Summary The Foam Assisted Water Alternating Gas (FAWAG) project has been a full-scale field demonstration of foam for gas mobility control. It was carried out in the Snorre field on the Norwegian Continental Shelf from 1997 to 2000, with support from the European Commission's Thermie Program. A production well treatment to reduce the producing gas/oil ratio (GOR) was performed in 1996. The FAWAG was initiated in the Central Fault Block (CFB) of the Snorre field in August 1998. A commercial surfactant system, AOS (alpha-olefin-sulphonate), with a carbon chain length mix of C14/C16, was chosen as the foaming agent. Approximately 2000 tons of commercial grade AOS surfactant have been injected. Foam for mobility control in the CFB operation had to be aborted because of operative problems in the target injector P-25A. The main operational conclusion from the CFB operations was that surfactant alternating gas (SAG) injection is preferable to coinjection. Operationally, SAG injection is almost identical to water alternating gas injection (WAG), which is a well-known production method. The concluding demonstration was performed on the Western Fault Block (WFB) in well pair P32-P39. The target injector and producer wells are approximately 1500 m apart. A total of 380 tons of commercial grade surfactant was used. The surfactant was divided into two slugs, each followed by gas injection that lasted until original gas injectivity was restored. The production from WFB has shown that large volumes of gas have been stored, either temporarily or permanently, in the reservoir. It has been estimated that the FAWAG treatment has contributed approximately 250 000 Sm3 of oil. The cost of the treatment in WFB was approximately U.S. $1 million. Introduction Foam is a method to improve sweep efficiency during gas injection, and several field applications of foam have been reported.1–6 In the North Sea, foam application before FAWAG has mainly involved production well treatments.4–6 In 1996, a foam treatment was performed on production well P-18, located in the CFB of the Snorre field.6 Foam was used to reduce the producing GOR. The FAWAG project commenced in 1997 on the CFB of the Snorre field. Snorre is one of the major oil fields on the Norwegian Continental Shelf in the North Sea, located about 150 km off the coast. The reservoir is a massive fluvial deposit within rotated fault blocks. The field was originally developed with water injection as the main drive mechanism and came on stream in 1992. One of the first measures taken to increase production was implementation of a downdip WAG pilot in the CFB. This was later expanded to cover the three main fault blocks in the field. The demonstration of FAWAG was carried out in the CFB and WFB, as described in Fig. 1. The main target for the FAWAG was the Upper Statfjord reservoir zones S1 and S2. Upper Statfjord is a sandstone reservoir with upward coarsening sequences. The permeability is in the range of 400 to 3,500 md, and the blocks are dipping 5 to 9° toward the southwest. The injection is downdip. In the CFB, there is vertical communication between S1 and S2; this seems not to be the case in the WFB target area. In WFB, the injection is below the original water/oil contact. The Snorre oil is originally undersaturated by 260 bar. The injection gas used is identical to the export gas and is rich in intermediate components. Laboratory studies conclude that the gas is miscible with reservoir oil at pressures above 282 bar. The gas and water are injected downdip in all but one fault block in order to use existing water injectors and producers. In areas with direct communication from injector to producer, breakthrough times of gas on the order of 1 month were observed for well distances in excess of 1 km. In the Upper Statfjord sands, the gas will rapidly segregate and move updip. The gas will mix with the oil when the phases are in contact, but the amount of oil contacted is limited in later cycles. Local attics in the reservoir will be well swept by gas, and structural attics behind producers will form secondary gas caps. The principles behind FAWAG are illustrated in Fig. 2. The high mobility of the gas may result in early breakthrough of gas in the producers. On the Snorre field, it is believed that gas either moves on top of the reservoir zone or through other high-permeable zones. By generating foam in the reservoir, it is anticipated both that the gas sweep efficiency is improved and that the oil production is increased. To create the foam, a suitable foaming agent (surfactant) must be used. The surfactant can be applied in different ways. Both injection in a SAG mode and coinjection of aqueous surfactant solution and gas have been investigated in the FAWAG project. As part of the qualification plan for foam, it was decided to carry out two foam pilots: one producer treatment for gas shutoff, and one in-depth treatment to control gas mobility. The mobility-control operation had to be aborted because of operative problems in the target injector. Consequently, the operation was moved to the WFB of Snorre in 1999 for the concluding demonstration. This paper will give a summary of all foam applications on Snorre. Experiences from the foam tests involve logistics, evaluation of the gas-blocking effect, injection design, and gas storage. P-18 Gas Shutoff Treatment The producer treatment was carried out in well P-18 in July 1996,6 where a total of 32 tons of commercial-grade surfactant was used. P-18 was suffering from high GOR caused by premature gas breakthrough from WAG injection. The objectives of the test were to reduce the GOR in P-18 and to bring P-18 in production. The foam was placed in the target reservoir zone, which was isolated in the well during injection by a packer. It became apparent from downhole pressure measurements that a strong foam had been generated in the formation. The treatment resulted in a GOR reduction of more than 50% over a period of 2 months, resulting in a significantly increased oil production from lower reservoir zones. It is expected that a more gentle opening of the well after treatment could have increased the effective treatment period. Other North Sea foam treatments to reduce the producing GOR are discussed in Refs. 4 and 5.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe FAWAG Project (Foam Assisted WAG) is a full-scale demonstration by Saga Petroleum of the use of foam for gas mobility control. The injection of foam started in the Central Fault Block at the Snorre Field in August 1998, after a twoyear planning period and many years of active research. The first phase of the project, Surfactant-Alternating-Gas (SAG) injection was completed late 1998, and the co-injection phase is expected to be completed by Summer 1999. Approximately 2000 tons of commercial grade surfactant will be injected in the project. The project is partly sponsored by the European Commission's Thermie program.The paper presents the basic concept behind the method, the selection of chemicals, the logistics for handling of the chemicals and the technical modifications needed on the offshore facility to perform the injection. Preliminary results, particularly the response from the injector, is presented for the first phase of the project.

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This paper presents a summary of laboratory work carried out to support the design of a foam pilot in the North Sea Snorre Field. Displacement tests in Snorre cores (60 cm long) at reservoir conditions (300 bar and 90 C) were conducted to evaluate the gas blocking and mobility reduction properties of foam as a function of surfactant concentration, foam quality, fluid injection rate, oil saturation, type of gas, and ageing time. Several different core flood modes were used: a) and b) gas injection or oil injection at constant pressure drop, c) foam injection at constant rate, and d) and e) gas injection or gas/oil co-injection at constant rate. The surfactant selected for the field test (a C14/16 alpha olefin sulphonate) provided high mobility reduction with the Snorre miscible hydrocarbon gas at oil saturations in the range of 8-19 %PV. Apparent viscosities up to 2500 cP were observed during foam flooding, with some dependence of apparent viscosity on oil saturation. Generally, shear thinning behaviour was observed for wet foam. Gas injection after foam resulted in a decrease in apparent viscosity by a factor of 10; however, significant residual gas mobility reduction was retained. Under an imposed pressure gradient, strong gas blocking by foam was observed. Foam properties do not appear to be a strong function of the surfactant concentration in the range of 0.5-2.0 wt% (which is significantly above cmc). Both surfactant ageing in the core and foam throughput have a positive influence on foam properties. In some experiments, foam propagation was slow compared to the injection rate and required several PV of foam flooding. C14/16AOS adsorption on the rock was in the order of 0.5 mg/g. Based on the results obtained, a 1 wt% surfactant solution will be recommended for a production well treatment. The foam injection strategy will be to follow alternating slugs of surfactant solution and gas with an equal volume of foam by co-injection. Introduction The Snorre Field, located in the Northern North Sea, 200 km north-west of Bergen, was put on stream in August 1992 with water flooding as the primary recovery mechanism. In February 1994 a WAG pilot project involving two injection wells and three production wells was initiated in the Statfjord Formation of the field. Extensive evaluation of the project plans and predictions showed that early gas breakthrough may be a potential problem. As a result, the use of foam for gas mobility control, fluid diversion, and blocking to reduce GOR in production wells has been considered as a means of improving the WAG process. Based on promising results from foam treatment evaluation research, including laboratory experiments and numerical simulation studies, it has been decided to perform a foam pilot to control the GOR in a producer, scheduled for the spring 1996. An injector treatment (foam assisted WAG) may realise much larger potential for improved oil recovery than a producer treatment, but with major technical and economic risks. (The interwell distance in the Snorre field is 700-1500 m). Therefore, to reduce the risk, a producer field test has been proposed as a first pilot. This test will give valuable operational experience for future foam projects, as well as important information regarding foam generation and stability in the Statfjord Formation. A previous paper provides a summary of screening laboratory work carried out to select a surfactant suitable for the field test. The surfactant, a C14/16 alpha olefin sulphonate (AOS), was selected based on criteria set to solubility, foam properties, health and environmental safety considerations, availability, and cost. The present paper summarizes optimisation studies for this surfactant and design recommendations for the producer treatment. These optimisation studies comprise gas blocking and mobility reduction properties of foam as a function of surfactant concentration, foam quality, fluid injection rate, oil saturation, type of gas, and ageing time. The data were used as input to a foam reservoir simulator for evaluation of various foam treatment strategies. Based on integrated results from laboratory and simulation studies, the pilot was designed. Experimental Core and Fluid Preparation. The foam experiments were performed using two composite cores, constructed from core plugs of similar properties from the Upper Statfjord Formation. The characteristics of the cores are summarised in Table 1. P. 563

The stability of foam in porous media has been investigated by core flooding at pressures from 10 to 300 bar, both in the presence and absence of oil. A C16 alpha olefin sulphonate (AOS) and a fluorinated betaine surfactant was studied. In the absence of oil, both surfactants displayed increasing apparent viscosity with increasing pressure. The functional form of the pressure dependence differed for the two surfactants, however. The apparent viscosity increased by a factor of 30 for C16 AOS, and a factor of 3 for the fluorinated surfactant. At 300 bar, the two surfactants performed identically. In the presence of oil (hexane-diluted stock tank oil at low pressure and reservoir oil at high pressure), C16 AOS again displayed increasing foam stability with increasing pressure, while the fluorinated betaine showed the opposite trend. The data from experiments in oil free cores are discussed in terms of the limiting capillary pressure theory, and measured pressure variation of the surfactant solution surface tension. The effects of oil on foam stability was assessed by measurement of spreading and entering coefficients at different pressures. For C16 AOS, no change in these coefficients was observed between 20 and 300 bar. For the fluorinated surfactant both coefficients changed significantly, to values indicating detrimental oil-foam interaction at high pressure. Thus, the change in oil-foam interaction seem to explain that the fluorinated surfactant did not show increasing foam stability with pressure in the presence of oil. The observations show that both the foam stability in absence of oil and the oil-foam interactions varies differently with pressure for different surfactants. This implies that flooding experiments at reservoir pressure are required for a proper screening of foamers.