EOR evolution

Elena Escobar

July 2, 2014

Efforts surrounding the research and development of technologies for oil recovery are currently being centralized in order to ensure continued production of crucial sources of hydrocarbons worldwide. As a result, it is expected that enhanced oil recovery (EOR) processes will have a much more important role in supporting the development of giant reservoirs located in offshore fields.

Offshore areas are of high interest to Repsol, with large reservoirs recently being discovered in Venezuela, Brazil, Gulf of Mexico (GOM) and Alaska. Currently, the daily production of the offshore fields, where Repsol is participating with other partners, is about 260Mboe, and located mainly in Trinidad & Tobago, GOM, Brazil and Spain. Repsol’s offshore production is expected to increase significantly in the next five years due to two developments: the Shenzi development field located in the GOM, which has reserves of about 400MMbbl, and various carbonate reservoirs in offshore Brazil, holding more than 2 billion bbl in reserves. To support the technical needs associated with the development of these fields, Repsol has invested in different strategic R&D projects in the EOR area.

Worldwide EOR application

EOR processes are defined as the injection of fluids into the reservoir in order to reduce oil saturation and increase the oil recovery factor. The most common EOR recovery processes are the injection of thermal fluids such as steam to reduce the viscosity of heavy oils into the reservoirs; as well as the injection of water soluble chemicals such as polymer, surfactant and alkali to improve the recovery factor mainly in medium and light oil reservoirs. Miscible and immiscible gas injections, such as hydrocarbon (HC) gas, CO2, N2, and air, are also widespread in medium and light oil reservoirs. Figure 1 shows the world daily EOR production, locations and production rates of the main EOR projects.

With the exception of the thermal projects in the Zulia state in Venezuela and the hydrocarbon injection projects in the North Sea, most of the large EOR applications are performed in onshore fields. In the past,

Repsol examined the recovery processes applied to its offshore reservoirs with similar characteristics to Repsol’s mature reservoirs such as Teak, Saaman and Pui, which are located in Trinidad & Tobago.

For this study, Repsol used the C&C DAKS database, 2013, and applied the following filter: offshore fields, sandstone lithology, oil API gravity < 220, porosity < 40% and permeability < 1000 mD. As a result, Repsol obtained a sample of 220 fields. Of these, 132 reservoirs (66% of the total) had secondary oil recovery processes, waterflooding, and hydrocarbon gas injection processes applied. However, only 14 reservoirs (6%) reported EOR applications; ten miscible CO and HC gas injection and four polymer injections(most at pilot test level).

Another search was done by filtering offshore fields only. In this case, 441 reservoirs were identified with only 17 fields (4%) reporting any use of EOR applications. These EOR fields are in a water depth ranging from 200-4800ft.

Drivers and challenges

The drivers of offshore EOR applications include: a continued increase in oil prices over the last seven years; the decline in secondary oil recovery of large reservoirs in the North Sea; the discovery of large offshore reservoirs in presalt Brazil; as well as major advances in the development of EOR chemicals (surfactants and polymers).

Compared with onshore field conditions, applying EOR processes to offshore projects is more challenging. For example, due to the spacing between large wells and the fact there are much fewer wells, sweep efficiency is much lower. It takes longer for reservoirs to respond to the EOR process being applied. Furthermore, there are limitations of off- shore facilities in terms of space, weight and power supply. In addition, many off- shore structures are old, therefore, safety restrictions to implement new processes are higher than onshore. As a result, offshore EOR applications have higher capital and operating costs than those for onshore, resulting in a reduced number of potential EOR technologies that can be applied offshore. For instance, air injection processes are considered too risky from an operational point of view to be implemented at offshore conditions.

Compared to shallow water conditions, the commercial development of heavy oil resources in deepwater offshore reservoirs still poses many unresolved

technological challenges. Most new offshore EOR projects are aimed at light and medium oil fields due to the higher market value of these fluids, and because they are easier to transport from the reservoir to its final destination. The production of deepwater, offshore heavy oil fields is severally impacted by the low temperature of the sea water (around 4oC in the sea floor) making it difficult to pump the oil to the surface as its viscosity is increased due to heat loss along the production well to the surface. Moreover, the high heat loss and fuel costs make transporting steam into the reservoir for the steam injection process very expensive and inefficient.

The picture is different for developing heavy oil fields located in shallow water, close to shore, such as on eastern cost of Maracaibo Lake (60m water depth) in Venezuela, with more than 40 years of successful offshore, cyclic steam stimulation (CSS), in fields like Bachaquero, [11.7OAPI, 6621million stock tank bbl (MMstb) OOIP] (Escobar et. al. 1997).

Current applications

A number of field examples show the increasing importance of offshore EOR application.

Offshore EOR projects have been applied in North Sea fields since 1976 (Awan, Teigland, Kleppe 2006). EOR off- shore processes in this region have been focused on five technologies and 19 field application projects such as hydrocarbon gas injection (six miscible field applications); water-alternate-gas (WAG) injection (three miscible and six immiscible field applications); simultaneous water & gas (SWAG) injection (one field application); or microbial enhanced oil recovery (one field application). WAG appears to be the most successful EOR technology applied in the North Sea.

Since 2003, China National Offshore Oil Corp. (CNOOC) has implemented EOR chemical flooding in offshore heavy oil reservoirs in Bohai Bay, China (Xiaodong, et. al. 2011). Polymer flooding is an important technology for the strategic development of these kinds of fields with three existing polymer EOR projects on heavy oil fields. The projects have been implemented to improve mature water flooding. The total oil production improvement was more than 6MMstb by the end of 2010.

In 2011, Petrobras implemented the first EOR pilot project of CO2 and natural gas injection in pre-salt Brazil, at miscible conditions, through a WAG scheme injection (SantÁnna Pizarro, Moreira Branco 2012). The pilot is being carried out at Lula Field (28-300API), deepwater (1800-2400m), in the Santos Basin. The source of CO2 is the associated natural gas produced with the oil in the field. Early results show that the tested EOR process has the potential to be successful.

Additionally, Repsol and Petrobras have evaluated different chemical EOR technologies (i.e. polymers, surfactants, and low-salinity water flooding) for the Albacora-Leste field in deepwater (about 2300m), off Brazil (Abdelmawla 2013). Albacora-Leste is a turbidity reservoir, with very high salinity (80,000-90,000ppm) formation brine. Currently, Repsol and Petrobras are working together to go ahead with a chemical EOR pilot test.

Di Pietro et al. (2014) evaluated recoverable crude oil resources associated with CO2-EOR to 531 offshore oil fields in GOM.

The research mentioned that there is a great opportunity to economically apply CO2-EOR in major offshore reservoirs in the GOM. The study also recommend designing CO2-EOR in the conceptualization stage of the development plan for new deepwater offshore projects, which could greatly reduce the overall cost and make the application of these processes more attractive in the future.


Various factors are driving the search for increased EOR such as successful secondary recovery methods, new important offshore discoveries, as well as efforts to reduce the production decline of mature offshore fields in the North Sea, GOM and China. To enable the economic transformation of these resources, further development of oil recovery and flow assurance technologies are necessary.

Elena Escobar is manager of an R&D strategic project on thermal EOR and has worked at the Repsol Technology Center (CTR) as a consultant for oil recovery since

2007. Over the last 27 years, Elena has been involved in enhanced oil recovery (EOR) projects for different oil companies and research institutes. During that time, she has also been a technical leader for different thermal and gas EOR projects and pilot projects. From 2007 to 2009, Elena had also served as mentor of the Repsol reservoir knowledge community. Elena has a PhD in Petroleum Engineering from Texas A&M University.