TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractGel-Cement Combination Squeezes have been successfully used for gas shutoff applications. Coupled with coiled tubing selective placement, gels and cements exhibit a synergistic gas shutoff effect. Gels provide an indepth block to gas production by forming a crosslinked polymer network within the porous media. Cements are able to fill voids and cavities to block gas production and provide a strong near wellbore block. Thirteen treatments have been performed to date with an economic success rate of 85%. Implementation of the technology required the use of a well-controlled gel system, consideration of possible contamination issues and modification of current coiled tubing placement strategies.

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

An enriched, Water-Alternating-Gas (WAG), miscible flood was brought on stream in December 1982 in the Prudhoe Bay Field on Alaska's North Slope. This Prudhoe Bay Field on Alaska's North Slope. This paper outlines details of the Project and traces paper outlines details of the Project and traces its evolution from conceptual engineering through start-up to initial performance. The Project involves an area containing 442 million barrels original oil in place. The 3,650 acre Project Area includes sixty 80-acre spaced wells in eleven inverted nine-spot patterns. Facilities process the 40 to 45 MMscf/D of miscible injectant which is then injected alternately with water on a 3 month/6 month gas/water cycle in eleven injection wells. An extensive surveillance program includes one fiberglass cased observation well, a comprehensive cased hole logging program, and radioactive gas tracers. The Project will program, and radioactive gas tracers. The Project will consist of WAG injecting a slug of more than 10% total pore volume (TPV) miscible gas. The miscible gas will pore volume (TPV) miscible gas. The miscible gas will be injected at a rate of approximately 1% TPV per year, followed by water injection to displace miscible gas through the reservoir and tertiary oil to producing wells. The estimated incremental-to-waterflood recovery is 5.5% of the original oil in place or 24 million barrels of oil. Introduction The Prudhoe Bay Sadlerochit (Permo-Triassic) reservoir located on the North Slope of Alaska (see Figure 1) contains over 22 billion stock tank barrels of oil and 40 trillion standard cubic feet of gas originally in place. The dominant recovery mechanism is gravity drainage place. The dominant recovery mechanism is gravity drainage supported by gas cap expansion. A waterflood has just been initiated which will ultimately be expanded to about 30% of the field. In August 1980, the Prudhoe Bay Unit (PBU) began evaluating the potential for enhanced oil recovery at Prudhoe. A task force composed of Unit members was formed to study this potential application. potential application. Process Selection Process Selection Four enhanced oil recovery categories were considered by the PBU: thermal processes, chemical flooding, enhanced waterflooding, and miscible flooding. The thermal processes, steam injection and in-situ combustion, were the easiest to eliminate from consideration. The average depth of the Sadlerochit is 9000 feet and current average reservoir pressure is 3850 psia. Steam injection recovery efficiencies would be low at these reservoir conditions. In-situ combustion would require high air injection pressures (5,000 to 6,000 psig) and ten to twenty acre well spacing. Berea core floods with Sadlerochit crude showed limited benefits from alkaline flooding. The acid number of Sadlerochit crude samples tested at 0.09 which is very marginal. Also, five different caustic compositions were evaluated with Sadlerochit crude for interfacial tension (IFT) values. The lowest IFT was 0.565 dynes/cm which is at least an order of magnitude too high to recover significant incremental oil over waterflood residual. Surfactant flooding initially appeared attractive for the Sadlerochit. However, one significant problem became apparent: injection of both low temperature Beaufort Sea water and higher temperature produced water would cause temperature and salinity gradients in the reservoir that would render current surfactants ineffective. Several schemes were devised to separate the two waters in the reservoir, but all were deemed uneconomical. Another obstacle was the high cost of providing chemicals at Prudhoe Bay. providing chemicals at Prudhoe Bay.

This paper was prepared for presentation at the 1999 SPE Western Regional Meeting held in Anchorage, Alaska, 26–28 May 1999.

October field is one of the major fields in GOS Egypt operating at 100,000 BFPD using 185 MMSCF gas lift injection gas though 50 active producing wells and 11 injection wells with 2 water source wells. Most of the reservoirs are waterflood. October field is located 21 miles from the west shoreline in the Gulf of Suez. With time, the performance of the producing wells showed a significant decline in productivity which was attributed to reservoir pressure decline. So, a study was done and resulted in selecting a waterflooding technique for reservoir pressure maintenance and increase of the oil recovery factor. The economic success of a waterflood project depends on the additional oil recovery it can achieve relative to increased cost over primary development. it must aso be operated in an environmentally friendly manner. The water source chosen for a waterflood project is usually based on a number of different factors, such as scaling tendency, rock/fluid compatibility, and possibility of bacterial activity. It is possible that a combination of sources could eventually be used. At the location of the waterflood project there may be a number of alternative water sources such as, seawater and separated formation water. Water taken from the sea and separated water associated with produced oil generally need extensive chemical treatment and expensive facilities. Would the project still give this added cost? The October field waterflood uses a pure water productive zone for source water, which is then injected into the reservoir by two methods:Water is produced from Zeit formation at depth 3000 ft by ESP and injected directly into water injection wells located on several adjacent platforms, without any chemical treatment. This was possible because the two waters (formation and injection water) were found to be compatible.Dumping water from the Zeit source formation directly to the oil productive zone in the same wellbore by pressure difference, otherwise known as dump flooding. This technique has an economic advantage over conventional injection schemes by eliminating the need for source water treatment, since the provided water was found to becompatible with flooded reservoir water, formation clays, and rock matrix. It is significantly reduces facility and flow line requirements and saves deck space offshore, and also reduces environmently impact. Introduction In many oil fields the natural reservoir energy will drop to such low levels that the wells will not produce at high enough rates to be economic. In some of these fields methods of restoring or injecting energy into the reservoir are used to increase the oil recovered from them. One of the most common methods used is "Waterflooding". This basic secondary recovery method is applied in many fields in Gulf of Suez, where certain wells are selected in each reservoir for water injection. Operationally, water is pumped down these injection wells into the reservoir, where it spreads out from the injection wells and moves toward the oil wells driving reservoir oil ahead of it. October field is one of the major fields in GOS Egypt operating at 100,000 BFPD using 185 MMSCF lift injection gas though 50 producing wells and 11 injection wells with two source water wells (one active). Withen a few years of initial production, most October wells showed a significant decline in oil productivity. Some "died" prematurely, while others became intermittent producers. A study was done by engineers from reservoir management and production engineering, to determine the causes of productivity decline. The team investigated multiple aspects of the decline in rate and concluded that the oil productivity decline was primarily due to decline in the reservoir pressure. Waterflooding is a frequently used technique to increase oil recovery after primary depletion; however the economic success of a waterflood project depends on the additional oil recovery it can achieve in spite of the increased costs over primary development.