Foam assisted CO2 enhanced oil recovery has attracted increasing attention of oil companies (operators and service companies) and research institutions mainly due to the potentially high benefit of foam on CO2-EOR.
Miscible and immiscible CO2 flooding projects are respectively proven and potential EOR methods. Both methods have suffered from limited efficiency due to gravity segregation, gas override, viscous fingering and channeling through high
permeability streaks. Numerous theoretical and experimental studies as well as field applications have indicated that foaming of CO2 reduces its mobility, thereby helping to control the above negative effects. However, there are still various conceptual and operational challenges, which may compromise the success and application of foam assisted CO2-EOR.
This paper presents a critical survey of the foam assisted CO2-EOR process to reveal its strengths, highlight knowledge gaps and suggest ways. The oil recovery mechanisms involved in CO2 foam flood, the effect of gaseous and soluble CO2 on the process, synergic effect of foaming agent and ultra-low IFT surfactants, logistic and operational concerns, etc. were identified as among the main challenges for this process. Moreover, the complex flow behaviour of CO2, oil, micro-emulsion and brine system dictates a detailed study of the physical-chemical aspects of CO2 foam flow for a successful design. Unavailability of reliable predictive tools due to the less understood concepts and phenomena adds more challenges to the process results and application justifications.
The study highlights the recent achievements and analysis about foam application and different parameters, which cannot be avoided for a successful foam assisted CO2 flood design and implementation. Accordingly, the study also addresses prospects and suggests necessary guidelines to be considered for the success of CO2 foam projects.
Screening for Enhanced Oil Recovery (EOR) processes is a critical step in evaluating future development strategies for depleted reservoirs under primary and secondary recovery. However, selecting the optimum EOR process for a given reservoir is challenging because it requires evaluating and comparing performance for various EOR processes, which is complex and time consuming.
This paper presents a new EOR screening model that can predict the performance of various gas- and water-based EOR processes based on simple reservoir properties. The model estimates the oil recovery from miscible and immiscible gas/solvent injection (CO2, N2, and hydrocarbons), low salinity water flood, polymer, surfactant-polymer, alkaline-polymer and alkaline-surfactant-polymer floods. The screening model is based on a set of correlations that were developed using the response surface methodology, which correlates the oil recovery at dimensionless times to the important reservoir and fluid properties and EOR process variables identified for each process. The results of the model have been validated against a number of field test and numerical simulation results.
The screening model provides the capability to screen a large set of reservoirs for a wide spectrum of EOR processes, to identify the good EOR targets and the optimum EOR process for the target reservoirs. In addition, this model easily performs sensitivity analysis without the need for numerical simulations, allowing teams to account for uncertainty in reservoir properties and optimization of flood design. Finally, the methodology can be applied for developing screening models for other oil recovery mechanisms such as thermal (steam injection, SAGD), microbial EOR and other methods.
The Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production using vertical wells was poor because of the thin (less than 5m) reservoir formation and high oil viscosity (600 to over 40,000cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. Still, with primary recovery less than 10% and several billion barrels of oil in place, the prize for EOR is large.
Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake due to the high viscosity of the oil, until the idea came of combining it with horizontal wells. A first - unsuccessful - pilot was implemented in 1997 but the lessons drawn from that failure were learnt and a second pilot met with success in 2006. The response to polymer injection in this pilot was excellent, oil rate climbing from 43bopd to over 700bopd and remaining high for over 6 years now; the water-cut has generally remained below 60%.
This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the two polymer flood pilots as well as the extension of the flood to the rest of the field (currently in progress).
Polymer flooding has generally been applied in light or medium gravity oil and even today, standard industry screening criteria limit its use to viscosities up to 150cp only. Pelican Lake is the first successful application of polymer flooding in much higher viscosity oil (1,000-2,500cp) and as such, it opens a new avenue for the development of heavy oil resources that are not accessible to thermal methods.
The use of injection and production rate control is a common practice for optimal waterflood management. However, the benefits of rate control for enhanced oil recovery (EOR) processes have not been fully explored. In this paper, we examine the role of rate optimization in polymerflooding to maximize sweep efficiency and to minimize polymer recycling by delaying polymer breakthrough.
Field scale rate optimization problems for EOR processes involve complex physical and simulation models, production and facility constraints, and a large number of unknowns. Deployment of smart well completions with inflow control valves (ICV) to control production/injection rates for various segments along the wellbore further compounds to the complexity of the optimization. We propose a practical and efficient approach for computing optimal production/ injection rates for polymerflooding with application to smart wells. Our approach relies on equalizing arrival time of the floodfront at all producers to maximize the sweep efficiency and additional 'norm' constraints on the arrival times to achieve production acceleration. The 'optimal' rate strategy is decided based upon a compromise between maximizing sweep efficiency and production acceleration. We use streamlines to compute the analytical sensitivity of arrival times with respect to well rates.
Analytical forms for gradient and Hessian of the objective function are derived, making our optimization computationally efficient for large-scale applications under a hierarchy of operational and facility constraints.
We demonstrate our approach using a 2D synthetic example and a field-scale application. The results clearly demonstrate the benefits of rate optimization either by reducing polymer usage or increasing oil recovery. In particular, the 3D field-scale application results in achieving higher oil recovery and reducing associated water and polymer production for the same amount of polymer injection. The geological uncertainty has been accounted for via a stochastic optimization framework based on a combination of the expected value and variance of a performance measure from multiple realizations.
Type I fractured reservoirs are those in which the matrix is impermeable and fractures provide essentially all of the storage capacity and the fluid-flow pathways in the reservoir. This paper summarizes an analog reservoir study that compared the performance of dozens of such reservoirs to understand their behavior when strong water drives are present and particularly when oil viscosities are moderately high. Most such reservoirs are basement or volcanic rocks; however, numerous analogous clastic and carbonate reservoirs have also been identified.
Recoveries in "Type I?? reservoirs access a larger fraction of the oil-in-place in the fractures and very little matrix oil. Fracture recoveries can be expected to be very high (60 to 90% of the swept fracture volume) with extremely low recoveries in the matrix. Fracture porosities vary widely in fractured reservoirs and analogs may be poor sources of this information. Values of fracture porosity in excess of 1.0% are uncommon; however, some fields may have values up to about 3% or higher for certain fractured cherts.
Strong water drives can lead to high initial flow rates and relatively early water breakthrough; true Type I reservoirs may have very poor recoveries as a result. Horizontal wells often accelerate total recovery and may in fact lead to substantial incremental recovery. Heavier oils exacerbate early water breakthrough. Few reservoirs with significant fracturing were consistently fractured areally and with depth. Heterogeneity in fracturing is the rule and has few exceptions. In some many cases identifying the driving cause of spatial heterogeneity in fracture occurrence is the key to developing the field properly. Water shutoff efforts around the world in highly fractured reservoirs are generally failures. Treatments that successfully shut off water often greatly reduce oil production. This is particularly true of horizontal wells and most true of uncemented liners and open holes. Only in cased and cemented vertical or horizontal wells is there a routine chance of shutting off completion intervals. In many such cases, profile control improvements are temporary as the unwanted fluid bypasses the near-wellbore shutoff area. Gas influx is generally more severe than water influx.
Horizontal well placement is critical in developing Type I reservoirs and is a function of reservoir management and fracture characterization. Multiple laterals offer attractive operational and cost alternatives. Overdrilling similar reservoirs appears to have occurred in quite a few fields. Example fields from around the world are compared using a variety of approaches including some unique comparisons of temperature logs and pressure transient analysis tests.
CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.
The technical success of an Enhanced Oil Recovery (EOR) project depends on two main factors - first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters need to be estimated prior to embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil.
There are many methods for determining the oil saturation (Chang et al. 1988, Pathak et al. 1989) and these include core analysis, well log analysis, Log-Inject-Log (LIL) procedures (Richardson 1973 and Reedy 1984), and Single Well Chemical Tracer Tests (SWCTT). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. There is no single method that provides the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the remaining oil saturation in the reservoir.
This paper presents the results from a field-wide data acquisition program conducted in a West Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in West Texas has been producing for more than the past 75 years and the producing mechanisms have included primary recovery, secondary waterflooding and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process and it was imperative to evaluate the oil saturation in the lower, previously-undeveloped zones. This paper briefly outlines the production history, reservoir description and reservoir management of the Means field, but this paper concentrates on the Residual Oil Zone (ROZ) that underlies the Main Producing Zone (MPZ), and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS - core analysis, LIL tests and SWCTT tests.
Masalmeh, Shehadeh K. (Shell Technology Oman) | Blom, Carl P.A. (Shell Intl E&P) | Vermolen, Esther C.M. (Shell International Ltd.) | Bychkov, Andrey (Shell International Ltd.) | Wassing, L. Bart M. (Shell Intl E&P Co)
A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100.
The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs.
Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process.
Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study.
In the past few years, we have been working on understanding waterflooding performance in heterogeneous oil-wet carbonate reservoirs (Masalmeh et. el., 2004, 2007b, 2008) with a focus on the impact of geological heterogeneity, imbibition capillary pressure and relative permeability models. In these earlier publications we have focused on parameters affecting cross flow between reservoir layers and hence sweep efficiency and field-wide remaining oil saturation distribution.