This paper examines oil displacement as a function of polymer solution viscosity during laboratory studies in support of a polymer flood in the Cactus Lake reservoir in Canada. When displacing 1610-cp crude oil from field cores (at 27°C and 1 ft/d), oil recovery efficiency increased with polymer solution viscosity up to 25 cp (7.3 s-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of the paper explores why this result occurred. That is, was it due to the core, the oil, the saturation history, the relative permeability characteristics, emulsification, or simply the nature of the test? Floods in field cores examined relative permeability for different saturation histories—including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1000 cp. In nine field cores, relative permeability to water (
The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Dang, Cuong (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Nguyen, Ngoc (University of Calgary) | Yang, Chaodong (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (Computer Modelling Group Ltd.) | Li, Heng (Computer Modelling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.
We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.
The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.
Large scale polymer flooding projects in heavy oil are now ongoing in several countries and numerous other projects are at the pilot or design stages. However, there is currently no guideline for the maximum acceptable oil viscosity, one of the important parameters in the screening of new projects. Standard screening criteria do not take the latest field results into account and more recent guidelines rely mostly on viscosity averages whereas they should focus on the extreme values instead.
Since the laboratory can only provide little help to settle this issue we propose to examine current field projects for guidance.
To the best of the author's knowledge, the Pelican Lake and the Seal polymer floods, both in Canada, are operating in the highest oil viscosity ranges; moreover, the data is public and can easily be accessed. We have therefore examined the performances of polymer injection in the highest ranges of oil viscosity in both fields to get an understanding of the limits. This involved first the identification of the highest oil viscosity patterns, then the estimation of the live oil viscosity during the polymer flood in these patterns and finally the performances of the polymer flood.
Viscosity measurements are notoriously difficult and not always very reliable in heavy oil and the evaluation of in-situ viscosity is even more difficult; therefore, we used ranges of viscosity rather than definite values. The observations from Pelican Lake and Seal seem in good agreement and suggest that polymer flood is still feasible and can provide an acceleration in production for live oil viscosities up to 10,000-12,000 cp. There is little experience beyond these values, but it appears that for higher ranges of viscosity polymer injection becomes much more difficult; in Seal polymer flood does not appear to be working satisfactorily in oil viscosities above 14,000 cp.
To the best of the author's knowledge, this is the first time that the issue of maximum oil viscosity is investigated in such a manner. Although these results are preliminary and would require further confirmation from other field cases, this paper will provide guidance to engineers screening heavy oil reservoirs for potential application of polymer flood.
Thermal and solvent-based EOR methods are not applicable in many of thin post-CHOPS heavy oil reservoirs in Western Canada. Alkaline-surfactant flooding has been suggested as an alternative to develop these reservoirs. The main mechanism behind these processes has been attributed to emulsion-assisted conformance control due to the effect of synthetic and/or natural surfactants. Because nanoparticles (NPs) offer some advantages in emulsion stabilization, here we combine surface-modified silica NPs and anionic surfactants to enhance the efficiency of heavy oil chemical floods.
Based on the results of bulk fluid screening experiments, in the absence of surface-modified silica NP surfactant concentration should be tuned at the CMC (between 1 and 1.5 wt. %) to achieve the highest amount of emulsion. These emulsions are much less viscous than the originating heavy oil. However, at surfactant concentrations far from the CMC, complete phase separation occurs 24 hours after preparation. In the presence of surface-modified silica NP this emulsification was achieved at much lower surfactant concentration. The mixture of 0.1 wt. % anionic surfactant and 2 wt. % surface-modified silica NP produce a homogeneous emulsion of heavy oil in an aqueous phase. This observation was not observed when aqueous phase contains only either 0.1 wt. % anionic surfactant or 2 wt. % silica NP.
Preliminary tertiary chemical floods with water containing 0.1 wt. % surfactant and 2 wt. % surface-modified silica NP yielded an incremental oil recovery of 48 % OOIP, which is remarkably higher than that of either surfactant or NP floods with incremental recoveries of 16 and 36 % OOIP, respectively. Tertiary recovery efficiency, defined as ratio of incremental recovery factor to maximum pressure gradient during the tertiary flood, is six times greater for the surfactant/NP mixture than for the surfactant-only flood. This enhancement in recovery efficiency is of great interest for field applications where high EOR and large injectivity are desired.
The current in situ exploitation of oil sands in Alberta employs steam-based recovery methods, which are energy-intensive. A few companies are adding solvent to steam aiming to reduce steam requirements. The mechanism of oil recovery by steam with added solvent is not clear. Over the years, on several occasions- as at the present time- the oil industry has resorted to the use of solvents with steam in thermal recovery operations. The past trials with solvent were short-lived in view of the cost of solvents as well as the lack of success. Given the controversy regarding the use of solvents with steam, this work is intended to explain whether solvent injection with steam increases oil recovery or not.
In this work, a new analytical model is developed for describing the solvent-SAGD performance based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of front which satisfy the equilibrium in the system.
The objectives of this work are to predict: vapour-steam chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the solvent-SAGD process. The results show that the rate of solvent retention increases over time, while the production rates of solvent and bitumen decrease.
The efficiency of this process is evaluated using Cumulative Steam-Oil Ratio (CSOR) and cumulative solvent-oil ratio, which permits a comparison of the efficiency of SAGD and solvent-SAGD processes for different solvents. On the whole, the results of this approach give a better understanding of the mechanism of oil production during the solvent-SAGD process by interconnecting vapour chamber conditions and the conditions of heated and diluted oil ahead of the interface.
By coupling heat and mass transfer for C3H8–
This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs.
The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.
This paper presents the integrated approach for the redevelopment of the waterflood in Howard-Glasscock field located primarily in Howard County, Texas. Originally discovered in 1925, the majority of production is now commingled across the Guadalupe, Glorieta and Clearfork formations. This is a mature field which is currently in the midst of a 5 and 10 acre infill drilling program that began in 2009. Emphasis has primarily been focused on drilling producing wells, but the basis for this project was to optimize an existing waterflood to guide the development strategy of the field moving forward.
A study of the production of the wells drilled since 2009 identified stronger performance in wells with offset waterflood support. On average, waterflood was responsible for a 22% improvement in the expected recovery per well, despite a lack of patterns or a comprehensive waterflood management plan. As a result, a multi-disciplined team was commissioned to design a strategy for the redevelopment of the flood and more active management of the daily operations. Geology and reservoir engineering aspects were used to characterize the reservoir in conjunction with classical waterflood methods to understand the current performance and validate the expectations for secondary recovery.
Fracture orientation was studied based on cases of early breakthrough and was utilized in pattern identification and well placement to maximize sweep and discourage direct communication between injectors and producers. Further, the success of the waterflood in Howard-Glasscock relies on the ability to control the flow of water over a 2,000 foot vertical interval. To address this, the team has implemented a surveillance plan with improved monitoring and communication with the operations team to enhance the collection of data and in order to react to the dynamics of a waterflood. The rapid response to injection observed in this field requires proper surveillance and timely control of water flow which ultimately drives the success of the program by moving water from high water cut intervals to bypassed oil zones.
This paper details the systematic approach that was used to design the redevelopment plan for a waterflood in a 90 year old field. The scope of work is being implemented and represents an adjustment in the development plan of Howard-Glasscock moving forward. Ultimately, the enhanced performance observed in recent drilling programs and the continued success of development in this mature field hinges on understanding and managing the waterflood moving forward.
Kuznetsov, Oleksandr (Baker Hughes) | Mazyar, Oleg (Baker Hughes) | Agrawal, Devesh (Baker Hughes) | Suresh, Radhika (Baker Hughes) | Feng, Xianhua (Baker Hughes) | Behles, Jackie (Baker Hughes) | Khabashesku, Valery (Baker Hughes)
Oil sand ore flotation is a primary method of bitumen recovery from mined Athabasca tar sands. In bitumen flotation, suspended biwettable ore fines, such as clays, tend to migrate to oil-water interfaces, creating slime coating on liberated bitumen droplets. Slime coating significantly reduces the efficiency of the flotation process and overall oil recovery. Ultra-dispersed hydrophilic silica nanoparticles were found to stabilize biwettable ore fines in an aqueous phase by adsorbing onto fines surfaces, even at concentrations as low as 50 ppm. As a result, fine solids move away from oil/water interfaces, reducing the slime coating and increasing bitumen recovery during flotation of low-grade ore by more than 5%. The addition of nanoparticles has no negative effect on froth quality or oil, water and solid separation in naphthenic and paraffinic froth treatment processes. Detailed molecular dynamics (MD) simulations revealed mechanisms that improve bitumen liberation from mined oil sands in a flotation process. The studies demonstrated that colloidal nanoparticles affect many stages of the bitumen extraction process from bitumen separation to clay wettability alteration.