The Role of Capillarity in the VAPEX Process

Abstract

The vapor extraction (VAPEX) process warrants the oil industry attention because of its applicability to recover viscous oil in the cases when steam assisted gravity drainage fails due to the presence of bottom water aquifer, low heat conductivity, thin pay zone, and excessive heat losses to the adjacent formations. Dilution of heavy oil and thus lowering the viscosity, density, interfacial tension, and capillary pressure is regarded as the basic mechanism of the VAPEX process. Although researchers have studied many influencing factors on oil recovery in VAPEX, the effect of capillary pressure has never been studied or understood completely. The objective of this study is to explore the effects of capillary pressure in the VAPEX process by combining experimental results with simulation studies. Extensive experimental studies are conducted in a rectangular transparent visual cell. Grain size distribution and model height are kept constant, while the viscosity of the targeted oil is varied. Capillary pressure and relative permeability data are obtained from flooding experiments to utilize in the simulator. Analysis of results reveals that capillary pressure acts in favor of the VAPEX process by shaping up the vapor chamber, reducing free gas production and also increasing drainage rate by increasing the effective contact area for molecular diffusion.     

Experimental Investigation of Capillarity and Drainage Height Roles in the Vapor Extraction Process

The authors present the results of a novel comprehensive experimental program to investigate the roles of capillary pressure and drainage height on the performance of the VAPEX process. Measured stabilized drainage rates at lower permeability range (5.1–6.4 D) in this study show no linear relationship with square root of permeability, as reported for experiments at high permeabilities (>200 D). In these tests stabilized drainage rates are a function of drainage height to the power of 1.1–1.3.     

The Semi-Analytical Modeling and Simulation of the VAPEX Process of “Kuh-e-Mond” Heavy Oil Reservoir

Abstract

The vapor extraction process (or VAPEX) uses vaporized solvents injected into a horizontal well to form a vapor chamber within the reservoir. Vapor dissolves in the oil and enhances the oil production by decreasing the oil viscosity in heavy oil reservoirs. To evaluate the process we conduct a simulation study on an Iranian heavy oil reservoir called Kuh-e-Mond. In addition, a semi-analytical investigation of the VAPEX process has been performed. The idea is to perform VAPEX simulation for a laboratory model and find a methodology to compare the results of the simulator with the semi-analytical Butler's model. In particular, a semi-analytical dimensionless correlation for production rate that incorporates all involved physical parameters in the VAPEX process is developed. Also, we performed a sensitivity analysis on the proposed correlation to obtain its adjustable parameters and optimize using available experimental data.     

溶剂辅助重力泄油技术开采稠油室内试验

多孔介质和Hele-Shaw设备中的溶剂辅助重力泄油开采机理不同,特别是两者产生脱沥青作用的压力范围是否一致及增产幅度的差别程度如何尚不明确。为研究溶剂辅助重力泄油技术开采多孔介质中稠油的机理,建立了3层结构的溶剂辅助重力泄油可视化填砂模型,对高渗岩心溶剂辅助重力泄油不同注入压力与泄油速率关系及相同注入压力下不同渗透率岩心溶剂辅助重力泄油脱沥青降黏作用和堵塞流动通道的复合作用机理进行了室内试验研究。试验结果表明:多孔介质溶剂脱沥青作用出现在饱和蒸气压附近,试验泄油速度提高3倍,但脱沥青作用发生的压力范围较小;脱沥青作用会造成低渗地层部分孔喉堵塞。因此,低渗地层VAPEX溶剂注入压力应低于溶剂的饱和蒸气压,而高渗地层则可以充分利用脱沥青降黏作用来提高泄油速率。      

A shortcut model to estimate oil production rate in VAPEX process

An analytical model for estimating the oil production rate in the vapor extraction process (VAPEX) is presented in this work. It regards the most effective properties of fluid and reservoir in the form of the Rayleigh number. The model involves three coefficients (x₁, x₂ and x₃) that are determined through minimizing an objective function based on the difference between experimental VAPEX data and calculated data. The strength of the model was examined through comparison experimental work. Having an average relative error of 15% against the real data, the model showed its high capability for predicting the VAPEX production rate.     

The Vapor Extraction Process: Review

Abstract

The high viscosity of Canadian crude oil is a serious challenge for the recovery efficiency of this resource by conventional methods. Since 1991, the vapor extraction process (VAPEX) has emerged as a promising technology that has gained considerable attention within the oil industry. This article presents a current review of this process and its variations, as well as describing important factors affecting the process such as solvent requirements, mass transfer, asphaltene precipitation, oil rate, and wettability. Recent research has shown that VAPEX is an efficient alternative for the recovery of heavy oil.     

Feasibility study on application of the recent enhanced heavy oil recovery methods (VAPEX,SAGD, CAGD and THAI) in an Iranian heavy oil reservoir

Enhanced oil recovery (EOR) methods assisted by gravity drainage mechanism and application of sophisticated horizontal wells bring new hope for heavy oil extraction. Variety of thermal and non-thermal EOR techniques inject an external source of energy and materials such as steam, solvent vapor, or gas through a horizontal well at the top of the reservoir to reduce in-situ heavy oil viscosity. So, the diluted oil becomes mobile and flows downwards by gravity drainage to a horizontal producer located at the bottom of the reservoir.

In this paper, a sector model of an Iranian fractured carbonate heavy oil reservoir was provided to simulate and evaluate capability of some EOR techniques such as Vapor Extraction (VAPEX), Steam Assisted Gravity Drainage (SAGD), Combustion Assisted Gravity Drainage (CAGD), and Toe to Heel Air Injection (THAI) at its reservoir conditions and fluid properties. The simulation results demonstrated that wet CAGD in comparison with other nominated methods could improve heavy oil recovery factor to around 19% much more than each of SAGD, THAI, and VAPEX techniques. It could also reduce the total energy to produced oil ratio index up to 82% with respect to SAGD process in a year.

Although lower oil recovery has been gained by VAPEX process, but using a proper vaporized solvent could produce a kind of de-asphalted and upgraded oil with increased API gravity up to 29°API with no considerable solvent loss.     

The effect of different solvents on the density of undersaturated athabasca bitumen: Application in VAPEX and ES-SAGD

Predicting the density of bitumen after solvent injection is highly required in solvent-based recovery techniques like expanding solvent-steam assisted gravity drainage (ES-SAGD) and vapor extraction (VAPEX) in order to estimate the cumulative oil recovery by these processes. Using experimental procedures for this purpose is so expensive and time-consuming; therefore, it is crucial to propose a rapid and accurate model for predicting the effect of various solvents on the dilution of bitumen. In this study, an adaptive neuro-fuzzy interference system is introduced to estimate the effect of methane, ethane, propane, butane, carbon dioxide, and n-hexane on the density of undersaturated Athabasca bitumen in wide ranges of operating conditions. The obtained results were in an excellent agreement with experimental data with coefficients of determination (R²) of 0.99997 and 0.99948 for training and testing datasets, respectively. Statistical analyses illustrate the superiority of the proposed model in predicting the bitumen density at different conditions.     

New Proposals of Theoretical Models for Oil Dispersion Concentration in Flow Through a Packed Bed

Abstract

When a fluid flows through a packed bed, dispersion of fluid occurs as a result of the combined effects of molecular diffusion and mixing in the voids. Thus, in using a packed bed as a coalescer, allowance must be made for the fact that the flow deviates somewhat from plug flow. In general, the dispersion coefficient in the longitudinal direction is greater than in the radial direction. New proposals for theoretical models for dispersion concentration in the packed bed were derived using an analogy between molecular diffusion and flow of secondary dispersion inside the packed bed. A general differential equation has been solved in two directions, the axial and the radial directions, under both unsteady and steady-state conditions.     

Pseudo Relative Permeability Compensation for Numerical Dispersion

Abstract

Reservoir simulation is an approach of recreating the occurring phenomena of the reservoir by solving the general governing equations that describe the reservoir processes. Finite difference technique is an effective method to get the solution out of the reservoir models for different scenarios. In light of many benefits of using course grid models rather than fine grid and simplification, using the same relative permeability curves from laboratory cannot be applied in the fields having large grid dimensions because of numerical dispersion (smearing) of finite difference modeling. Thus, the relative permeability curves must be modified based on the grid size and then applied into the simulator. The authors introduce a methodology to demonstrate how the lab relative permeability curves can be modified based on coarse grid sizes to honor the same anticipated rock behavior. Thus, an objective function is developed to minimize the numerical dispersion in a synthetic tilted reservoir by automatically changing the relative permeability and comparing the results with the equivalent fine model. By this method, modified relative permeability curves can be obtained and introduced to the coarse model. This modification workflow is almost inevitable for reservoir simulation models with very coarse grids and it eases the history-matching process by approaching more realistic solution.     

A New Methodology to Characterize Wettability Alteration in Network Modeling

abstract

In network models, the characterization of wettability for porous media is of great significance. In this article, an index, F, called the wettability alteration index, is defined and applied to evaluate the degree of wettability change after drainage displacement. This new parameter is also analyzed as a function of interfacial tension, size and shape of pores, and capillary pressure. A new method to characterize the wettability of a porous medium after primary drainage is proposed. The imbibition relative permeability curves obtained using the wettability alteration index are compared to those obtained using traditional methods.     

大庆喇萨杏油田萨零组油层模糊综合评判

为研究开发萨零组油层的可行性，利用模糊综合评判方法对喇萨杏油田萨零组油层进行了综合评价。评价标准采用目前公认的行业标准和经验判断标准，选取流体物性、砂岩发育程度、微观孔隙结构特征、岩石敏感性、储层物性等作为评价参数，通过实际资料与标准对比，得出单因素评价矩阵。依据单一因素对油藏开发效果的影响，确定相应的权重系数，并应用模型计算出最终评价矩阵。根据最大隶属原则判定萨零组油层属于“差”的水平。     

A Laboratory Study of Recovery with Carbon Dioxide around Critical Conditions of Trinidad's Heavy Oil and Tar Sands

Abstract

VAPEX is a heavy oil recovery process where two horizontal wells are placed low in a reservoir and solvents passed into the reservoir via the higher of the two wells. This lowers the oil viscosity and allows the oil–solvent mixture to move to the lower well. CO₂ could be a suitable solvent.

Some experimental work on heavy oil recovery using CO₂ at points around its critical conditions of 31°C and 73.3 bar is presented here. The recovery was between 15 to 30% with most of the extracts lying in the range above C₁₂. Reservoirs deeper than 2500 ft are therefore suited to this type of process.     

溶剂蒸气萃取脱沥青的影响因素实验

针对稠油热采后期采收率不断下降的难题,研究利用溶剂蒸气萃取技术改善开发效果。设计了矩形可视化填砂物理模型,采用新疆风城试验区块特稠油为实验油样,利用实际油藏取心对模型进行充填,进行了一系列溶剂蒸气萃取实验,分别研究溶剂类型、操作压力和填砂后渗透率对沥青沉淀的影响。研究发现,相同条件下丙烷作萃取溶剂时比丁烷萃取效果更好;当操作压力为丙烷的饱和蒸气压时,沥青沉淀效果最好,此时溶剂的回采比例最高,溶剂的循环利用也可降低使用成本;操作压力低于饱和蒸气压力时,会降低稠油中溶入的溶剂气量,降低脱沥青效果;在同一丙烷的饱和蒸气压力下,当渗透率达到几百个达西时,沥青沉淀会使稠油黏度下降,流动性增强,从而提高采油速度;当渗透率比较低时,沥青沉淀会堵塞部分孔隙,对稠油的流动造成一定影响,导致采油速度降低。     

Modeling of External Filter Cake Build-up in Radial Geometry

Abstract

The problem of formation damage (i.e., permeability reduction due to injection of particulates), is a matter of interest in several engineering fields. In the previous attempts to model the external cake formation, cake thickness has been considered to be only dependent on time; even though in practical applications, the dependency of the cake profile on space can be important. In this article, a novel model has been developed to describe the steady state external filter cake thickness profile along the wellbore. A set of equations is derived from the force balance for a deposited particle on the cake surface and the volume conservation of the fluid in the wellbore. These equations are combined with Darcy's law in radial geometry and the equation of flow in the wellbore, and solved numerically to obtain the cake thickness and fluid velocity profiles along the wellbore.     

An Experimental Investigation of the Effect of Pressure Gradient on Gas-oil Relative Permeability in Iranian Carbonate Rocks

Abstract

The authors examine the effect of pressure gradient on gas-oil relative permeability in horizontal and vertical immiscible displacement. The experiments are conducted on a core from lower Dalan formation in the South Pars oilfield of Iran, in constant pressure, unsteady-state condition, and different pressure gradients. The Toth method is used for calculating the relative permeability and plotting proper curves. Data analysis and the effect of pressure gradient on gas-oil relative permeability are investigated. Results show that relative permeability curves are affected by pressure gradient and this effect is much prominent at low pressures due to end-effect phenomena. The dependence of relative permeability curves on pressure gradient is correlated as a function of dimensionless capillary number. The accuracy of this correlation for relative permeability prediction is examined and a new method is introduced to minimize the end-effect phenomena on relative permeability curves.     

The Estimation of Formation Permeability in a Carbonate Reservoir Using an Artificial Neural Network

Abstract

Reservoir permeability is an important parameter that its reliable prediction is necessary for reservoir performance assessment and management. Although many empirical formulas are derived regarding permeability and porosity in sandstone reservoirs, these correlations cannot be accurately depicted in carbonate reservoir for the wells that are not cored and for which there are no welltest data. Therefore, having a framework for estimation of these parameters in reservoirs with neither coring samples nor welltest data is crucial. Rock properties are characterized by using different well logs. However, there is no specific petrophysical log for estimating rock permeability; thus, new methods need to be developed to predict permeability from well logs. One of the most powerful tools that we applied by the authors is artificial neural network (ANN), whose advantages and disadvantages have been discussed by several authors. In particular, 767 data sets were used from five wells of Bangestan reservoir in a southwestern field of Iran. Depth, Neutron (NPHI), Density (RHOB), Sonic (DT) logs, and evaluated total porosity (PHIT) from log data were used as the input data and horizontal permeability obtained by coring was as target data. Sixty percent of these data points were used for training and the remaining for predicting the permeability (i.e., validation and testing). An appropriate ANN was developed and a correlation coefficient (R) of 0.965 was obtained by comparing permeability predictions and the actual measurements. As a result, the neural science can be used effectively to estimate formation permeability from well log data.     

Liquid-phase Mutual Diffusion Coefficients for Heavy Oil + Light Hydrocarbon Mixtures

Abstract:

Liquid-phase mutual diffusion coefficients are a key parameter in reservoir simulation models related to both primary production and envisioned secondary recovery processes for heavy oil and bitumen. The measurement of liquid-phase mutual diffusion coefficients in bitumen and heavy oil + light hydrocarbon or gas mixtures present numerous experimental and data analysis challenges due to the viscosity and opacity of the mixtures, the variability of density, viscosity and mutual diffusion coefficient with composition, and the multi-phase nature of these mixtures. Data analysis challenges are particularly acute. For example, recently reported mutual diffusion coefficient values for liquid mixtures of bitumen + carbon dioxide vary over three orders of magnitude when different analysis methods are applied to the same experimental data. In this contribution, we illustrate the importance of measuring composition profiles within liquids as a function of time, as a basis for mutual diffusion coefficient computation, and for allowing explicitly for the variation of diffusion coefficient and liquid density with composition in the analysis of composition profile data. Such inclusions eliminate apparent temporal variations of mutual diffusion coefficients and yield values consistent with relevant theories and exogenous data sets. Liquid-phase mutual diffusion coefficients computed for the mixtures Athabasca Bitumen + pentane and Cold Lake Bitumen + heptane exemplify the experimental and data analysis approaches.     

A Discussion About Hydraulic Permeability and Permeability

Abstract

The unit of permeability is Darcy, md, or unit of area. The symbol used to represent it is k, and the symbol K is used to represent mobility. Many references including some textbooks in soil mechanics contain confusion between these two terms, that is, hydraulic permeability K is used to refer to permeability k. In these books the term hydraulic permeability or coefficient of permeability is used to refer to mobility. Moreover, the symbols k and K are used in a contrary manner. Also, there is an error in the unit of hydraulic permeability. This work is a trial to clarify and correct this error.