bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation of the Effect of Solvent Type and Drainage Height on the Performance of Vapor Extraction (VAPEX) Process in Heavy Oil Systems
Authors: Mohammadpoor Mehdi , Torabi Farshid 
Published: June 2013

Abstract
Available large resources of heavy oil and bitumen in Western Canada are potential future energy sources. Hence, looking for an economically viable, technically feasible, and environmentally friendly heavy oil recovery technique is inevitable.
Although the dramatic decrease in the viscosity of heavy oil with the temperature increase makes the thermal recovery techniques the first choice for these reservoirs, cost associated with generating the required heat, excessive heat loss to the surrounding formations, and large amount of CO2 emitted during these thermal processes are some of major economical and environmental concerns. Solvent-based heavy oil recovery methods have recently gained some attention due to the potential advantages over the thermal processes. It has been found that the viscosity reduction resulted from injecting the appropriate solvent is comparable to that obtained by heating in some cases.
In this paper, the vapor extraction (VAPEX) process is experimentally investigated to examine the effect of injecting different solvents and drainage heights on the heavy oil recovery. For this purpose, two large visual rectangular sand-packed VAPEX models with the heights of 24.5 cm and 47.5 cm and permeability of about 5 ~ 7D were employed. A heavy oil sample with viscosity of 2500 ~ 5500 cP was used to saturate both models. Pure propane, methane, and carbon dioxide where considered as respective solvents and injected in both models under the same operating conditions. The heavy oil production rate and the produced gas-oil ratio where measured periodically during the course of experiments. In addition, the asphaltene content and the visual observation of the gas chamber evolution were monitored.
It was found that the drainage height has a significant impact on the production rate and the ultimate heavy oil recovery. The experiments with smaller drainage height showed higher recovery factor and faster recovery process for similar period of injection-production. Among three different solvents utilized in this study, propane with lower vapor pressure and higher solubility showed more promising results. Additionally, CO2 and methane were used as carrier gases and a series of CO2-based VAPEX process were conducted. Results indicated that CO2-based VAPEX could be used as a means of feasible heavy oil recovery.
Field Trial Results of an Innovative Heavy Oil Production System
Authors: Rushby M. J. , McCann R. , McAleese A. 
Published: June 2013

Abstract
An innovative heavy oil production system has been developed in conjunction with a major operator and has now entered field trials. The system is compatible with cyclic steaming operations, is capable of deployment on jointed or coiled tubing, and fundamentally addresses sand related issues. This paper describes some aspects of the design and qualification of the system, and presents initial feedback from the first field trial.
The system has been developed for heavy oil applications, utilising downhole permanent magnet motor technology and a magnetic torque converter, resulting in both scalability and high operating efficiencies. This dramatically reduces the total power requirements, and the need for expensive surface electrical installations.
A progressive cavity pump is incorporated on bottom, allowing this small diameter system to be set in well bore deviations through to the horizontal. Combined with the ability to run at variable speed and rotate in either direction; sand related failures and workovers are reduced.
This novel configuration reduces both the surface footprint and environmental impact of the well. It also reduces deployment and workover requirements; resulting in fewer and safer operations.
By combining unique technology and a novel configuration a heavy oil system has been developed which reduces total cost of ownership. The system has entered field trials in the San Joaquin Valley fields in California.
Optimal Application Conditions for Steam-Solvent Coinjection
Authors: Keshavarz Mohsen , Okuno Ryosuke , Babadagli Tayfun 
Published: June 2013

Abstract
A limited number of laboratory and field evidences showed that steam-solvent coinjection can lead to a higher oil production rate, higher ultimate oil recovery, and lower steam-oil ratio, compared with steam-only injection. However, a critical question still remains unanswered: Under what circumstances the above mentioned benefits can be obtained when steam and solvent are coinjected? To answer this question requires a detailed knowledge of the mechanisms involved in coinjection and reflection of this knowledge to its numerical simulation. Our earlier studies demonstrated that the determining factors for improved oil production rates are relative positions to the temperature and solvent fronts, the steam and solvent contents of the chamber at its interface with reservoir bitumen, and solvent diluting effects on the mobilized bitumen just ahead of the chamber edge. Then, the key mechanisms for improved oil displacement are solvent propagation, solvent accumulation at the chamber edge, and phase transition.
This paper deals with this unanswered question by deriving a systematic workflow for selecting an optimum solvent and its concentration in coinjection of a single-component solvent with steam. The optimization considers the oil production rate, ultimate oil recovery, and solvent retention in situ. Multiphase behavior of water-hydrocarbon mixtures in the chamber is explained in detail analytically and numerically. The proposed workflow is applied to simulation of the Senlac SAP pilot project to investigate reasons for its success.
Results show that an optimum volatility of solvent can be typically observed in terms of the oil production rate for given operation conditions. This optimum volatility occurs as a result of the balance between two factors affecting the oil mobility along the chamber edge; i.e., reduction of the chamber-edge temperature and superior dilution of oil in coinjection of more volatile solvent with steam. It is possible to maximize oil recovery while minimizing solvent retention in situ by controlling the concentration of a given coinjection solvent. Initiation of coinjection right after achieving the inter-well communication enables the enhancement of oil recovery early in the process. Subsequently, the solvent concentration should be gradually decreased until it becomes zero for the final period of the coinjection. Simulation case studies show the validity of the oil recovery mechanisms described.
Impact of Solvent Loss During Solvent Injection Processes
Authors: Chang Jeannine , Canada Devon , Ivory John , Forshner Ken , Feng Yu 
Published: June 2013

Abstract
Only 5 - 15% of the oil in Lloydminster heavy oil reservoirs is recovered during cold heavy production with sand (CHOPS). Solvent injection processes are being explored as a means of recovering the heavy oil remaining in the reservoir after CHOPS has been completed. Solvent retention becomes a main concern for the process economics. This paper evaluates the relative importance of different solvent retention mechanisms and how solvent can be recovered from the reservoir so that solvent injection processes (e.g. cyclic solvent injection (CSI), Vapor Extraction Process (VAPEX), thermal solvent, and steam-solvent) can be economically viable. In particular, CSI is a promising post-CHOPS follow-up process.
Sources of solvent loss / retention include: Solvent trapped in the reservoir due to surface and interfacial forces including adsorption and capillary pressureSolvent vapor (free gas or trapped bubbles) in porous mediaDissolution in un-recovered oilDissolution in formation water or thief water zonesOther possible sources such as:Lack of confinement of injected fluids; especially important for post-CHOPS reservoirsHydrate formationPrecipitated asphaltenes
Three experiments were performed to estimate solvent losses due to different retention mechanisms. In these experiments, gaseous propane was injected into a sand pack to a pressure of 750 kPag and then depressurized (at an ambient temperature of 21 °C) in 100 kPa steps to 50 kPag. The propane produced at each depressurization step was measured. The sand packs used in the experiments were: Sand pack initially saturated with water ("wet pack")Dry sand packSand pack initially flooded with water and then with dead Husky Edam oil
The experimental results showed that there was significant propane retention in unproduced oil and as solvent gas. However, little propane adsorption occurred on the sand as it had a small surface area due to an insignificant amount of clays being present in the test packs. Solvent adsorption in a reservoir can be significant if there is a considerable amount of clays with a large surface area. It may be particularly high when shale is present.
Propane concentrations in the produced water from the wet pack were similar to literature values. Solvent loss in water was small due to the low pressures involved in the test. However, solvent loss in water will be significant if the solvent dissolves into the formation water at high temperature (for liquid solvent) and/or high pressure especially if there is a significant water source to sweep away the dissolved solvent or the water causes hydrate formation.
Long Term Wellbore Isolation in Corrosive Environments
Authors: Ilesanmi Oluwagbemiga R. , Hilal Bashar , Gill Steve , Leigh Henry , Brandl Andreas , Al Mazrouei Manal , Abdullah Ali , Halim Adam Omar 
Published: June 2013

Abstract
The paper reviews two case histories about successful wellbore isolation with a suitable cementing system for a recent enhanced oil recovery / CO2 project targeting the Thamama B formation of the Bab Far North reservoir in the UAE. The first two wells were vertical observers with zonal isolation required between the Thamama A and B. These wells were expected to exhibit a naturally corrosive environment (e.g. 56, 000 ppm of CO2). To address these challenges, a fit-for-purpose cementing system, suitable for CO2 and other corrosive fluids, was developed and successfully applied. The system was designed to isolate and protect specific Thamama zones and wellbore areas that contained gaseous or liquid corrosive CO2. This cement slurry was developed with a density of 16.7 ppg exhibiting expanding properties after setting to compensate potential shrinkage issues and to improve cement bond. Laboratory test results for the developed cementing system, such as compressive strength development, thickening time, expanding properties after setting, and integrity after long term exposure towards wet CO2, are presented and discussed. Performance requirements for cementing sytems to qualify for CO2 tolerance are elucidated. Finally, the execution in the field and the quality of the cement job was evaluated. All of the special designs exhibited excellent bond log results. The favorable lab test results and the positive case history conclude that the developed cementing system can be a viable solution to provide long term zonal isolation in a wellbore with a corrosive environment.
Modeling In-Situ Combustion in a Heavy Oil Field in Romania
Authors: Ruiz Jorge , Naccache Paul , Priestley Andrew , Glatz Guenther , Crecana Virgil 
Published: June 2013

Abstract
Suplacu de Barcau, a heavy oil field in Romania with more than 2,700 wells and over 50 years of air injection history, is considered one of the world's largest in-situ combustion projects. This paper describes a 3D simulation study of a sector of the field. The sector chosen spans the entire history of the field, from a short period of cold production in the early 1960s to the current production method of cyclic steam stimulation followed by air injection. To date, about 200 wells have been drilled in this sector, which covers approximately 1.1 km2.
We present the different stages of the numerical study and review some of the difficulties involved in modeling in-situ combustion in a large model. We describe how we managed the uncertainties in the reservoir and in the fluid description, and how we overcame limitations in the available data. Kinematic data from laboratory experiments were used as a starting point, and we present details of the simplified kinematic formulation that was needed to improve the numerical performance of the simulation model.
The model is heterogeneous, so there is an uneven propagation of the combustion front. We compare historical production rates with the model predictions and estimate areas of oil that were bypassed due to this heterogeneity and to gravity override.
Analytical Evaluation of Casing Connections for Thermal Well Applications
Authors: Tao Gang , Xie Jueren 
Published: June 2013

Abstract
Thermal well technologies, such as Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD), are widely used for the exploration of heavy oil and oilsands resources. Casing connections are one of the most critical components in thermal wells in terms of the wellbore structural and pressure integrities. High temperature operation of thermal wells inevitably imposes significant axial loads on the casing connections, and as a result, a plastic strain design concept must be used for the casing and connections. In addition, thermal well design should consider the impact of formation shear movement that may be caused by changes in the stress state in the reservoir and overburden formations during thermal operations. To meet the design challenges posed by thermal wells, premium connections are usually preferred over API connections due to generally superior structural capacity and sealability. Rigorous engineering assessments, such as full-scale physical tests and analytical evaluations are often used to assess the performance of premium connections and to identify suitable connection designs for the intended applications. These engineering assessments typically consider the in-situ load conditions specified by operators, or the load cases recommended by industry guidelines, such as the recently released Thermal Well Casing Connection Evaluation Protocol (TWCCEP 2012).
This paper presents approaches and considerations for using Finite Element Analysis (FEA) to conduct the analytical evaluation of casing connections for thermal wells. Such analytical evaluations serve to determine the worst-case specimen configurations (e.g. highest potential for galling or leaking) for full-scale testing programs under the load conditions specified in the Protocol, such as make-up and thermal cycles, as well as for understanding the connection performance under in-situ load cases as specified by operators, such as bending and formation shear. Analysis results provide useful insight into connection performance in terms of structural capacity, leakage resistance and galling potential. To demonstrate the use of the proposed analysis approaches and considerations, an example case with a generic premium connection geometry is analyzed and the results are presented.
Characterizing the Effect of Heat Transfer on Multiphase Flow during the Steam-Assisted Gravity Drainage (SAGD) Process
Authors: Azom Prince N. , Kamp A. M. , Srinivasan S. 
Published: June 2013

Abstract
By solving a 1-D heat equation for single phase flow, Butler et al. (1981, 1985) derived their classical SAGD equation, which has excellent predictive capability at experimental scales but performs poorly at field scales. Several authors have tried to remedy this by accounting for multiphase flow at the steam-bitumen boundary and their efforts have resulted in modified expressions for the oil rate incorporating rate multipliers. The practice of applying rate multipliers, however results in models that seem to vary for each reservoir or experiment. Recently, by making the prior assumption that fluid saturations ahead of the steam chamber vary linearly with temperature, Sharma and Gates (2010) derived a SAGD equation that accounts for multiphase flow ahead of the steam chamber, which performs excellently at field scales but poorly at experimental scales. In this work, we couple the multiphase mass conservation equations with the energy equation and show that the multi-scale, multiphase flow phenomenon associated with SAGD is the classical Marangoni (thermo-capillary) effect which can be characterized by the Marangoni number. At low Marangoni numbers (typical of experimental scales) we get the Butler solution while at high Marangoni numbers (typical of field scales), we approximate the Sharma & Gates solution. We present results from our model in dimensionless space so they can be used as a fast SAGD predictive model within a proxy-based history matching process.
Phase Behavior and Physical Property Modeling for Vapex Solvents: Propane, Carbon Dioxide, and Athabasca Bitumen
Authors: Badamchi-Zadeh Amin , Yarranton Harvey , Maini Brij 
Published: June 2013

Abstract
Employing CO2 as the non-condensable gas in the Vapex process is an attractive option that could provide environmental benefits of CO2 sequestration along with improved Vapex performance. Mixtures of CO2 and a hydrocarbon such as propane allow the solvent to be tailored to different reservoir conditions. To test potential solvent mixtures, the phase behavior and physical properties measurements and modeling are required. We have previously reported on the phase behavior, viscosity and density of the CO2-propane-Athabasca Bitumen systems (Badamchi-Zadeh et al., 2009a,b). These results confirmed the ability of carbon dioxide and propane mixtures to sufficiently reduce Athabasca bitumen viscosity.
In this study, an oil characterization and equation of state model are developed to describe the phase behaviour of mixtures of carbon dioxide, propane, and Athabasca bitumen. The model is tuned to fit the experimental phase behaviour data for binary and ternary mixtures of these components. Solubility data for carbon dioxide and Athabasca bitumen reported by Svrcek and Mehrotra 1982 are also used.
It was found that two parameter cubic equation of state would require a third parameter (i.e. volume-shift) to better predict liquid density. The volume shift parameter was adjusted to improve cubic equation of state calculated liquid density against experimental data. Pederson (1987) viscosity correlation coefficients were modified to improve liquid viscosity prediction for propane, carbon dioxide, and bitumen mixtures.
Investigation of Alkali Resistant Polymer for Improved Heavy Oil Recovery
Authors: Doda Ankit , Kotsuchibashi Yohei , Trivedi Japan J , Narain Ravin 
Published: June 2013

Abstract
Heavy oil reservoirs in western Canada with viscosities ranging from 1,000 cp to 10,000 cp are being exploited using chemical enhanced oil recovery techniques. The most widely used polymer in enhanced oil recovery applications is hydrolyzed polyacrylamide (HPAM). The primary reason for its vast use is its higher viscosity in an aqueous solution and resistance to bio-degradation however is very prone to alkaline conditions as it hydrolyzes very rapidly under such environment.
To overcome this shortfall of conventional HPAM, a new co-polymer P(AAc-st-VP) was synthesized using Acrylic Acid (AA) and N-vinyl-2-pyrrolidinone (NVP) and proper initiator, that can offer stability against alkali. In the research presented herein, currently available conventional HPAM polymers were examined against new synthesized P(AAc-st-VP) co-polymer with improved properties by including different weight percent of N-vinyl-2-pyrrolidinone monomer for use with a focus on highly alkaline environment. Rheological properties were compared in terms of viscosity and elasticity under various NaOH concentrations and aging time, for typical alkali-polymer flood operations. The core flooding experiments of alkali-polymer (AP) flooding was conducted for oil samples collected from a heavy oil reservoir in Alberta. The results were analyzed for tertiary heavy oil recovery performance, residual resistance factor, and residual oil distribution. No significant change in rheological properties of P(AAc-st-VP) co-polymer was observed in presence of alkali even for longer aging times while the conventional HPAM showed much higher viscosity loss, becoming less effective for AP or ASP heavy oil recovery operations. Due to stable rheological characteristic under alkali condition, the new synthesised P(AAc-st-VP) co-polymer showed improved performance over conventional HPAM polymer in terms of injectivity and residual resistance factor. Analysis of the results indicates that AP flooding using P(AAc-st-VP) co-polymer could effectively overcome the drawbacks of conventional HPAM polymer and improve the recovery efficiency for the heavy oil with higher injectivity.
Smart Pad Reservoir Production Machine for Oil Sands SAGD Operations
Authors: Guo Tao , Wang Jingyi , Gates Ian D. 
Published: June 2013

Abstract
The Steam Assisted Gravity Drainage (SAGD) process is widely used in the Athabasca oil sands deposit to recover bitumen. Since the viscosity of bitumen is high at original reservoir conditions, heat is required to lower its viscosity to the point it becomes mobile enough to be recovered under gravity drainage. To heat the reservoir, steam is injected into the formation and thus SAGD is energy intense – on average, the steam-to-oil ratio (SOR) is equal to about 3.5 m3 (expressed as cold water equivalent) of steam injected per m3 of bitumen produced. Given that the fuel used to generate steam is the largest operating cost, the SOR is a key parameter for evaluating the economics of any SAGD project. The target for many SAGD operations is a SOR lower than 2.5 m3/m3. Here, we explore the use of dynamic distributed steam injection within a pad of SAGD wellpairs controlled via a Proportional-Integral-Derivative (PID) feedback controller, a concept we refer to as Smart Pad. The Smart Pad Reservoir Production Machine is designed to dynamically distribute steam injection along multiple well pairs so that over a period of operation, the pad-scale cSOR is dynamically improved as the process evolves. First, a method to condition the PID control gains is described and second, the controller is applied to a multiple well pair SAGD pad in an oil sands reservoir with a top water zone. The results demonstrate that automated control can lead to improvements of the SOR over that of constant pressure. The results show that automated PID control is able to detect the "sweet spots" (oil zones with better geological properties) in the reservoir and dynamically deliver more steam to that region. Meanwhile, it reduces the steam injection towards relatively worse reservoir quality zones, i.e. shale barriers, high permeability channel to the top water zone, to lower the local SOR. In this manner, the PID feedback controller provides an efficient method to recovery bitumen in SAGD operation, especially during the first 7-10 years' operation, where it helps to achieve a relatively low cSOR and maintain a normal level of oil recovery. Also, the PID controller reduces the degree of dependence of SAGD operation on the geological conditions of the reservoir. The algorithm described could be applied to any operating or new SAGD pad.