Multiphase flow at the edge of a steam chamber

The use of steam‐assisted gravity drainage (SAGD) to recover bitumen from Athabasca deposits in Alberta has been growing. Butler [Butler, J. Can. Pet. Tech. 1985;24:42–51] derived a simple theory to calculate the production rate of oil during SAGD in an ideal reservoir. This simple and useful theory made several assumptions about the properties of the reservoir and operating conditions of the process. The theory also assumed that the highest mobility oil is at the edge of the steam chamber and that the oil phase velocity is highest at the chamber edge and reduces with distance into the oil sand. This research examines flow conditions at the edge of the steam chamber. Specifically, a new theory is derived that takes into account the impact of oil saturation and relative permeability on the oil mobility profile at the edge of a steam chamber. It is shown that the flow behaviour at the edge of a steam chamber is more complex and is not fully represented by Butler's theory. Contrary to Butler's theory, the oil mobility has its maximum some distance away from the edge of the steam chamber. The results reveal that the higher the thermal diffusivity of the oil sand, the deeper the location where the oil phase velocity is maximum. The developed model has been validated against published experimental and field data.     

Stability of the edge of a SAGD steam chamber in a bitumen reservoir

Steam-Assisted Gravity Drainage (SAGD) is a key in-situ recovery process being used today to extract oil from bitumen reservoirs. In SAGD, an oil-depleted chamber of steam grows within the oil sands formation along a pair of horizontal wells and heats bitumen-laden oil sands at its edge. The viscosity of bitumen drops by up to five orders of magnitude when heated to above 200 °C and mobilized bitumen at the chamber edge flows under gravity to a production well located at the base of the chamber. If the steam chamber does not grow uniformly along the wellpair, then bitumen recovery is less than ideal. To raise the thermal efficiency, and consequently the economics, of the process, efficient heat transfer from chamber to the oil sands must occur and the chamber must grow uniformly along the entire length of the wellpair. If steam fingers develop at the edge of the chamber, then the heat transfer area enlarges and raises the thermal efficiency of the process since more heat is directed to the oil sands. In this research, the stability of the interface between the steam chamber and oil sands is examined by using linear stability theory. The results show that the stability is controlled by the difference between the energy content-weighted Darcy–Rayleigh numbers of the steam/water phases (displacing fluid) and the oil phase (displaced fluid). Also, the results show that at typical SAGD steam saturation temperatures, the chamber edge is unstable providing the steam quality at the edge exceeds about 50%.     

稠油复合吞吐中不同注入剂对比实验研究

稠油油藏在我国石油资源中占有重要地位,目前主要工业化开采方式是蒸汽吞吐和SGD技术等,但采收率一般在20%左右,这样大量资源无法有效采出,目前许多稠油区块开始使用注蒸汽过程中加入CO2和降粘剂等实现复合吞吐。本文在优选降粘剂的基础上,以中原油田油藏为基础开展复合吞吐过程中不同注入剂的配比优化研究。首先自主研发水平井吞吐的物理模拟实验装置,优化油溶性降粘剂+CO2+氮气+蒸汽的优化配比设计。实验结果表明,对于超稠油(粘度大于50 000 m Pa·S)复合吞吐效果不理想,这类油藏不适合,对于粘度小于50 000 m Pa·S的稠油复合吞吐可以提高单独蒸汽吞吐效果,同时得到注入剂的组合方式和具体组合参数值,对实际油藏开发有重要指导意义。     

Adaptability of a hydrophobically associating polyacrylamide/mixed‐surfactant combination flooding system to the Shengli Chengdao oilfield

We investigated the performance of a combination flooding system composed of hydrophobically associating polyacrylamide (HAPAM) and a mixed surfactant [fatty acid disulfonate anionic gemini surfactant (DMES) plus the nonionic surfactant Triton X‐100 (TX‐100)] under the reservoir conditions of the Shengli Chengdao oilfield. With 1800 mg/L HAPAM and 300–3000 mg/L mixed surfactant, the surfactant–polymer (SP) flooding system reached an ultralow oil–water interfacial tension, and the viscosity of the system was greater than 40 mPa s. After the solution was aged for 120 days, its viscosity was still more than 40 mPa s; this indicated a good aging stability. The core flooding experiments with different porous media permeabilities showed that the SP flooding system created a higher resistance factor and residual resistance factor. In addition, the indoor flooding experiments indicated that the SP combination flooding system increased the enhanced oil recovery by more than 30% over that of the original oil in place compared with the water flooding system. Therefore, it was feasible to use an SP flooding system in the Chengdao oilfield. © 2014 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2014 , 131, 40390.     

Steam fingering at the edge of a steam chamber in a heavy oil reservoir

The steam‐assisted gravity drainage (SAGD) process is one of the key in situ recovery processes being used today to recover heavy oil and bitumen. In this process, steam injected through a horizontal well, flows convectively towards the outer edges of a depletion chamber. At the edges of the depletion chamber, the steam releases its latent heat to the cool oil sand and raises its temperature. The heated oil is mobile and flows under the action of gravity to a horizontal production well located several metres below the injection well. It remains unclear what is the exact mechanism of chamber growth. Some have suggested that in addition to heat conduction, it is by convective steam flow in the form of pointed fingers at the edges of the chamber which penetrate the oil sand. In theory published by Butler [Butler, J. Can. Petroleum Technol. 1987;26(3):70–75], it was determined that the fingers can be as long as 6 m for Athabasca bitumen reservoirs. In this research, a new theory is derived and provides predictions of the rise rate which compare better to estimates derived from field thermocouple data and physical model experimental observations than values obtained from Butler's theory. The results suggest that in the absence of mobile water, heat conduction rather than steam fingers at the chamber edge is the dominant heat transfer mechanism.     

数值模拟技术在石炭系边水气藏开发中的应用

川东石炭系气藏地层水以边水形式存在,气藏的出水类型主要为裂缝水窜型和沿高渗带舌进型。本文对数值模拟方法在川东石炭系边水气藏开发中的特点进行了总结,通过云和寨和万顺场两个石炭系气藏的应用实例可以看出,数值模拟预测的云和寨石炭系气藏云和2井见水时间与实际非常接近,而应用数值模拟开发方案对万顺场石炭系气藏池6井实施排水采气,有效的保护了气藏遭受水侵的危害。     

A new reaction model for aquathermolysis of Athabasca bitumen

Aquathermolysis of bitumen occurs when it is thermally cracked in the presence of water. Current in situ technologies for bitumen production, such as Cyclic Steam Stimulation and Steam‐Assisted Gravity Drainage, inject high pressure, high temperature steam in the reservoir to heat the bitumen which in turn lowers its viscosity enabling flow to a production well. Thus, the major physical effect of steam is the heating of bitumen which mobilises it. Beyond physical interactions, chemical effects also result: steam heating produces acid gases, such as carbon oxides, sulphur dioxide and hydrogen sulphide along with small amounts of hydrogen and methane. For steam‐based in situ bitumen recovery processes, nearly all analyses, including simple drainage theories and thermal reservoir simulations, focus solely on the physical processes: heat transfer, fluid flow and thermodynamic equilibrium. However, steam chambers are also underground reactors: bitumen aquathermolysis occurs due to high temperatures and water saturation. Here, we describe a new in situ aquathermolysis reaction scheme for Athabasca bitumen to predict hydrogen, methane, carbon oxides, hydrogen sulphide and other heavy molecular weight hydrocarbons. Reaction parameters were fitted against one experimental data set and validated against other independent experimental data sets, both from the literature. Our results indicate that, to more accurately predict gas compositions and rates, the effects of aquathermolysis should be taken into account in reservoir modelling. © 2012 Canadian Society for Chemical Engineering     

注蒸汽热采技术研究进展

在研究大量文献的基础上,总结了注蒸汽采油的机理,概述了稠油注蒸汽热采的研究现状与发展趋势,着重探讨了稀油注蒸汽热采的应用前景、研究现状以及稀油注蒸汽热采还需要深入研究的课题。研究认为：稠油注蒸汽热采已是比较成熟的技术,在稠油开发中占有重要的地位,其发展趋势为利用天然气、溶剂、高温泡沫、聚合物等来改善注蒸汽热采效果;稀油油藏水驱、聚驱后转注蒸汽热采具有可行性,今后需重点解决的问题包括采用煤或核能生产蒸汽、采用水汽交注、蒸汽泡沫等方法提高稀油油藏注蒸汽热采的采收率。     

气顶油藏屏障注水技术研究

气顶油藏作为一类较为复杂的油气藏在开发中遇到的最主要问题是气顶气锥进，造成油井气窜，解决这一问题较好的方法是在油气界面处注水形成水障，以隔离气顶和油藏，达到抑制气体锥进，阻止油井气窜的目的。文章以新疆油田分公司莫北2井区气顶油藏为例，对气顶油藏屏障注水技术进行了研究。     

Regime transition in viscous and pseudo viscous systems: A comparative study

A comprehensive quantitative study on the effect of liquid viscosity (1 ≤ µ_L ≤ 1149 mPa‐s) on the local flow phenomena of the gas phase in a small diameter bubble column is performed using ultrafast electron beam X‐ray tomography. The internal dynamic flow structure and the bubble size distribution shows a dual role of the liquid viscosity on the hydrodynamics. Further, the effect of solid concentration (C_s = 0.05, 0.20) on the local flow behavior of the gas phase is studied for the pseudo slurry viscosities similar to the liquid viscosities of the gas–liquid systems. The effects of liquid and pseudo slurry viscosities on flow structure, bubble size distribution, and gas phase distribution are compared. The bubble coalescence is significantly enhanced with the addition of particles as compared to the system without particles for apparently same viscosity. The superficial gas velocity at which transition from homogeneous bubbly to slug flow regime occurs is initiated by the addition of particles as compared to the particle free system for apparently same viscosity. © 2014 American Institute of Chemical Engineers AIChE J, 60: 3079–3090, 2014     

A Review of Advanced Molecular Engineering Approaches to Enhance the Thermostability of Enzyme Breakers: From Prospective of Upstream Oil and Gas Industry

During the fracture stimulation of oil and gas wells, fracturing fluids are used to create fractures and transport the proppant into the fractured reservoirs. The fracturing fluid viscosity is responsible for proppant suspension, the viscosity can be increased through the incorporation of guar polymer and cross-linkers. After the fracturing operation, the fluid viscosity is decreased by breakers for efficient oil and gas recovery. Different types of enzyme breakers have been engineered and employed to reduce the fracturing fluid′s viscosity, but thermal stability remains the major constraint for the use of enzymes. The latest enzyme engineering approaches such as direct evolution and rational design, have great potential to increase the enzyme breakers’ thermostability against high temperatures of reservoirs. In this review article, we have reviewed recently advanced enzyme molecular engineering technologies and how these strategies could be used to enhance the thermostability of enzyme breakers in the upstream oil and gas industry.     

Gas‐Liquid Mass Transfer in Fibrous Bed Reactor with Counter‐Current Liquid Recycle

In this work, the gas‐liquid mass transfer in a lab‐scale fibrous bed reactor with liquid recycle was studied. The volumetric gas‐liquid mass transfer coefficient, k_La, is determined over a range of the superficial liquid velocity (0.0042–0.0126 m.s^–1), gas velocity (0.006–0.021 m.s^–1), surface tension (35–72 mN/m), and viscosity (1–6 mPa.s). Increasing fluid velocities and viscosity, and decreasing interfacial tension, the volumetric oxygen transfer coefficient increased. In contrast to the case of co‐current flow, the effect of gas superficial velocity was found to be more significant than the liquid superficial velocity. This behavior is explained by variation of the coalescing gas fraction and the reduction in bubble size. A correlation for k_La is proposed. The predicted values deviate within ± 15 % from the experimental values, thus, implying that the equation can be used to predict gas‐liquid mass transfer rates in fibrous bed recycle bioreactors.     

Oleic acid‐based poly(alkyl methacrylate) as bio‐based viscosity control additive for mineral and vegetable oils

This work described the design of an efficient oleic‐acid based viscosity control additive for lubricating oils as potential alternative to petroleum poly(alkyl)methacrylates (PAMAs) additives. Hence, Poly(2‐(methacryloyloxy)ethyl oleate) (PMAEO) was synthesized by free radical homopolymerization to afford a comb‐like polymer structure similar to common PAMAs. Then, in order to evaluate its efficiency as viscosity control additive, the resulting polymer was mixed at several concentrations from 1%wt to 10%wt with different oil compositions, including a mineral paraffinic oil (MPO) and an organic triglyceride oil (OTO). For all polymer‐solution blends, relative viscosities (RV) measurements showed that addition of PMAEO in MPO had a better contribution on oil viscosity at 100°C than at 20°C (RV = 1.16 at 40°C while RV = 1.25 for 3%wt of PMAEO in MPO). These results were attributed to the coil expansion of polymer chains with increasing temperature. Additionally, rheological studies showed that addition of 3%wt of PMAEO in MPO improved the MPO cold flow properties at ?30°C by decreasing the required yield stress to put the oil in motion from 310 mPa to 42 mPa. These results are in total accordance with the common viscosimetric properties of PAMAs‐based viscosity control additives at low and high temperature in mineral oils. POLYM. ENG. SCI., 59:E164–E170, 2019. © 2018 Society of Plastics Engineers     

Highly thermally conductive room‐temperature‐vulcanized silicone rubber and silicone grease

In this study, the effects of thermally conductive filler type (α‐Al₂O₃, SiC), volume fraction of the filler, and filler particle size distribution on the thermal conductivity and viscosity of room‐temperature‐vulcanized (RTV) silicone rubber and silicone grease were investigated. We were interested to find that silicone grease (or the RTV silicone rubber) had a maximum thermal conductivity (～1.48 W/mK) and a minimum viscosity (～3.4 × 10⁴ mPa s), with a definite total volume fraction of the filler (0.55) when the distribution of filler sizes (the number ratio of two different particles sizes, i.e., 0.8 and 6 μm) was 600–700. We were able to increase the thermal conductivity of the RTV silicone rubber and silicone grease beyond 2 W/mK by increasing the total volume fraction of the filler with adequate filler size distributions. © 2003 Wiley Periodicals, Inc. J Appl Polym Sci 89: 2397–2399, 2003     

A Zwitterionic Surfactant Bearing Unsaturated Tail for Enhanced Oil Recovery in High‐Temperature High‐Salinity Reservoirs

High‐temperature/high‐salinity (HTHS) reservoirs contain a significant fraction of the world's remaining oil in place and are potential candidates for enhanced oil recovery (EOR). Selection of suitable surfactants for such reservoirs is a challenging task. In this work, two synthesized zwitterionic surfactants bearing a saturated and an unsaturated tail, namely 3‐(N‐stearamidopropyl‐N,N‐dimethyl ammonium) propanesulfonate and 3‐(N‐oleamidopropyl‐N,N‐dimethyl ammonium) propanesulfonate, respectively, were evaluated. The surfactant with the unsaturated tail showed excellent solubility in synthetic seawater (57,643 ppm) and in formation brine (213,734 ppm). However, the unsaturated surfactant with a saturated tail showed poor solubility, and therefore it was not evaluated further. The thermal stability of the synthesized unsaturated surfactant solution in seawater was evaluated by heating the solution at 90 °C in a sealed aging tube for 2 weeks. The thermal stability of the unsaturated surfactant was confirmed by FTIR and NMR analysis of the aged samples at such harsh conditions. The critical micelle concentration (CMC) of the synthesized unsaturated surfactant in seawater was 1.02 × 10^?4 mol L^?1, while the surface tension at CMC was 30 mN m^?1. The synthesized unsaturated surfactant was able to reduce the oil–water interfacial tension to ~10^?1 mN m^?1 at different conditions. A commercial copolymer of acrylamide and 2‐acrylamido‐2‐methylpropane sulfonic acid (AM‐AMPS) was tested for EOR applications in HTHS conditions. The addition of the synthesized unsaturated surfactant to the AM‐AMPS copolymer increased the viscosity of the system. The increase in oil recovery by injecting the unsaturated surfactant solution and the surfactant–polymer mixture in solution was 8 and 21%, respectively. The excellent properties of the synthesized unsaturated surfactant show that surfactants with an unsaturated tail can be an excellent choice for HTHS reservoirs.     

风城油田重18井区超稠油油藏注气方式优化选择研究

水平井热采模式一直是改善特、超稠油油藏开发效果的有效手段。在热采中后期,常规同采同注的注气方式存在着蒸汽热利用率低、蒸汽波及范围小和剩余油量大等问题。研究不同注气方式对该类油藏开发效果和经济效益的影响,研究表明,水平井组一注多采和直平井组合吞吐方式均能很大程度提高蒸汽利用率,有效驱替井间的剩余油。     

Improving the operational stability of the multi‐chamber spout‐fluid bed via the insertion of a submerged partition plate

The effect of a submerged partition plate on improving the gas–solid flow robustness and stability in a three‐dimensional spout‐fluid bed with multiple inter‐connected chambers is numerically investigated by means of computational fluid dynamics coupled with discrete element method (CFD‐DEM). Notably, multiple‐chamber beds are necessary in scaling up the spout‐fluid bed. The influence of plate height on gas–solid distribution, spout‐annulus interaction and chamber interaction are also studied to optimize the design. The results demonstrate that inserting a partition plate with height above a certain threshold can effectively improve the stability of spouting and uniformly re‐distribute the flux load in each chamber, giving rise to parallel fountains and lower circulation flux of the solid phase. Results indicate that the plate height should be at least 80% of the packed bed height investigated, with the most optimal being about 92% based on steady spouting, and the maximum solid and gas exchanging fluxes between the chambers. © 2016 American Institute of Chemical Engineers AIChE J, 63: 485–500, 2017     

热采井抗高温长效水泥固井技术研究与现场应用

稠油油藏大多采用热力降粘的方式开采,主要是采用蒸汽热采的方法。注蒸汽热采一般为蒸汽吞吐,后期转为蒸汽驱,因此热采稠油井的固井必须适合和满足蒸汽吞吐和蒸汽驱开采方式。后期注蒸汽开采时,由于地层的保温效果很差,高温蒸汽在注入过程中能量通过水泥环很快耗散到地层中,导致稠油油藏达不到注蒸汽热采的效果,严重影响稠油油藏的开发效果。在注蒸汽开采过程中,水泥石在高温蒸汽环境中强度衰减严重,导致水泥环破裂损坏,使原本封固好的环空失效,引发油气水窜,严重缩短油井寿命。针对稠油油藏固井存在的问题,须研究开发一种适用于封固稠油热采井的长效固井技术,使该固井技术具有水泥浆热容高、保温效果好,可延缓蒸汽注入过程中能量损失;水泥浆具有良好的强胶结性能,大大改善固井第二界面胶结强度,有效防止油气水窜的发生,提高浅层水泥封固段长期封固效果;水泥石强度高,抗高温性能好,其强度在高温下衰减缓慢,可经受稠油热采高温蒸汽的侵蚀的优点。有效解决稠油热采井在高温驱替环境下固井质量差、油井寿命短的问题,为稠油油藏勘探开发提供有力的技术支撑。     

Solution behavior of water‐soluble poly(acrylamide‐co‐sulfobetaine) with intensive antisalt performance as an enhanced oil‐recovery chemical

In the process of oilfield development, salt tolerance is an important property for enhanced oil‐recovery (EOR) chemicals. In this study, we synthesized two acrylamide‐based sulfobetaine copolymers containing 2‐hydroxy‐3‐[(3‐methacrylamidopropyl)dimethylammonio]propane sulfonate (SHPP) or 3‐(4‐acry‐loyl‐1‐methyl‐piperazinio)‐2‐hydroxypropane sulfonate (SHMP). The interactions between these two copolymers and inorganic salts were compared, and the apparent viscosity (η_app) behaviors of copolymer–salt solutions at different shear rates and temperatures were investigated. We found that the η_app of PAPP and PAMP showed intensive antisalt performance, exhibiting an excellent antipolyelectrolyte effect. The η_app retention value of 30,000 mg/L PAMP in brine was 86.47 mPa s at 510 s^?1, and when the temperature was increased to 90 °C, it was 99.73 mPa s; this was better than that of PAPP under the same conditions. Therefore, PAMP was more applicable as an EOR chemical that have outstanding salt tolerance and temperature resistance. © 2018 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018 , 135, 46235     

川东北高温碳酸盐岩储层自转向酸研究与应用

针对川东北元坝气田高温碳酸盐岩储层水平段均匀布酸的需求,研制出一种高温转向酸产品,开展了转向酸的pH值变粘、流变等性能评价,并在现场进行了应用。研究结果表明:该转向酸具有良好的pH值变粘特性,在140℃,170 S-1条件下粘度仍然保持在100 mPa·s以上,破胶液粘度为7 mPa·s,现场酸压施工过程中在排量不变的情况下油压压差最高达到6 MPa。