Enhanced oil recovery (EOR) techniques can significantly extend global oil reserves once oil prices are high enough to make these techniques economic. Given a broad consensus that we have entered a period of supply constraints, operators can at last plan on the assumption that the oil price is likely to remain relatively high. This, coupled with the realization that new giant fields are becoming increasingly difficult to find, is creating the conditions for extensive deployment of EOR. This paper provides a comprehensive overview of the nature, status and prospects for EOR technologies. It explains why the average oil recovery factor worldwide is only between 20% and 40%, describes the factors that contribute to these low recoveries and indicates which of those factors EOR techniques can affect. The paper then summarizes the breadth of EOR processes, the history of their application and their current status. It introduces two new EOR technologies that are beginning to be deployed and which look set to enter mainstream application. Examples of existing EOR projects in the mature oil province of the North Sea are discussed. It concludes by summarizing the future opportunities for the development and deployment of EOR.

An Industry Consortium (BP, ChevronTexaco and Nalco Company) conducted a joint research project known as Bright Water. The goal of this project was to develop a novel, time- delayed, highly expandable particulate material that would improve the sweep efficiency of a water flood. In November 2001, the first of these water flood profile modification treatments was pumped in the Minas field, as reported in SPE 84897 (1). An overview of the development of the particulate system is given in the present paper. The polymeric "kernel" particles are capable of "popping" under the influence of temperature and time. The expanded particle can then provide resistance to fluid flow in porous media. Various properties of the kernel dispersions are summarized. Laboratory tests representative of the deployment of the product are presented to illustrate the injection, propagation and popping of the particles. Screening criteria for application of the product are reviewed and related to product selection for the field trial. Introduction Over the last 40 years there has been a concerted effort to improve the recovery of oil by mobility control using polymers and polymer derived gels (2). Much of the work has focussed on near wellbore gel treatments using polymers and gels but there has also been considerable work on Polymer flooding and hybrid derivatives of this (3–7). All flooding polymers alter the water mobility in the reservoir predominantly by changing the aqueous viscosity. The ratio of the apparent viscosity of the treatment (as calculated from pressure measurement during treatment injection) to the viscosity of water in the same conditions is known as the Resistance Factor (or RF). Some polymer can also adsorb on the rock pore walls to leave a lasting change through altering the hydraulic radius of the pores and thus the permeability of the rock. The ratio of the effective permeability of the rock pores to water flow before treatment to the effective permeability after flushing the treatment out is known as the Residual Resistance Factor (or RRF). The polymer flooding process has some strengths, but also a number of weaknesses. In particular the polymers are sensitive to salinity, temperature, shear and biological degradation to differing degrees. The better performing polymers tend to use more expensive monomers or production processes. There are also limitations related to the reservoir flooding process. High viscosity of the polymer flooding solution limits the injection rate at any given injection pressure. The maximum usable viscosity is typically limited to between three and ten times that of the injection water (RF maximum of 10). There are added risks of the injector fracturing and of polymer shear degradation. Unfortunately, the effectiveness of the process is reduced at low viscosity, and overall this severely restricts the range of viable applications. In the field projects where polymer flooding has been used with technical success, the cost of the accelerated oil is relatively high. In 1996 it was estimated as $8 to 10 per barrel (8) but more recently a review of the field wide commercial polymer flood in the Daqing oilfield (5) found that in this mature field, with easily accessible fresh water, the fully accounted cost was $9.34 per barrel compared with $9.42 for continued water flood production. It is apparent that a less restricted, more cost effective method for improving sweep efficiency in oil reservoirs would be desirable. This could be achieved by injecting a low viscosity material, which subsequently triggered to form a highly viscous or blocking phase. Concentrating on the permeability reduction element of the waterflood modification should result in a system that uses most of the injected materials to produce a lasting effect. It would also ensure that injected material was never subsequently produced with the water from the field. Field trials and commercial applications of gel systems intended to achieve this have been reported (9,10) but it is unclear how far the gelant penetrates into the reservoir (11).

An Industry Consortium (BP, ChevronTexaco and Ondeo Nalco Energy Services) conducted a multi-company research project known as Bright Water. The goal of this project was to develop a time-delayed, highly expandable material that would improve the sweep efficiency of a water flood. In November 2001, the first of these water flood profile modification treatments was pumped in the Minas field. The Minas Field, located on the island of Sumatra in Indonesia, has an OOIP of 8.7 billion barrels, is at nearly 50% recovery, and has water-cuts greater than 97%. Reservoir thief zones have been identified throughout the main reservoir layers. The main objective for pumping a profile modification material is usually to divert injected water out of thief zones and into zones with higher oil saturation, though areal sweep improvement can also be expected. The profile modification treatment of 42,000 barrels water containing 4500 ppm of active material was pumped into Minas injector 7E-12 ("A1" sand). The objective of the field trial was to verify that significant volumes of this low cost material could be pumped deep into the reservoir at low viscosity, and then expand after a pre-designed time interval. Injection tracer studies were conducted pre- and post-treatment to aid in determining changes to the injection sweep efficiency. A bottom hole pressure fall off test was also used to measure post - job permeability. The trial demonstrated that large volumes of the material can be pumped into the formation without raising the injection pressure or blocking the injection well bore, can propagate in the rock pore system, and then will expand at a pre-designed time. Changes in oil production after the trial will be discussed along with the field data acquired during and after the trial. As part of the continued development of this material, a second trial commenced in late November 2002 on a North Sea (UK) production platform. The treatment was successfully placed in mid December, 2002. Introduction This paper presents a case history in which a novel profile modification treatment was pumped in the Minas waterflood. Of all the problems that can beset oil wells, unwanted water production is one of the most troublesome, yet water flooding to improve the recovery of oil is the most common secondary recovery process used in the modern oil industry. Water production causes many problems such as corrosion, scaling, cost of oil water treatment and cost of disposal. In water injection projects excess water production is often linked to poor sweep efficiency, which renders significant amounts of oil irrecoverable during the economic life of a field. Poor sweep efficiency can be the result of zones with unfavorable permeability in heterogeneous reservoirs or unfavorable mobility ratio within homogeneous rock. Specifically water can break through from the water injection to the oil production wells in the most permeable zones while significant oil is left in the reservoir (Fig. 1) or it can pass through low mobility oil by a process of viscous fingering.1 The problem can be even more severe when bottom water zones with high water saturation and therefore variations in relative permeability exist. 2,3

Use policyThe full-text may be used and/or reproduced, and given to third parties in any format or medium, without prior permission or charge, for personal research or study, educational, or not-for-prot purposes provided that:• a full bibliographic reference is made to the original source • a link is made to the metadata record in DRO • the full-text is not changed in any way The full-text must not be sold in any format or medium without the formal permission of the copyright holders.Please consult the full DRO policy for further details. To identify families of stable planar anchor groups for use in single molecule electronics, we report detailed results for the binding energies of two families of anthracene and pyrene derivatives adsorbed onto graphene. We find that all the selected derivatives functionalized with either electron donating or electron accepting substituents bind more strongly to graphene than the parent non-functionalized anthracene or pyrene. The binding energy is sensitive to the detailed atomic alignment of substituent groups over the graphene substrate leading to larger than expected binding energies for -OH and -CN derivatives. Furthermore, the ordering of the binding energies within the anthracene and pyrene series does not simply follow the electron affinities of the substituents. Energy barriers to rotation or displacement on the graphene surface are much lower than binding energies for adsorption and therefore at room temperature, although the molecules are bound to the graphene, they are almost free to move along the graphene surface. Binding energies can be increased by incorporating electrically inert side chains and are sensitive to the conformation of such chains. © 2014 AIP Publishing LLC.

Summary Waterflood thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction to the nature of a novel, heat-activated polymer particulate. Details are presented of a trial of this in-depth diversion system, resulting in commercially significant incremental oil from a BP Alaskan field. The system of one injector and two producers was selected because of a high water/oil ratio and low recovery factor, which was recognized as an indicator of the presence of an injection-water thief zone and was confirmed by study of a previous injection survey. The area around the wells is bounded by faults, so the system can be considered to be isolated from surrounding wells and operations. The position of the thermal front in the reservoir, tracer transit times, injection rates, and interwell separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial. The treatment was designed using laboratory tests and numerical simulation informed by pressure and chemical-tracer tests. Long- sandpack tests indicated permeability-reduction factors of 11 to 350 for concentrations of 1,500 to 3,500 ppm active particles in sand of 560- to 670-md permeability at 149°F. 15,587 gal of particulate product was dispersed using 8,060 gallons of dispersing surfactant, into 38,000 bbl of injected water, and was pumped over a period of 3 weeks at a concentration of 3,300 ppm active particles. Placement deep in the reservoir between injector and producer was confirmed by pressure-falloff analysis and injectivity tests. The incremental oil predicted from the simulation was 50,000 to 250,000 bbl over 10 years. In fact, more than 60,000 bbl of oil was recovered in the first 4 years at a cost comparable with that of traditional well work and less than that of sidetracking.