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.

Summary The Pelican Lake heavy-oil field in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production by use of vertical wells was poor because of the thin (less than 5 m) reservoir formation and high oil viscosity (800–80,000-plus cp). 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. However, with primary recovery at less than 10% and 6.4 billion bbl of oil in place (OIP), the prize for enhanced oil recovery (EOR) is large. Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake because of 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 learned and a second pilot was met with success in 2006. The response to polymer injection in this pilot was excellent, with oil rate increasing from 43 BOPD to more than 700 BOPD and remaining high for more than 6 years; the water cut has generally remained at less than 60%. Incremental recovery over primary production is variable but can reach as high as 25% of oil originally in place (OOIP) in places. This paper presents the history of the field and 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 currently, standard industry-screening criteria limit its use to viscosities up to 150 cp only. Pelican Lake is the first successful application of polymer flooding in much-higher-viscosity oil (more than 1,200 cp), and as such, it opens a new avenue for the development of heavy-oil resources that are not accessible by thermal methods.

Thermal EOR has long been considered the sole Enhanced Oil Recovery method for heavy oil but this is no longer the case; several heavy oil polymer floods have proven successful and more are in the planning stages. In the US alone several billion barrels of oil could be targeted; in the rest of the world and in Latin America in particular the potential target is also probably large but mostly unknown at this point. Even though polymer flooding recovery is usually lower than with thermal methods, it is less capital intensive and may be the only economical solution for instance in thin reservoirs.As any EOR project, polymer flooding of heavy oil is done in stages -screening, feasibility study, pilot preparation, pilot execution and eventually full field deployment. Each of these stages requires care and attention to details and many pitfalls need to be avoided in order to reach the final stage of full deployment.This paper intends to provide guidelines on the whole process, based on practical experience and illustrated with actual field cases. This should allow operators to benefit from a better understanding of the challenges and potential of polymer flooding of heavy oil and open the door for more projects.

Chemical EOR methods such as polymer flooding and ASP (Alkaline-Surfactant-Polymer) are generally not considered suitable for oil viscosities over one or two hundred cp (polymer) or even less (SP/ASP). However this perception is changing, in particular due to field results obtained from a number of chemical EOR pilots or full field floods implemented in Canada in higher viscosity oil in the past few years. Canada is a country well-known for its heavy oil production; recovery processes such as Cold Heavy Oil Production with Sand (CHOPS) and Steam Assisted Gravity Drainage (SAGD) have been invented there. However cold production is limited in terms of the level of recovery it can achieve and thermal techniques also have limitations in particular when reservoirs are thin. Thus Canadian companies have been pursuing chemical EOR to increase recovery in those types of reservoirs. The aim of this paper is to review some of the Canadian projects for which public information is available. Several mostly unpublished projects will be discussed in details, and conclusions will be drawn on the applicability of chemical EOR methods in heavy oil. The practical experience gained in Canada can be applied in other regions of the globe where chemical EOR has so far not been considered or has been screened out because of high viscosity.

Low permeability reservoirs contain a significant and growing portion of the world oil reserves, but their exploitation is often associated with poor recovery even after waterflood. Miscible or immiscible gas injection is usually the first choice in terms of EOR methods but it is not always feasible for instance due to lack of adequate supply. In such cases chemical EOR is often considered. In this paper we propose to examine the specific challenges of chemical EOR in low permeability reservoirs by reviewing the well documented chemical EOR field operations that were implemented in reservoirs ranging from conventional low permeability (around 100 mD) to so-called tight reservoirs (few mD). Shale plays where permeability is in the µD range and which only produce when simulated by hydraulic fractures are not considered in our investigation. We show that what works at the lab scale in low permeability plugs cannot be automatically transposed to the field scale. In particular low permeability can lead to injectivity issues and uncontrolled fracturing due to near wellbore plugging or simply to the high pressures required to propagate the injected chemical over large distances. Another challenging aspect of chemical EOR in low permeability reservoirs is the high chemical adsorption due to important surface to volume ratio and specific mineralogy, as in the case of carbonates (fractured or not). Success and failures of chemical EOR pilots in such challenging reservoirs, including innovative approaches such as wettability alteration, are reviewed. Overall, this review will provide the reader with an updated view of past and on-going developments in chemical EOR applied to low permeability reservoirs. It should help operators determine whether a given low permeability reservoir is eligible to such processes or not.

A successful polymer flood is being implemented in the Pelican Lake heavy oil field located in Northern Alberta (Canada). With primary recovery around 5-7 % and several billion barrels OOIP, the field offered a big target for EOR but polymer flooding had never been considered in such high viscosity oil (600 to 80,000cp) until the idea of using horizontal wells gave way to a very successful 5 horizontal wells polymer flood pilot in 2005, followed by a progressive extension to the rest of the field. This paper provides a brief description of the polymer flood pilot then focuses on the various steps involved to generate a realistic reservoir model to history match the pilot. Polymer flooding in heavy oil reservoirs (1500 cp oil in the pilot area) using horizontal wells is really new and the response of the pilot was not totally expected. The oil rate has increased beyond expectations but more surprisingly, the water-cut has increased very slowly and is only in the 50-60 % range after 7 years of operations. History matching the pilot history was important in order to understand what was really taking place in the reservoir; it was performed using up to date Assisted History Matching techniques. Good results have been obtained in terms of history matching. The model can therefore be used to investigate the influence on oil recovery of many parameters such as well length and spacing, injection rate, polymer concentration, slug size, and to evaluate additional recovery compared to continued primary recovery or waterflood. History matching the pilot performance opens the door to a better understanding of polymer flooding in heavy oil reservoirs and to increasing the number of potential application cases.

SAGD is a very promising recovery process to produce heavy oils and bitumen resources. The method ensures both a stable displacement of steam and economical rates by using gravity as the driving force and a pair of horizontal wells for injection/production. After several years of small scale field tests (pilots), the method is now considered as mature and large scale projects are scheduled in a near future (in Canada for instance). Nevertheless, both technical and economical success of the process require a satisfactory development of the steam chamber, which can be achieved by well monitoring (i.e. steam trap control). This paper presents a general methodology based on numerical investigations to obtain and maintain an optimized development of the chamber throughout the production life of the wellpair. First, the methodology is explained on a synthetic case and applied to a real field case example. Field data are first history matched with the model and then the proposed approach is used to evaluate how the oil production could have been enhanced and optimized further. It is shown that an optimized steam chamber development is obtained by adjusting the steam injection rate to the potential of the reservoir (fluids and geology) and by monitoring the production rate during the process/operations to keep the steam chamber as large as possible but away enough from the production well to prevent any steam breakthrough. The results are in good agreement compared with Butler's analytical model (oil rate and steam chamber shape). A very good history match is obtained in the field case example. The proposed methodology shows that oil production rate can be doubled when injection/production rates are adapted to the SAGD reservoir potential. Introduction SAGD principle In one decade, SAGD process has turned out to be the most promising strategies to develop huge heavy oil and bitumen accumulations [1,2,3,4,5,6]. Like the conventional thermal processes (steam stimulation, steam injection,...) [1,7], this method aims at reducing oil viscosity by increasing the temperature. In the SAGD process, this is achieved by drilling a pair of horizontal wells. Typically, the two horizontal drains are located at short distance one above the other (Figure 1). Steam is injected into the upper well and hot fluids are produced from the lower well. This progressively creates a chamber, which develops by condensing steam at the chamber boundary and giving latent energy to the surrounding reservoir. Heated oil and water are drained by gravity along the chamber walls towards the production well [1]. The strength of SAGD is to merge a stable displacement of oil by steam with high production rates. The first feature is achieved by using gravity drainage as the only driving force. Whereas gravity drainage gives rise to poor production rates with conventional wells, some good productivity can be obtained with the use of horizontal wells. SAGD process obviously benefits from the recent and impressive progress drilling technology and development of specific tools enable to make possible accurate well pair placement and roughly constant inter-well spacing [8].

A polymer flood pilot has been ongoing since September 2008 in Suriname in the heavy oil Tambaredjo field operated by Staatsolie. Initially, the pilot consisted of one injection well and four producers and was later expanded to three injection wells and nine direct offset production wells (all vertical).The Tambaredjo oil field is the largest oil field in Suriname and has been producing since 1982. The field contains approximately 525 MMSTB STOOIP of 16°API oil with an initial viscosity of 300 -600 cP at reservoir conditions. Primary recovery (Ϯ 30% OOIP) is relatively high given the oil viscosity; this is believed to be due to a combination of compaction drive, edge water drive in the northern part of the field and limited bottom water influx in other areas, and perhaps foamy oil behavior. In spite of this high primary recovery, large quantities of oil remain in the reservoir, making it an attractive target for EOR.Due to the relatively thin pay, thermal methods have not been considered for the reservoir but on the other hand polymer flood was judged suitable. The oil viscosity is high but still lower than in other successful projects for instance in Canada while other reservoir characteristics are also suitable: low reservoir temperature and low water salinity allow the use of standard HPAM polymer, and high permeability is beneficial for injectivity. Moreover, the reservoir is highly heterogeneous, which has presented some challenges to the process.Initially, a polymer viscosity of 45 cP was injected which was later increased, first to 85 cP and then to 125 cP in order to improve the sweep efficiency. The overall response to polymer injection has been positive even if some wells have not responded positively to the injection, and incremental recovery (over primary) to date is estimated at on average 11% STOOIP. Due to the unconfined nature of the pattern some wells adjacent to the pilot have also shown response to injection.Given the success of the project, work is currently under way for an expansion of the polymer flood to encompass 33 additional injection wells.The paper presents the results of the pilot and describes the operations and challenges encountered during the project, in particular during the injection of the higher viscosity polymer. The combination of high reservoir heterogeneity, use of hydraulically fractured vertical wells and high polymer viscosity injected contribute to make this pilot an interesting field case.