Screening of Oil Pools on Alaskan North Slope and Phase Behavior Study of Viscous Oil and CO2 System in Conjunction with CO2 Sequestration

Abstract

Carbon dioxide gas, a greenhouse gas (GHG), is released in the atmosphere by combustion of solid waste, wood, and fossil fuels for energy generation. Due to conspicuous absence of CO₂ sequestration studies for Alaska, the study of CO₂ sequestration options on North Slope has a very important role to play. The screening of the oil reservoirs to evaluate the technical feasibility with respect to their CO₂-EOR potential was performed by calculating the rank of the oil reservoirs with parametric approach. CMG-WinProp® simulator was used to predict phase behavior for CO₂ injection in viscous oil by tuning the equation-of-state.     

Modeling crude oil gasification

Abstract

The characteristics of CO₂-gasification of crude oil under steady-state condition were studied using a simulator. The model was developed using the minimization Gibbs free energy minimization. The effects of reactor temperature and CO₂/crude oil ratio on gas composition and lower heating value (LHV) of the produced syngas were investigated. As a result, the maximum LHV was obtained at a CO₂/crude oil ratio of 0.1 and gasification temperature of 800?°C.     

The Evaluation of Variable-Injection Rate Waterflooding,Immiscible CO2 Flooding,and Water-alternating-CO2 Injection for Heavy Oil Recovery

Abstract

Despite the existence of studies for separate evaluation of waterflooding, immiscible CO₂ flooding, and CO₂ water-alternating gas (WAG) for heavy oil recovery, there is a lack of an experimental, comparative evaluation of these three methods. The authors conducted tests for comparative evaluation of variable-injection rate waterflood (VIWF), immiscible CO₂ flood, and CO₂ WAG. The results illustrate the (a) effectiveness of VIWF, immiscible CO₂ flood, and CO₂ WAG; (b) effect of permeability and oil viscosity on VIWF, immiscible CO₂ flood, and CO₂ WAG; (c) effect of injection rate on VIWF; and (d) effect of slug ratio on CO₂ WAG.     

烃组分对CO2驱最小混相压力的影响

针对CO_2-EOR原油组分对混相能力影响的问题,应用界面张力消失法设计了不同碳数烃组分、不同族烃组分、不同含量烃组分混合模拟油与CO_2的最小混相压力实验,分析不同族烃组分与CO_2最小混相压力的变化规律,探寻原油中影响CO_2驱最小混相压力的关键组分。研究表明:原油中不同组分与CO_2的最小混相压力不同,相同碳数烃组分最小混相压力依次为:烷烃、环烷烃、芳香烃;同族烃的碳数越小,最小混相压力越小;相同碳数烃类的混合组分模拟油的最小混相压力小于单一烃组分的最小混相压力;原油中低碳数烷烃含量增加,最小混相压力降低,高碳数芳香烃含量增加,最小混相压力升高。该研究结果为多种类型油藏实施CO_2驱提高采收率提供了数据材料及理论支撑。     

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.     

An Integrated Decision Support System for Management of CO2 Geologic Storage in the Weyburn Field

Abstract

Geologic storage of CO₂ in depleted oil reservoirs is considered to be an effective approach for both facilitating GHG sequestration and enhancing oil recovery. However, as a potential problem in the long run, risks associated with geological storage of CO₂, such as leakage to the groundwater and atmosphere, might pose significant threats to local communities and surrounding environment. Identification and evaluation of such risks are essential for the long-term management of CO₂ storage. Doing so requires a set of advanced technologies in order to well understand the long-range transportation of CO₂ and its impact mechanisms. This study developed an integrated decision support framework for the Weyburn Field. This system included modules of data management, inexact hybrid numerical simulation, optimization for CO₂ EOR processes, hybrid fuzzy-stochastic risk assessment, and post-modeling analysis. A user-friendly interface was designed through visual language programming. Such an effort would provide project managers with a collection of measures for analyzing and visualizing operations and development of different applicable technologies. Valuable information can be provided to EOR project operators about what might be required for new projects or project expansions and how to go about gathering and using the data they will need.     

Operation Parameters on CO2-Foam process

Abstract

Reducing the mobility of CO₂ by means of generating in situ foam is an effective method for improving the oil recovery in CO₂ flooding processes. Implementation of the CO₂-foam technique typically involves the co-injection of CO₂ and surfactant solution into the porous medium. The surfactant molecules form bubble films that trap the flowing CO₂ molecules. The effectiveness of the CO₂-foam process is measured in terms of foam mobility. The mobility of CO₂-foam is affected by different operation parameters, such as pressure, temperature, foam quality, and brine concentration. However, surfactant type governs the overall efficiency of the CO₂-foam process. This paper presents the results of a series of experiments conducted to study the effect of various parameters on the CO₂-foam process. Bottle tests were conducted for four commercially available surfactants and among them, Chaser CD-1045 was found to be the most effective surfactant for CO₂-foam flow under reservoir conditions. It was observed that an increase in pressure from 1, 200 psi to 1, 500 psi leads to increase of the mobility of CO₂-foam, and an increase in temperature from 72 to 122°F reduces the mobility. Also, as the foam quality increases from 20 to 80%, the mobility decreases. It was observed that there was no significant effect on the mobility with an increase in brine concentration from 1 to 3 wt%.     

Asphaltene Deposition under CO2 Injection: An Experimental Study of the Bangestan Reservoir of Ahwaz Oilfield,SW Iran

Abstract

It is essential that precipitation of asphaltenes is recognized early in the planning stage of any CO₂ enhanced oil recovery (EOR) project so that appropriate testing can be performed to evaluate whether there will be a negative impact on reservoir performance. This article presents detailed evaluations of slim tube data that were obtained during CO₂ injection using a medium-gravity Iranian crude oil.

A crude oil from Bangestan reservoir of Ahwaz oilfield containing 18.2% asphaltenes with ~31.5 °API gravity was flooded by purified CO₂ (>96% CO₂) in a slim tube apparatus under 2,700 psi at 110°C. We were going to determine the minimum miscibility pressure (MMP) of the sample oil under injection of CO₂ flood, but when a CO₂ slim tube test was performed for this oil at 2,700 psi, less than half of the saturated oil in the tube was recovered, which implied that the displacement process was immiscible. At this pressure, the asphaltene deposition in the slim tube apparatus was so severe that even a pressure gradient of 6,200 lb/in² was not able to displace any fluid through the capillary tube. Therefore, we abandoned MMP determination with this sample and investigated the problem.

Due to the high percentage of asphaltenes in the sample, using the slim tube MMP as an apparatus for determining minimum miscibility pressure of CO₂ and sample oil can be misleading.     

Risk Assessment of CO2 Geological Storage and the Calculation of Storage Capacity

Abstract

Greenhouse gas emission is becoming serious, and attention has been paid to CO₂ geological storage which will not only help to achieve CO₂ reduction in air but improve oil recovery. This article provides risk assessment of CO₂ geological storage and calculation of storage capacity, which was validated in an oilfield.     

Interfacial Interactions Between Crude Oil and CO2 Under Reservoir Conditions

Abstract

In this paper, an experimental technique was developed to study the interfacial interactions between crude oil and CO₂ under reservoir conditions. By using the axisymmetric drop shape analysis (ADSA) for the pendant drop case, this new technique makes it possible to measure the interfacial tensions (IFTs) between crude oil and solvents, such as CO₂, at high pressures and elevated temperatures. The major component of this experimental setup is a see-through windowed high-pressure cell. In this study, the IFT of the crude-oil–CO₂ system was measured as a function of pressure at two fixed temperatures. It was found that, due to mutual interfacial interactions between crude oil and CO₂, their dynamic IFT gradually reduces to a constant value, i.e., the equilibrium IFT. The major interfacial interactions observed in this study include light-ends extraction and initial turbulent mixing. At T = 58°C, the equilibrium IFT reaches 1–2 dyne/cm when P ≥ 13.362 MPa, and only partial miscibility is achieved even up to P = 28.310 MPa. Thus, this experimental study shows that only partial miscibility can be obtained in most CO₂ flooding reservoirs. In addition, it is expected that the observed light-ends extraction and initial turbulent mixing phenomena may have significant effects on ultimate oil recovery and long-term CO₂ sequestration.     

Changes in the properties of conventional crude oil before and after CO2 flooding

Abstract

In order to enhance oil recovery of a conventional oil reservoir by CO₂ flooding, the changes in the properties of the crude oil before and after CO₂ flooding are systematically investigated by on-site sampling and experimental testing. The results show that, after CO₂ flooding, the light hydrocarbons of the produced crude oil is increased and the heavy hydrocarbons of the produced crude oil is decreased due to the deposition of resins and asphaltenes in the pores of the formation. In addition, the produced fluid (a mixture of oil and water) has a high water separation rate, the oil- water interface has a high tension value, and the crude oil has a high acid value and a low viscosity. The conclusions can provide a certain guidance for high-efficiency development of a conventional oil reservoir by CO₂ flooding.     

Hybrid connectionist model determines CO2–oil swelling factor

In-depth understanding of interactions between crude oil and CO₂ provides insight into the CO₂-based enhanced oil recovery (EOR) process design and simulation. When CO₂ contacts crude oil, the dissolution process takes place. This phenomenon results in the oil swelling, which depends on the temperature, pressure, and composition of the oil. The residual oil saturation in a CO₂-based EOR process is inversely proportional to the oil swelling factor. Hence, it is important to estimate this influential parameter with high precision. The current study suggests the predictive model based on the least-squares support vector machine (LS-SVM) to calculate the CO₂–oil swelling factor. A genetic algorithm is used to optimize hyperparameters (γ and σr2) of the LS-SVM model. This model showed a high coefficient of determination (R² = 0.9953) and a low value for the mean-squared error (MSE = 0.0003) based on the available experimental data while estimating the CO₂–oil swelling factor. It was found that LS-SVM is a straightforward and accurate method to determine the CO₂–oil swelling factor with negligible uncertainty. This method can be incorporated in commercial reservoir simulators to include the effect of the CO₂–oil swelling factor when adequate experimental data are not available.     

CO2 sequestration through enhanced oil recovery in a mature oil field

Recent advances in enhanced oil recovery (EOR) technology create new opportunities for CO₂ sequestration. This paper proposes a technical–economic model for underground storage of CO₂ emitted by a fertilizer industry in the Northeast of Brazil, in a hypothetical mature oil reservoir through EOR operation. Simulations based on mass, energy and entropy balances, as well as economic analysis, were assessed for the process of CO₂ sequestration combined with EOR. This model takes into account the energy requirements for the whole CO₂ sequestration process, as well as the emissions inherent to the process. Additionally, a breakdown cost methodology is proposed to estimate the main financial determinants of the integrated EOR with CO₂ sequestration (costs of CO₂ purchase, compression, transportation and storage). Project evaluation is derived from a cash flow model, regarding reservoir production profile, price and costs, capital expenditures (CAPEX), operating expenditures (OPEX), carbon credits, depreciation time, fiscal assumptions etc. A sensitivity analysis study is carried out to identify the most critical variables. Project feasibility, as expected, is found to be very sensitive to oil price, oil production, and CAPEX. Moreover, there is the contribution from the mitigation of the greenhouse gas (GHG) by storing a significant amount of CO₂ in the reservoir where it can remain for thousands of years.     

Performance Evaluation of Cyclic Pressure Pulsing in a Depleted,Naturally Fractured Reservoir with Stripper-Well Production

Abstract

We present a parametric study on the operational parameters of cyclic pressure pulsing with N₂ and CO₂. We aim to develop a better understanding of how operational parameters affect the process performance in a shallow, naturally fractured, and depleted reservoir of the Big Andy Field in eastern Kentucky. The study includes analyses of various design parameters such as the injection rate, lengths of injection and soaking periods, cycle rate limits, and number of cycles. Incremental oil production, peak oil rate, and net present value (NPV) are considered as the performance criteria. Analyses have been performed using a single-well, dual-porosity, compositional reservoir model.     

Modeling of CO2 capture from gas stream emissions of petrochemical industries by membrane contactor

Abstract

Process optimization of CO₂ removal from natural gas by a polyvinylidene fluoride hollow-fiber membrane contactor is a major goal of many computational fluid dynamics (CFD) simulations in this area. In this study, a 2D CFD model based on mass transfer equation inside the tube, the membrane, and the shell section of a HMFC at steady state and laminar conditions is developed and solved by COMSOL Multiphysics with finite element approach. Simulation results show an excellent agreement with experimental data. The model predicts that higher liquid velocity and membrane porosity results in higher CO₂ removal, because of enhancement of effective diffusion coefficient. Also, taller fiber length results in higher contact area and higher mass transfer of CO₂ from natural gas into distilled water. Although higher temperature will decrease the CO₂ removal.     

A numerical simulation study of CO 2 injection for enhancing hydrocarbon recovery and sequestration in liquid-rich shales

Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO₂) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organicrich shale could permanently store CO₂ without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO₂-enhanced oil shale recovery and shale formation CO₂ sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO₂ injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO₂ flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO₂ injectivity.     

Modeling CO2 miscible flooding for enhanced oil recovery

The injection of fuel-generated CO2 into oil reservoirs will lead to two benefits in both enhanced oil recovery (EOR) and the reduction in atmospheric emission of CO2. To get an insight into CO2 miscible flooding performance in oil reservoirs, a multi-compositional non-isothermal CO2 miscible flooding mathematical model is developed. The convection and diffusion of CO2-hydrocarbon mixtures in multiphase fluids in reservoirs, mass transfer between CO2 and crude, and formation damages caused by asphaltene precipitation are fully considered in the model. The governing equations are discretized in space using the integral finite difference method. The Newton-Raphson iterative technique was used to solve the nonlinear equation systems of mass and energy conservation. A numerical simulator, in which regular grids and irregular grids are optional, was developed for predicting CO2 miscible flooding processes. Two examples of one-dimensional (1D) regular and three-dimensional (3D) rectangle and polygonal grids are designed to demonstrate the functions of the simulator. Experimental data validate the developed simulator by comparison with 1D simulation results. The applications of the simulator indicate that it is feasible for predicting CO2 flooding in oil reservoirs for EOR.     

Influence of pressure and CO2 content on the asphaltene precipitation and oil recovery during CO2 flooding

During CO₂ flooding, the crude oil is treated with CO₂, and meanwhile it is displaced by CO₂. Based on the two processes, the influence of pressure and CO₂ content on the asphaltene precipitation and oil recovery efficiency are systematically investigated by indoor simulation experiment. With the increase of the pressure or CO₂ content during CO₂ treatment, the amount of asphaltene precipitation can be increased to a certain value. Correspondingly, the degrees of the changes of oil-water interface, the compositions of crude oil, and reservoir permeability are positively correlated with the amount of asphaltene precipitation. However, during the process, the oil recovery has an optimal value due to the combined action of asphaltene precipitation and the improvement of flow performance of the crude oil. These conclusions can provide a basis for high efficiency development of low permeability oil reservoirs by CO₂ flooding.     

Exploitation of fractured shale oil resources by cyclic CO2 injection

With shale oil reservoir pressure depletion and recovery of hydrocarbons from formations, the fracture apertures and conductivity are subject to reduction due to the interaction between stress effects and proppants. Suppose most of the proppants were concentrated in dominant fractures rather than sparsely allocated in the fracture network, the fracture conductivity would be less influenced by the induced stress effect. However, the merit of uniformly distributed proppants in the fracture network is that it increases the contact area for the injection gas with the shale matrix. In this paper, we address the question whether we should exploit or confine the fracture complexity for CO₂-EOR in shale oil reservoirs. Two proppant transport scenarios were simulated in this paper: Case 1—the proppant is uniformly distributed in the complex fracture system, propagating a partially propped or un-propped fracture network; Case 2—the proppant primarily settles in simple planar fractures. A series of sensitivity studies of the fracture conductivity were performed to investigate the conductivity requirements in order to more efficiently produce from the shale reservoirs. Our simulation results in this paper show the potential of CO₂ huff-n-puff to improve oil recovery in shale oil reservoirs. Simulation results indicate that the ultra-low permeability shales require an interconnected fracture network to maximize shale oil recovery in a reasonable time period. The well productivity of a fracture network with a conductivity of 4 mD ft achieves a better performance than that of planar fractures with an infinite conductivity. However, when the conductivity of fracture networks is inadequate, the planar fracture treatment design maybe a favorable choice. The available literature provides limited information on the relationship between fracture treatment design and the applicability of CO₂ huff-n-puff in very low permeability shale formations. Very limited field test or laboratory data are available on the investigation of conductivity requirements for cyclic CO₂ injection in shale oil reservoirs. In the context of CO₂ huff-n-puff EOR, the effect of fracture complexity on well productivity was examined by simulation approaches.