The paper describes laboratory development and field application of polymer-stabilized foams for gas-control in Prudhoe Bay field, including formulation of the foam, its evaluation in sand-packs, and treatments of several wells at Prudhoe Bay. It will also document long term reduction of excessive GOR (gas-oil-ratio) in hydraulically fractured wells with small impact on black oil production. Candidate selection criteria, treatment design/implementation and three case histories (with summaries of all treatments to date) will be covered along with future enhancements to treatment design. Introduction Facility constraints on handling excessive gas production have limited black oil rates at Prudhoe Bay field for a number of years. Approaches to dealing with this problem have included expansion of gas handling facilities, so that current capacity is approximately 7.5 BSCF/day. Gas-cap expansion with continuing production, cusping (shale under-runs), and propped hydraulic fractures that grow upward into a gassed-out region or close enough to the gas-oil-contact (GOC) to cause coning, continue to increase field-wide gas-oil-ratio (GOR), with concomitant negative impact on liquid rates. Increasing standoff from encroaching GOC and zone shutoff of gas cusping have been addressed with remarkable success using both cement and cross-linked polymer-gel recompletions. Attempts to use foam to address gas coning associated with GOC encroachment met with limited technical success. The short-lived treatments were judged uneconomic and were discontinued. Prior to work described in this paper, the only attempts to control excessive gas production from high GOR hydraulically fractured wells involved cyclic production or simply shutting in the well or, in some cases, side-tracking. Inability to isolate the offending zone is a major reason gas shut-off re-completions were not attempted in fractured wells. Three technical developments led us to re-evaluate the use of foam for gas shut-off. First, theoretical work on critical rates for water- and gas coning has given important insight into the types of candidates most amenable to treatment for coning problems. To briefly summarize, effective treatment of a typical matrix coning problem requires a blocking agent that extends radially many tens to hundreds of feet from the wellbore, a technically and economically daunting requirement. However, coning induced by a highly conductive vertical fracture can be controlled by sealing off the fracture/gas-zone connectivity. This can be accomplished by plugging the fracture itself, or by placing a blocking agent in matrix between the fracture and the gas source. Treatment volume for effective gas shutoff is expected to thus be much smaller/more economical than that required to treat a matrix problem. Furthermore, correction of a matrix coning problem is expected to increase the critical production rate prior to reoccurrence of coning by 1.5 to 5 fold, whereas correction of a fracture connection to unwanted fluid can result in an order of magnitude or more increase in the critical rate. Second, surfactants that produce an aqueous-phase foam with stability to oil saturations approaching 30-35% (based on our laboratory studies) have become available. This offers the possibility to employ indiscriminate placement of foam or foaming agent, while relying on higher oil saturations to destabilize foam that invades an oil producing interval. Third, adding appropriate water-soluble polymers has been shown to increase foam stability and strength. In addition, utilization of a polymer with cross-linkable functionality offers the further option of forming an even stronger gelled foam. These options offered the possibility of increasing treatment lifetime, and hence economics, through use of a stronger foam than had been previously available. With these advancements we believed it was now possible to attack the problem of excessive gas influx from matrix into a propped hydraulic fracture. P. 443