Background: Abnormal regulation of calpains and Src contributes to stroke-induced brain damage. Results:The abnormally activated calpains cleave Src to generate a truncated Src fragment capable of directing neurons to undergo cell death. Conclusion:A new function of Src in neuronal death is discovered. Significance: Prevention of calpain-mediated cleavage of Src is a potential therapeutic strategy to minimize stroke-induced brain damage.

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).

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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.