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.
Choudhuri, Biswajit (Petroleum Development Oman) | Kalbani, Ali (Petroleum Development Oman) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman) | Ravula, Chakravarthi V. (Petroleum Development Oman) | Hashmi, Khalid (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman)
In viscous oil reservoirs, Polymer flooding is often used to improve oil recovery either after a short period of waterflooding or as a tertiary recovery process following extensive period of waterflood. After six years of water flooding in a major reservoir in Sultanate of Oman having viscous oil (90cp), a field development plan was developed to implement polymer flooding in this reservoir with anticipated incremental oil recovery of around 10% over and above that of waterflood. Necessary facilities were constructed, injection and production wells were drilled, completed, converted and the polymer flood project was initiated and ongoing since the last three years through 27 polymer injectors. By implementing proactive Well and Reservoir Management (WRM) strategies, the actual oil recoveries have been better than predicted levels so far. It is demonstrated here that proactive well and reservoir management through proper well and reservoir surveillance and dynamic adjustment of injection and production rates play a very important role in improving the performance of polymer floods as in waterfloods.
Well and Reservoir Management (WRM) principles in case of a polymer flood are similar to that of high mobility ratio waterfloods with some additional aspects that are specific to a polymer flood scenario. Polymer chemical costs, its higher viscosity and non Newtonian fluid flow behavior all create unique conditions that are nonexistent in normal waterfloods. This, in turn, dictates the strategies and methods employed to optimize polymer flood performance. This paper details successful implementation of proactive WRM strategy that has played a key role in sustaining production from this polymer flood field to date. It describes the pattern management processes to optimize pattern wise polymer injection and oil recoveries, conformance control measures implemented to increase sweep and oil recovery, innovative surveillance techniques to monitor fracture growth in polymer injection wells and for evaluation and optimization of production/injection profiles. Production wells and facilities issues arising from polymer breakthrough are being addressed to mitigate any adverse effects.
Lawrence, John J. (ExxonMobil Upstream Research Co.) | Sahoo, Hemant (Exxon Mobil Corporation) | Teletzke, Gary F (ExxonMobil Upstream Research Co.) | Banfield, Jessica (ExxonMobil Canada) | Long, Jamie M. (ExxonMobil Canada) | Maccallum, Nicholas (ExxonMobil Canada) | Noseworthy, Ryan J. (ExxonMobil Canada) | James, Lesley A (Memorial University of Newfoundland)
The Hibernia oil field is located in the North Atlantic Ocean over 300 km from St. John's, Newfoundland. The field consists of numerous fault blocks undergoing conventional gas or water injection. The gas injection process is proving to be very efficient providing high recoveries in individual blocks. Expansion of gas injection through conventional development or EOR may potentially provide significant benefits if optimized correctly under a limited gas supply. The need to understand the relative benefits of gas injection into one block versus another has increased and necessitated a full gas utilization study. One EOR option being considered is water-alternating-gas (WAG) injection in some blocks.
The objective of the study is to establish a field-wide improved recovery plan based on integrated laboratory, reservoir simulation, pilot, gas supply, and infrastructure studies. This paper will describe the integrated study plan and current progress.
The Gas Utilization Optimization Project entails three broad phases: 1) Study Phase; 2) WAG Pilot Execution; and 3) Field-Wide EOR Development. The primary focus at this point is the Study Phase, which will include laboratory studies, reservoir simulation studies, pilot engineering studies, and gas supply and infrastructure assessment.
The laboratory studies are being performed to develop a better understanding of PVT, EOR, and SCAL as it applies to the WAG pilot and field-wide development. The reservoir simulation studies provide a basis for the design of the EOR pilot and the field-wide development plan. Pilot engineering must be performed to ensure the pilot will provide the information necessary to make business decisions on future development. Assessing gas supply and infrastructure is essential to understanding gas availability, value, and opportunities for enhancement. This phase is particularly important for remote locations where external gas supplies are limited.
This study provides a template for obtaining and integrating information and data necessary to design, evaluate, and implement a gas injection project for improved oil recovery.
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.
Thakuria, Chandan (Petroleum Development Oman) | Al-Amri, Mohsin Saud (Petroleum Development Oman) | Al-Saqri, Kawthar Ahmed (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman) | Al-Hashmi, Khalid Hamad (Petroleum Development Oman) | Zuhaimi, Khalid (Petroleum Development of Oman)
The first field scale Polymer flood project in the Middle East region is being implemented in an oil field of Sultanate of Oman from early 2010. The oil field discussed here containing viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding.
This field scales Polymer flood project comprising 27 patterns as Phase-1 covers about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in all these 27 injectors. Further extension in phases to full field polymer flooding is under evaluation.
Till now this Polymer flood project has successfully completed 3 years of good performance contributing to significant oil gain. This paper describes briefly about the principles involved in polymer flooding, planning of this polymer flood project, field implementation and field examples of polymer response. In addition, a few practical aspects of managing key issues in polymer flooding like- fracture growth in injectors, shear degradation of polymer solution, pattern conformance and back produced polymer has been covered in this paper.
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 Cold Lake project, located in Alberta, Canada, is the world's largest heavy oil in situ thermal development, with production of about 24,000 m3/d (150 kB/d) of oil from more than 4500 wells. In 2009, Cold Lake produced its one billionth barrel (160 million m3) of heavy oil.
The world class Cold Lake hydrocarbon resource is characterized as a bitumen deposit, featuring in situ viscosities in excess of 100,000 mPa-s. Early depletion plans envisioned a thermal recovery process similar to the steamflood technologies employed to recover heavy oil in California's San Joaquin Valley. The order of magnitude difference between Cold Lake and California in-situ viscosities, however, severely limits steam injectivity below fracture pressure, necessitating the development of a Cold Lake specific cyclic steam stimulation (CSS) process throughout the 1980s.
Continual process optimization combined with infill drilling has resulted in a progressive increase in expected bitumen recovery from 13% to greater than 40% of effective bitumen in place (EBIP). A multi-disciplinary reservoir management effort conducted over the last several years has provided the view that Cold Lake recovery levels may potentially be increased to over 65% by adapting steamflood principles to mature CSS areas of the reservoir:
As cyclic process efficiency declines due to lack of steam confinement, steamflood technologies become an attractive recovery scheme in mature Cold Lake reservoir by capitalizing on large scale inter-well communication while focusing on gravity drainage:
This paper illustrates the successful design, implementation and evaluation of cyclic steam stimulation pilot in heavy oil field of Sudan. This field contains heavy oil in multiple reservoirs of Bentiu formations of late cretaceous age occurring at epths of 550-600m. Reservoirs are highly porous (~30%), permeable (1000-2000 mD) and unconsolidated in nature. Fluid properties include viscous crude of degree API 15 - 17 and corresponding viscosities in the range of 3700 cp and 3000 cp at reservoir conditions.
In view of higher viscosities and consequently lower oil rates and envisaged meager primary recovery of around 18-20%, plan is made for thermal enhanced oil recovery (TEOR) application early to overcome the resistance to flow and maximize the recovery. As EOR processes are reservoir and reservoir fluid specific, therefore, it is prudent to understand the reservoir response to the steam injection before full field application. Cyclic steam stimulation has been implemented in eight selected wells spread over the field encompassing varying reservoir characteristics for understanding the efficacy of the process, acquiring the valuable data and operational experience. Equally important objective was to gain experience for minimizing the key risks, associated problems and challenges.
Wells have been completed with heat compatible casing and cement. Steam quality of 75% was injected for 6-12 days and wells were subjected to soaking of 3-5 days. Putting on production an improvement of three to five folds has been realized compared to primary production and first cycle is sustaining more than six months. Actual results are better than predicted in simulation studies with lower steam intensity of 120 m3/m compared to planned 160m3/m. Paper also discusses improvement in oil production and its variation with formation and fluid characteristics, formation thickness, depth of formations, duration of injection and soaking periods along-with response variables like oil-steam ratio and steam/water production. Operational challenges in preventing the heat losses in annulus, lifting challenges and sand production are also discussed.
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.