantial problems for efficient oil recovery for all recovery techniques.Hence,it is necessary to know how particular production processes are affected by different BW layer thicknesses,and how standard production procedures can be adapted to handle such reservoirs.Toe-to-heel air injection(THAI)is a thermally efficient process,generating in situ energy in the reservoir by burning a fraction of the oil-in-place as coke and has the potential to economically and environmentally friendly work in reservoirs with BW layer.However,to ascertain that,studies are needed first.These are conducted via numerical simulations using commercial reservoir thermal simulator,CMG STARS.This work has shown that the shape of the combustion zone in THAI remains forward-leaning even in the presence of a BW layer,indicating that the process is stable,and that there is no oxygen bypassing of the combustion front.However,the oil recovery rate is highly negatively affected by how large the thickness of the BWzone is,and the severity of such effect is determined to be proportional to the thickness of the BW layer.This study also shows that there is a period of low oil production rate which corresponds to mobilised oil displacement into the BW zone which in turn causes a surge in water production rate.The practical implication of this is that prolonged period of low oil production rates will expose companies and/or investors to higher risk due to the oil market volatility.In this study,it is also revealed that the height of the mobilised oil that is displaced into the BW zone equates to that of the displaced and replaced water thereby implying that when the BW layer thickness is 50%that of the oil layer(OL),less than 50%of the mobilised oil will be recovered when the entire reservoir is swept by the combustion front.Therefore,conclusively,applying the THAI process in its conventional form in reservoirs containing bottom water is not recommended,and as a result,a new strategy is needed to enhance process economics by improving the oil production and hence recovery rates.

Using deep neural networks coupled with principal component analysis for ore production forecasting at open-pit mines

Ore production is usually affected by multiple influencing inputs at open-pit mines.Nevertheless,the complex nonlinear relationships between these inputs and ore production remain unclear.This becomes even more challenging when training data(e.g.truck haulage information and weather conditions)are massive.In machine learning(ML)algorithms,deep neural network(DNN)is a superior method for processing nonlinear and massive data by adjusting the amount of neurons and hidden layers.This study adopted DNN to forecast ore production using truck haulage information and weather conditions at open-pit mines as training data.Before the prediction models were built,principal component analysis(PCA)was employed to reduce the data dimensionality and eliminate the multicollinearity among highly correlated input variables.To verify the superiority of DNN,three ANNs containing only one hidden layer and six traditional ML models were established as benchmark models.The DNN model with multiple hidden layers performed better than the ANN models with a single hidden layer.The DNN model outperformed the extensively applied benchmark models in predicting ore production.This can provide engineers and researchers with an accurate method to forecast ore production,which helps make sound budgetary decisions and mine planning at open-pit mines.

FCC coprocessing oil sands heavy gas oil and canola oil. 2. Gasoline hydrocarbon type analysis

This study set out to gain a deeper understanding of a fluid catalytic cracking(FCC)coprocessing approach using canola oil mixed with bitumen-derived heavy gas oil(HGO),for the production of partially-renewable gasoline,with respect to its composition and quality.The FCC coprocessing approach may provide an alternative solution to reducing the carbon footprint and to meet government regulatory demands for renewable transportation fuels.In this study,a mixture of 15 v%canola oil in HGO was catalytically cracked with a commercial equilibrium catalyst under typical FCC conditions.Cracking experiments were performed using a bench-scale Advanced Cracking Evaluation(ACE)unit at a fixed weight hourly space velocity of 8 h^(à1),490–530C,and catalyst/oil ratios of 4–12 g/g.The total liquid product samples were injected via an automatic sampler and a prefractionator(to removet254C)into a gas chromatographic system containing a series of columns,traps,and valves designed to separate each of the hydrocarbon types.The analyzer gives detailed hydrocarbon types of à200C gasoline,classified into paraffins,iso-paraffins,olefins,naphthenes,and aromatics by carbon number up to C_(11)(C_(10)for aromatics).For a feed cracked at a given temperature,the gasoline aromatics show the highest selectivity in terms of weight percent conversion,followed by saturated iso-paraffins,saturated naphthenes,unsaturated iso-paraffins,unsaturated naphthenes,unsaturated normal paraffins,and saturated normal paraffins.As conversion increases,both aromatics and saturated iso-paraffins increase monotonically at the expense of other components.Hydrocarbon type analysis and octane numbers with variation in feed type,process severity(temperature and catalyst/oil ratio),and conversion are also presented and discussed.

Effect of operating pressure on the performance of THAI-CAPRI in situ combustion and in situ catalytic process for simultaneous thermal and catalytic upgrading of heavy oils and bitumen

According to the analysis of the 2020 estimates of the International Energy Agency(2020),the world will require up to 770 billion barrels of oil from now to 2040.However,based on the British Petroleum(BP)statistical review of world energy 2020,the world-wide total reserve of the conventional light oil is only 520.2 billion barrels as at the end of 2019.That implies that the remaining 249.8 billion barrels of oil urgently needed to ensure a smooth transition to a decarbonised global energy and economic systems is provided must come from unconventional oils(i.e.heavy oils and bitumen)reserves.But heavy oils and bitumen are very difficult to produce and the current commercial production technologies have poor efficiency and release large quantities of greenhouse gases.Therefore,these resources should ideally be upgraded and produced using technologies that have greener credentials.This is where the energy-efficient,environmentally friendly,and self-sustaining THAI-CAPRI coupled in situ combustion and in situ catalytic upgrading process comes in.However,the novel THAI-CAPRI process is trialled only once at field and it has not gained wide recognition due to poor understanding of the optimal design parameters and procedures.Hence,this work reports the first ever results of investigations of the effect of operating pressure on the performance of the THAI-CAPRI process.Two experimental scale numerical models of the process based on Athabasca tar sand properties were run at pressures of 8000 kPa and 500 kPa respectively using CMG STARS.This study has shown that the higher the operating pressure,the larger the API gravity and the higher the cumulative volume of high-quality oil is produced(i.e.a 2300 cm3 of z24 oAPI oil produced at 8000 kPa versus the 2050 cm3 of z17.5 oAPI oil produced at 500 kPa).The study has further shown that despite presence of annular catalyst layer,the THAI-CAPRI process operates stably.However,it is found that a more stable and safer operation of the process can only be achieved at optimal pressure that should lie between 500 kPa and 8000 kPa,especially since at the lower pressure,should the process time be extended,it will not take long before oxygen breakthrough takes place.The simulations have shown in details that at higher pressures,the catalyst bed is easily and rapidly coked and thus the catalyst life will be very short especially during actual field reservoir operations.Since the oil drainage flux into the HP well at field-scale is different from that at laboratory-scale,and at field-scale,the combustion front does not propagate inside the HP well,it will be practically very challenging to regenerate or replace the coke-deactivated annular catalyst layer in actual reservoir operations.There-fore,it is concluded that during field operation designs,an optimum pressure must be selected such that a balance is obtained between the combustion front stability and the degree of catalytic upgrading,and between the catalyst life and its effectiveness.

稠油开采中多元热复合流体相态的研究进展

稠油的储量远超常规石油的储量,但因稠油黏度大和密度大的特点而难以开采,高效经济开发稠油已成为石油领域的研究重点。热复合开采技术是目前高效开发稠油油藏的关键技术,其中多元热复合流体的相态特征是稠油油藏开采流程设计与评价的关键。为此,从热复合开采技术中的混合气体系和稠油-气体系2个方面,系统地阐述了多元热复合流体相态的实验和理论研究现状。对于混合气体系相态,多采用静态法进行实验测试,使用状态方程结合混合规则进行理论预测,CO_(2),N_(2),H_(2)O和CH_(4)等常见气体分子组成的二元体系的相态测试趋于成熟,但缺少多元体系的测试数据与预测模型;对于稠油-气体系相态,总结了一般性实验流程与近年实验结果,提出一种加速油气相平衡的新型实验装置构想,指出目前理论预测在气体种类、注气量、气体扩散模型、二元相互作用系数等方面的不足。进而对多元热复合流体相态研究提出展望,以期促进热复合开采技术进一步的机理研究与参数优化。

旅大特稠油储层新型完井液体系的构建与评价

旅大A油田是一个埋藏浅、油质稠、储量大的典型重质特超稠油油藏,热采开发是其有效的开发方式。稠油油藏在储层物性、流体性质及开采工艺方面与常规油藏存在较大差异,现有常规水基完井液体系无法满足需求。针对该油田稠油热采工艺,充分考虑稠油油藏储层特性、稠油预防乳化增稠和降黏促排的新需求,开展新型完井液体系的构建。通过抑制性、降黏助排性、配伍性及热采高温环境下储层保护效果的评价,建立起适用于稠油的新型有机胺完井液体系。该体系在提升稠油热采井开发储层保护效果的同时,降低完井液综合成本,为渤海油田稠油开发提质增效提供有力保障。

塔河油田稠油井生产测井技术应用效果评价

通过对比塔河油田不同稠油井测量产液剖面时的稀稠比、测量时机、仪器组合,分析成败原因,最终总结出一套适合稠油井的生产测井施工优化方案,并在两口井的施工中实施,均取得合格生产测井数据。

疏松砂岩稠油油藏防砂介质的原油-地层砂协同复合堵塞机制与规律

针对稠油出砂井防砂介质堵塞问题,使用稠油与水混合液携带地层砂,开展单向驱替流动、热采交变吞吐流动两种模式下的挡砂堵塞驱替模拟试验,揭示不同条件下割缝、绕丝、复合滤网和砾石层等多类型防砂介质的稠油-地层砂协同堵塞机制与规律,根据堵塞机制和定量关系,构建稠油-地层砂对防砂介质堵塞程度和动态产能预测模型。结果表明:高黏度稠油对防砂层多孔介质具有明显堵塞作用,渗透率损伤可高达70%;稠油防砂井中,存在稠油和地层砂对防砂介质的协同堵塞机制,稠油以束缚油的形式占据介质空间,加剧内部分选桥架堵塞,最终造成90%以上渗透率损害,但同时挡砂效果得到提升;热采蒸汽交变吞吐生产方式对稠油-地层砂的协同堵塞具有明显的解除堵塞效应;但随着交替轮次的增加,解堵和渗透率恢复幅度逐渐下降;对于稠油油藏防砂,建议挡砂精度相比常规油藏防砂精度放宽1~2个等级。

渤海稠油油田热化学复合吞吐增效技术研究与应用

针对渤海稠油油田在生产稠油井存在的原油黏度大、胶质沥青质沉积造成储层有机堵塞严重、产量递减快、边底水突进、含水上升快等问题,通过室内实验研究分析、物理模拟与参数优化开展了海上热化学复合吞吐增效技术研究。结果表明:随温度升高,胶质、沥青质扩散系数增大,石英石表面对重质组分的吸附能力减弱,有助于胶质沥青质解离;热气化学复合解堵后,岩心水测渗透率均可恢复到初始岩心水测渗透率的60%~70%;热(80℃)+气(溶解)作用下,与50℃脱气油相比可使原油黏度降低约80%;在热和化学剂作用下,原油形成低黏水包油乳状液,稠油黏度由2000 mPa·s降低至30 mPa·s,降黏率为98.5%;稠油相渗曲线测试实验(100℃)结果显示,化学剂注入后使稠油相渗曲线等渗点右移,两相共渗区域增大,油相渗透率变大,水相渗透率降低,残余油饱和度降低,开发效果改善;在热水驱过程中,注入泡沫堵调后,高渗填砂管和低渗填砂管采收率均有明显提高,低渗管采收率提高约11个百分点,高渗管采收率提高约8个百分点。模拟吞吐实验结果表明:在热+化学+气协同作用下,可至少降低含水20%~30%,采油指数由0.90 mL/(min·MPa)提高至1.95 mL/(min·MPa),可显著改善低产稠油井的开发效果。热化学复合吞吐增效技术已在渤海稠油油田现场取得成功试验,措施井含水最高降低73.4个百分点,有效期150天,平均日产油较措施前提高2.9倍,有效期内累增油4300 m^(3),为渤海稠油冷采井增储上产提供了新的技术思路和方向。

稠油冷采用冻胶分散体调驱体系的相互作用机制

目的旨在有效解决稠油化学冷采过程中降黏剂窜流现象严重、油藏动用效率低的问题,支撑稠油绿色高效开发。方法基于稠油冷采降黏剂高效降黏洗油与冻胶分散体调剖剂储层调控的协同效应,采用复配方式构建了稠油冷采用冻胶分散体调驱体系,测试其基本性能,并使用界面扩张流变仪以及流变仪,考查了体系的界面流变特性和剪切应力特性。结果体系由质量分数为0.06%~0.12%的冻胶分散体和质量分数为0.05%~0.15%的降黏剂组成,为粒径均一的低黏流体,能够降低界面张力并乳化稠油,降黏率达到95%以上。体系中降黏剂在油水界面的吸附行为决定了体系的乳化降黏能力,降黏剂通过吸附在冻胶分散体的表面提高了体系的聚结稳定性,并考查了组分含量及油藏条件对以上过程的影响。结论构建了一种兼具储层调控和高效降黏能力稠油冷采用冻胶分散体调驱体系,探明了体系中各组分间的相互作用机制,为稠油化学冷采提供了技术支持。

油田上产策略研究——以准噶尔盆地胜利油田矿权区块为例

针对准噶尔盆地胜利油田矿权区块建成百万吨级油田并稳产8年之后,面临进一步上产难题,提出并开展油田上产对策研究。油气开发企业经常面临勘探捷报频传,开发无米下锅的情况。究其原因,还在于找到的储量难以开发,而且产量上得去还要稳得住。针对春风油田排6南区块埋藏浅、原油黏度高、南部发育边水的油藏特点及不同开发阶段开发矛盾变化,形成7种开发的范式。其中,坚持注氮气辅助水平井、油水过渡带微生物采油、超稠油油井计量,以及蒸汽吞吐、蒸汽驱、热水驱协同开发的经验值得深入总结推广。针对永进油田超深层油藏高质量发展难题,对现有资料重新解读。永进油田侏罗系异常高压、裂缝发育有助于高产,坚持原始创新、独立思考、运用数学思维解决油田开发难题,才能取得永进油田规模开发突破。