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.     

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.     

稠油油藏蒸汽辅助重力泄油参数优化研究

在SAGD开采过程中,蒸汽腔的形成与发育直接影响着最终开发效果的好坏,在泄油过程中,蒸汽腔的大小、泄油能力不断在改变,蒸汽—油界面不断在移动,为防止蒸汽突破进入生产井或者热油积聚在蒸汽腔底部压迫蒸汽腔,必须对蒸汽腔的扩展状况以及油层温度场、压力场以及含油饱和度场进行动态模拟。本文应用STARTS数值模拟软件,对注采井间进行局部加密,精细模拟井间温度、压力场,对直井—水平井组合的SAGD技术的布井参数、注采参数等进行了优化设计,并对开发效果进行了预测。验证了运用数值模拟方法研究蒸汽辅助重力泄油技术开发效果的可行性和蒸汽辅助重力泄油技术开发超稠油油藏的可行性。     

On fingering of steam chambers in steam‐assisted heavy oil recovery

Western Canadian oil sands reservoirs are among the largest petroleum accumulations in the world. Given original oil viscosity up to 5,000,000 mPa‐s, these oils are currently recovered from these reservoirs using steam which heats the oil to ～250°C with reduced viscosities <10 mPa‐s. A key issue faced by thermal recovery processes is the uniformity of the steam chamber within the reservoir. Nonuniformities of the chamber arise from multiphase flow instabilities in the porous media where fingering has been explained by penetration of low viscosity steam into viscous oil. Here, fine‐grid thermal reservoir simulation reveals that fingering takes place in the gas phase beyond the chamber edge in a zone created by gas exsolution due to elevated temperature beyond the edge of the steam chamber. The results suggest that nonuniform chambers will occur in perfectly homogeneous reservoirs which implies that uniform chambers along wells may be impossible to achieve. © 2015 American Institute of Chemical Engineers AIChE J, 62: 1364–1381, 2016     

Optimization strategies and impact of low oil price on long term SAGD projects

Steam assisted gravity drainage (SAGD) has been known as a commercially proven high ultimate recovery process for bitumen and heavy crudes. It is an energy intensive process, which is economical when oil price is above certain value. When the oil price goes below the economic threshold of project, steam injection can be decreased or completely stopped for a certain period of time, and can resume thereafter when the condition alters. The objective of this study is to provide comprehensive information about the effect of steam injection interruptions on thermal project performance. An optimization strategy for the SAGD process, in cases where steam injection interruption occurs, is discussed using actual reservoir models of different geological formations. An economical model is used to evaluate operating strategy effect on the net present value (NPV) of the project. The parameters, like shut-in period, initial steam injection period, etc, are optimized for Athabasca type oil sand reservoirs. The results show several key mechanisms exist in the life cycle of the SAGD process that must be included to reflect the field scale behaviour; otherwise, the mechanistic simplicity of the models could lead to directional and semi-quantitative conclusions. Among the mechanisms, temperature effect on basic petrophysical properties of reservoir rocks was found to have an important role in the oil recovery, and considerably impacts the results of optimization. When the steam injection is interrupted, an optimum shut-in period can be determined to maximize the oil recovery. The optimum length of steam injection interruption depends on the initial steam injection period.     

Numerical simulation of solvent and water assisted electrical heating of oil sands including aquathermolysis and thermal cracking reactions

Simulations of bitumen recovery using solvent‐ and water‐assisted electrical heating of oil sands are presented to evaluate the process and to study gas generation. Aquathermolysis and thermal cracking and dissolution of acid‐gases in water are included. Steam‐assisted gravity drainage (SAGD) is also simulated for comparison. Results show that gas generation negatively impacts SAGD. However, in electrical heating dissolution of gases into solvent weakens their negative impact. Results indicate that SAGD generates a larger gas volume than electrical heating. In both processes, methane is found to be the major species in the produced gas and H₂S concentration can reach high values. While the effect of acid–gas solubility in water on oil recovery is not evident its effect on generated gas volume is significant. Simulation results demonstrate that electrical heating is more energy efficient than SAGD. These results find application in design of experiments and pilot and field‐scale implementation of the process. © 2017 American Institute of Chemical Engineers AIChE J, 63: 4243–4258, 2017     

Heavy oil recovery efficiency using SAGD,SAGD with propane co-injection and STRIP-SAGD

Primary oil recovery methods in heavy oil basins generally extract 5–10% of the available resource, with the vast majority left in the ground and recoverable only through Enhanced Oil Recovery (EOR) methods. Traditional EOR methods, such as SAGD and solvent-assisted SAGD, generate steam in surface facilities and inject it underground to mobilize the oil for production. However, these methods can have considerable energy losses that significantly impact process performance. In contrast, the Solvent Thermal Resource Innovation Process (STRIP) technology, which uses down hole combustion of methane to produce CO₂ and steam, reduces the operating and capital costs of surface facilities, saving more than 50% of the energy typically required for thermal production. In this work, simulations of conventional SAGD, SAGD with a non-condensing solvent (propane), and STRIP-SAGD for a typical bitumen reservoir in the Fort McMurray region in Alberta, Canada were performed using the combined software system ADGPRS/GFLASH. SAGD simulations used steam injection with a quality of 0.8 while STRIP simulations injected a vapor–liquid mixture with a quality of 0.8. Furthermore, both solvent-based EOR methods required longer operation periods than conventional SAGD to recover a similar amount of oil. However, when compared on the basis of cumulative oil produced for the same overall energy input, it is shown that STRIP-SAGD recovered more oil per kJ of energy input to the reservoir than either SAGD or SAGD with propane co-injection.     

薄层稠油油藏SAGD物理模拟研究

紧密围绕杜84块兴Ⅰ组油藏的地质特点与开发现状,依据相似原理设计建立了比例物理模型,开展SAGD比例物理模拟实验,探讨了薄层稠油双水平井SAGD开采中蒸汽腔的形成和发育过程,生产特征和开发效果,预测了盖层的热损失,可为开发方案编制提供借鉴。     

Effect of Operating Temperature on Water‐Based Oil Sands Processing

Operating temperature is one of the most important controlling parameters in oil sands processing. Considering the massive energy consumption and green house gas emission, lowering the processing temperature is highly desirable. To achieve such an ambitious goal requires a comprehensive understanding on the role of temperature in oil sands processing. This paper provides an overview of major findings from existing studies related to oil sands processing temperature. The relation between temperature and bitumen recovery is discussed. The effect of temperature on the physiochemical properties of oil sand components, such as bitumen viscosity, bitumen surface tension and surface potentials of bitumen and solids, is analyzed. The interactions between bitumen and solids and between bitumen and gas bubbles as a function of temperature are recounted. Also discussed is the role of chemical additives in oil sand processing. It has been found that temperature affects nearly all properties of oil sands among which bitumen viscosity and bitumen‐solids adhesion impose a prominent impact on bitumen recovery. The use of selected chemical additives can reduce bitumen viscosity and/or the bitumen‐solids adhesion, and thus provide a possible way to process oil sands at a low temperature while maintaining a high bitumen recovery.     

Solvent screening for non‐aqueous extraction of Alberta oil sands

Non‐aqueous extraction of bitumen from oil sands has the potential to reduce fresh water demand of the extraction process and eliminate tailings ponds. In this study, different light hydrocarbon solvents, including aromatics, cycloalkanes, biologically derived solvents and mixtures of solvents were compared for extraction of bitumen from Alberta oil sands at room temperature and ambient pressure. The solvents are compared based on bitumen recovery, the amount of residual solvent in the extracted oil sands tailings and the content of fine solids in the extracted bitumen. The extraction experiments were carried out in a multistage process with agitation in rotary mixers and vibration sieving. The oil sands tailings were dried under ambient conditions, and their residual solvent contents were measured by a purge and trap system followed by gas chromatography. The elemental compositions of the extraction tailings were measured to calculate bitumen recovery. Supernatants from the extraction tests were centrifuged to separate and measure the contents of fine solid particles. Except for limonene and isoprene, the tested solvents showed good bitumen recoveries of around 95%. The solvent drying rates and residual solvent contents in the extracted oil sands tailings correlated to solvent vapour pressure. The contents of fine solids in the extracted bitumen (supernatant) were below 2.9% for all solvents except n‐heptane‐rich ones. Based on these findings, cyclohexane is the best candidate solvent for bitumen extraction, with 94.4% bitumen recovery, 5 mg of residual solvent per kilogram of extraction tailings and 1.4 wt% fine solids in the recovered bitumen. © 2012 Canadian Society for Chemical Engineering     

Theoretical studies on the gravity drainage of heavy oil during in-situ steam heating

One concept for the in-situ production of oil from the tar sands involves the continuous injection of steam into a growing steam-saturated volume or steam chamber. Steam flow to the boundary of the chamber, condenses and gives up its heat to the surrounding oil sands. The condensate and heated oil flow by gravity to a production well located at the bottom of a chamber and are removed continuously. The well may consist of a horizontal slotted pipe. This paper describes the theory of operation of such a process and an equation is derived which predicts the rate of drainage.     

Understanding Water‐Based Bitumen Extraction from Athabasca Oil Sands

The current state of knowledge on the fundamentals of bitumen recovery from Athabasca oil sands using water‐based extraction methods is reviewed. Instead of investigating bitumen extraction as a black box, the bitumen extraction process has been discussed and analyzed as individual steps: Oil sand lump size reduction, bitumen liberation, aeration, flotation and interactions among the different components that make up an oil sand slurry. With the development and adoption of advanced analytical instrumentations, our understanding of bitumen extraction at each individual step has been extended from the macroscopic scale down to the molecular level. How to improve bitumen recovery and bitumen froth quality from poor processing ores is still a future challenge in oil sands processing.     

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     

Ethyl acetate as a bio-based solvent to reduce energy intensity and CO2 emissions of in situ bitumen recovery

We introduce ethyl acetate (EA), a bio-based chemical, as a potential solvent for bitumen recovery through comprehensive phase behavior and numerical simulation studies. Phase behavior and thermophysical properties of EA/live bitumen are measured at temperatures and pressures up to 190°C and 4 MPa, respectively. Experimental studies suggested that coinjection of EA with steam can reduce the bitumen viscosity by several orders of magnitude. Our numerical simulations show that coinjection of 2–8 mol% EA with steam can significantly reduce the steam-oil-ratio (SOR) by almost 0.9 units while increasing the bitumen production rate. This reduction in SOR can be translated to significant energy saving of ~2.2 GJ, emission reduction of ~120 kg of CO₂, and wastewater reduction of ~120 m³ per ton of the produced bitumen, which are almost 20–25% lower than the steam-assisted gravity drainage (SAGD) process.     

Water‐Based Bitumen Recovery from Diluent‐Conditioned Oil Sands

Important process development aspects leading to more efficient bitumen recovery from diluent‐conditioned oil sands by water‐based methods are discussed. Bitumen viscosity of 0.5–2 Pa·s is required at the processing temperature and can be reduced to this level by bitumen dilution with an organic solvent. Oil sand porosity, however, poses a restriction on the amount of diluent that can be accepted by the oil sand. Also oil sand‐diluent conditioning time is an important process parameter and can vary from a few minutes for oil sands with low‐viscosity bitumen to several hours if viscosity of the bitumen is high. Additionally, the bitumen separation efficiency during digestion and flotation can be enhanced by reducing the bitumen/water interfacial tension through addition, for example, of tripolyphosphate to the aqueous phase.     

Assessment of Bitumen Re c overy from the Athabasca Oil Sands Using a Laboratory Denver Flotation Cell

A methodology was developed in this study to evaluate the effect of operating parameters on the processability of oil sands using small‐scale laboratory experimental devices. By subtracting bitumen recovered to the froth by entrainment with water, the concept of “true flotation recovery” is proposed to describe bitumen recovery resulting from bitumenbubble attachment. The experimental results indicated that “true flotation recovery” is a more sensitive and meaningful marker than overall bitumen recovery to evaluate the processability of oil sands using small‐scale laboratory test units.     

Development of a vision‐based online soft sensor for oil sands flotation using support vector regression and its application in the dynamic monitoring of bitumen extraction

Extraction from oil sands is a crucial step in the industrial recovery of bitumen. It is challenging to obtain online measurements of process outputs such as bitumen grade and recovery. Online measurements are a prerequisite for innovating better process control solutions for process efficiency and cost reduction. We have developed a soft sensor to provide online measurements of bitumen grade and recovery in a flotation‐based oil sand extraction process. Continuous froth images were captured using a VisioFroth camera system on a batch flotation unit. A support vector regression (SVR) model with a Gaussian kernel was constructed to develop a soft sensor for bitumen grade and recovery using froth image features as the inputs. The model was trained and validated for batch flotation of different grades of oil sands ore at industry‐relevant process conditions. A Dean‐Stark analyzer was used to obtain offline grade and recovery measurements that were used to calibrate the soft sensor. Mean squared errors (MSE) of 62 and 74 were achieved for grade (%) and recovery (%), respectively, and this was obtained using 5‐fold cross validation. The developed soft sensor model has been applied successfully in the real‐time dynamic monitoring of flotation grade and recovery for different grades of ore and operating conditions.

     

Processibility of Athabasca Oil Sand Using a Laboratory Hyd ro t ransport Extraction System (LHES)

A novel laboratory scale apparatus has been developed and used to assess the extraction performance of oil sands under conditions analogous to current industrial processes. The apparatus can be used to investigate independently, the liberation of bitumen from the sand as well as air‐bitumen attachment and bitumen recovery. Experiments show that lower operating temperatures have a detrimental effect on bitumen recovery and controlled air addition is beneficial for recovery. The liberation of bitumen from sand grains has been found to proceed faster than air attachment and bitumen recovery, making the flotation the ratelimiting step in the extraction process. The potential benefit of staged air injection into hydrotransport pipelines as a possible process aid is discussed.     

水基提取技术用于油砂分离的研究进展

油砂作为一种重要的非常规油气资源,其分离技术的研究近些年来引起了国内科研工作人员的重视。介绍了目前世界上最重要的油砂分离技术--水基提取技术的基本原理及影响油砂分离的重要影响因素,阐述了油砂结构、特性与水基提取分离的重要关系及分离条件对沥青回收率的重要影响作用,同时探讨了原子力显微镜用于油砂水基分离过程中相关微观机理研究的重要应用,最后对水基提取技术用于油砂工业生产的流程进行了简单介绍。     

Effect of Temperature on the Stability of Froth Formed in the Recycle Process Water of Oil Sands Extraction

The formation of a stable froth on the top of separation vessels plays an important role in bitumen flotation during bitumen recovery from oil sands. The effect of temperature on the stability of froth using recycle process water employed in bitumen extraction was investigated using a water column. The froth became less stable with increasing solution temperature. Once the solution temperature increased above 50°C, irreversible precipitation of the surfactants present in the recycle process water was observed, resulting in a less stable froth.