No abstract

CO 2 flooding process as a common enhanced oil recovery method may suffer from interface instability due to fingering and gravity override, therefore, in this study a method to improve the performance of CO 2 flooding through an integrated ultraosund-CO 2 flooding process is presented. Ultrasonic waves can deliver energy from a generator to oil and affect its properties such as internal energy and viscosity. Thus, a series of CO 2 flooding experiments in the presence of ultrasonic waves were performed for controlled and uncontrolled temperature conditions.Results indicate that oil recovery was improved by using ultrasound-assisted CO 2 flooding compared to conventional CO 2 flooding. However, the changes were more pronounced for uncontrolled temperature conditions of ultrasound-assisted CO 2 flooding. It was found that ultrasonic waves create a more stable interface between displacing and displaced fluids that could be due to the reductions in viscosity, capillary pressure and interfacial tension. In addition, higher CO 2 injection rates, increases the recovery factor in all the experiments which highlights the importance of injection rate as another factor on reduction of the fingering effects and improvement of the sweep efficiency.

Poor cleanup efficiency of injected fracture fluid (FF) has been considered as one of the main factors contributing to the poor performance of many hydraulically fractured wells (HFWs). Limited parametric studies evaluating the efficiency of FF cleanup have not embarked on a much needed extensive investigation of variation of all pertinent parameters. In this work we present the results of over 130000 simulations of the process, for a HFW model that was constructed using a reservoir simulator. A computer code has been developed, which automatically, read input data, link the injection and production periods and create the output data. The impact of 16 parameters describing the gas and FF effective permeability of matrix and fracture, pressure drawdown, capillary pressure, and porosity have been studied for two injected FF volume values. Different statistical experimental design methods have been used to sample a reasonably wide range of variation of pertinent parameters. Linear and quadratic response surface models have been used to map the gas production loss (GPL), compared to 100% cleanup case. The results indicate that GPL is mainly controlled by parameters related to FF cleanup inside the fracture particularly fracture permeability. In some cases increased back flow of FF from matrix into fracture increases GPL. As production continues, the impact of matrix permeability and gas exponent of Corey type relative permeability curve in the matrix become more pronounced. The fracture residual gas saturation and matrix gas end points have negligible effect. The relative importance of pertinent parameters is less for lower FF injection volume and especially at higher production periods. These practical findings can be used to make a better decision on the performance of such costly operations, suggested methods for improving the cleanup efficiency of FF and the optimum fracture design practices.

Hydraulic fracturing is considered as one of the most effective stimulation techniques to improve recovery especially from unconventional low permeability reservoirs. However this promising stimulation technique sometimes does not respond as expected. Significant amount of work has been dedicated to this topic with ineffective fracturing fluid (FF) clean-up considered as one of the main reasons for this underperformance. However there are still great deals of uncertainties in this area primarily due to large number of parameters affecting FF invasion and its back flow. This work presents results of 10 different sets of numerical simulations consisting of injection, soaking and production periods for 40960 runs. Each set consists of 4096 runs and investigates the simultaneous impact of 12 pertinent parameters (fracture permeability, matrix permeability (km), end points and exponents of Corey gas and FF relative permeability curves in both matrix and fracture and matrix capillary pressure (Pcm) (depending on interfacial tension (IFT), km and pore size index). Two-level full factorial experimental design and linear response surface statistical approaches were used to sample the variables domain, covering a wide practical range determined with the support of our 11 industrial sponsors, and generate output response. Results indicate that improvement in FF mobility inside the fracture is the major factor affecting FF cleanup efficiency. In line with this finding, maintaining high Pcm, by retaining high IFT, results in cleaner fracture (lower gas production loss, GPL). That is, increasing IFT retains FF within the matrix and allows more gas to flow freely inside the fracture. This was confirmed by the corresponding saturation map of FF distribution. The effect of Pcm was more pronounced when drawdown was very low and/or soaking time was extended. At very low drawdown and when km was reduced, in a set within its variation range, the effect of the resultant increase of Pcm on GPL was more pronounced than that of the resultant decrease in FF mobility. Generally when injected FF volume increased, larger GPL was observed and reduction of GPL (cleanup) was also slower. As fracture length decreased, cleanup was faster and the effect of fracture pertinent parameters on GPL, compared to those of matrix, decreased. This works findings allows better evaluation of benefits of this costly operation leading to an optimized design and more efficient ways to improve its performance. For instance, sometimes aiming for a longer fracture, due to its FF poor cleanup performance, is not practically attractive and use of IFT reducing agents to produce more FF during the back flow period, would not have the intended impact to bring back its performance to the desired ideal level.

Horizontal wells are a proven and acknowledged technology to enhance well productivity through an increase in reservoir contact compared to that of vertical wells under the same conditions. In the last three decades, a considerable effort has been directed by many investigators to study flow around horizontal wells. In gas condensate reservoirs, in addition to the three dimensional (3D) nature of the flow geometry, the flow behaviour is further complicated by the phase change and the variation of relative permeability (kr) due to the coupling (increase in kr by an increase in velocity or decrease in IFT) and inertia (a decrease in kr by an increase in velocity) effects. Therefore, simulating such a complex 3D flow using commercial numerical simulators requires a 3D fine grid compositional approach which is very impractical, cumbersome and sometimes triggers convergence problems due to numerical instability. So far, none of these studies propose a method to deal with the complex multiphase behaviour of gas condensate flow around the horizontal well. Consequently, the introduction of a quick and reliable tool for long term productivity calculation in such a system is much needed. This paper presents a technique which was developed through a comprehensive study of the flow behaviour around horizontal wells in gas condensate reservoirs involving the creation of many in-house mathematical models using finite element and finite difference methods. An in-house simulator was developed to accurately model the multiphase flow of gas and condensate around horizontal wells. A large data bank was then generated covering the impact of a wide range of pertinent geometric and flow parameters on well performance including: well and reservoir geometries, reservoir and bottom-hole pressure, fluid velocity, gas oil ratio and fluid composition.Based on the results of the simulation, a new method has been proposed to predict the productivity of horizontal wells for the case of multiphase flow of gas and condensate. In this approach, the flow behaviour of gas and condensate around the well is quantified in terms of the effective wellbore radius of an equivalent open hole that replicates flow around the actual 3D system. The effective wellbore radius varies with fluid properties, velocity and interfacial tension (IFT), reservoir and wellbore conditions. The integrity of the new methodology has also been verified for various fluids and flow conditions.With this approach, a simple spreadsheet, without recourse to complex numerical simulation, can predict the horizontal well performance, significantly facilitating engineering and management decisions on the application of costly horizontal well technologies.