TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA redevelopment strategy for a hydrocarbon producing reservoir in a complex geological environment is presented in this paper. With the application of the IOR technology, the hydrocarbons, which seemed to be hidden in unreachable parts of the reservoir, became economically extractable, increasing the value of the field. The thin oil column and the large gas cap are trapped in a low permeability turbidite type sandstone reservoir. The thickness of layers separated by interbedded claymarles is less than 10 meters of each. In the first 15-year production period 12% oil recovery could be reached from the reservoir having 10 mD average permeability. At starting of the production the depletion mechanism was gas cap expansion combined with weak water drive (1975)(1976)(1977)(1978)(1979)(1980)(1981)(1982)(1983)(1984)(1985). The initially flowing wells started to produce with artificial gas lift in 1980. Water injection was necessary to maintain the reservoir pressure so this technology was launched in 1985. In the early 90's the reservoir had very poor economics because of the low productivity and injectivity of vertical wells. The forecasted production rates had been keeping to the economic limit. 1993 was a mileage in the production history because the first horizontal well was drilled and completed in the reservoir. By the end of 1999 the number of horizontal oil wells was increased up to 20 inducted by the excellent production results. During this production period, the continuous reservoir monitoring reflected the problems of different phases of exploitation and what kinds of solution alternatives were induced by the integrated interpretation of the increasing information obtained from production history. This paper answers how the production potential of the reservoir could be doubled in the last seven years and how the forecasted ultimate oil recovery increased to over 40%. Redevelopment of this producing object was reached by the IOR technique. Infilling of the producing well pattern and acceleration of exploitation was the key in this mature reservoir. With 3.6 USD/bbl investments an additional 5.2 million equivalent barrel reserve became proved.

In Hungary, the oil prices in the range of $20 makes EOR projects commercially viable. Because of their structures and fluid properties, the oil reservoirs in Hungary are suitable for gas injection EOR methods. This EOR potential is well supported by favourable infrastructure in the local oil industry/surroundings. The paper presents the EOR application for a large reservoir in the Pannonian basin. The Szeged-Móraváros is undersaturated fractured reservoir with Triassic dolomite, Miocene sandstone and conglomerate at the depth of 2630–2450 meters below the sea level. The OOIP derived from material balance is 11.56 million cubic meter and oil gravity is 817 kg/m3. The initial pressure was pr=331 bar, initial temperature was tr=140 °C. In the period of the natural depletion between 1975–1980, the cumulative oil production was 1,27 million cubic meter. In this period, because of the limited water influx, the reservoir pressure dropped below the bubble point and secondary gas cap started to increase. The pressure dropped to pr=244 bar. In 1980, water injection was started to maintain the reservoir pressure. The aim was to increase the reservoir pressure above the bubble point pressure. With this water injection from 1980 to the present time, the oil recovery is 36.4 % with a cumulative oil production of 4.21 million cubic meter. The current reservoir pressure is 250 bar. For studying the further recovery enhancement, laboratory and reservoir simulation studies were carried out to evaluate different gases. Natural gas, nitrogen, and CO2 were selected for the gas injection near the structure top. In Hungary, large CO2 reserves are available 50–250 km distance from the oil field. The natural gas resources are easily available because of the developed gas distribution network and the production of nitrogen by stripping from the air can be also easily realised. At the optimal pr=250 bar pressure, the displacement process is not miscible in the reservoir, and the recovery increment is not sensitive to the type of injected gas or its quality. The reservoir simulation shows the recovery increment is about 12 %. We have selected nitrogen gas as an injection gas based upon economic and environment evaluations. The paper describes how we arrived at this conclusion in a country where there is a well-developed natural gas market. The paper also includes discussion about the methods and criteria used to select the process. Introduction The amount of the produced oil and condensate coming from the EOR processes is 170,4 thousand tons recently. More than 70 % of the total amount is connected to gas injection technologies mainly to CO2 injection but methane and ethane rich gases are also used as the material of EOR injection mass. CO2 is available from natural resources in the Western part of the country, here is the largest CO2 injection project is taking part. In the central area of the country, only limited natural CO2 resources are available. Here a gas enriching plant is working where the CO2 is forming as a sideproduct. CO2 reservoirs are also in the eastern part of the country but their development has not yet begun because of the lack of utilisation. However the most important oil resources of the country are in the Southern, Southern-East areas relatively far from the above mentioned CO2 areas. Therefore, in this region, studying the possibility of methane and nitrogen injection is necessary because of the limited or cost requiring availability of CO2. A systematic screening was made between 1997–2000 for the Southern-Hungarian oilfields. The most important conclusion of the study was that the temperature and pressure conditions, the geological features and the PVT characteristics of the reservoir fluids are favourable mainly for the EOR with gas injection.

The first horizontal well was drilled in Hungary in 1989 and thereafter 60 horizontal sections were completed. The 76% of these wells are in the Algyo field, which is the largest HC accumulation in the Pannonian basin. After a 25-year production, the inaccessible hydrocarbons, which are deposited in unreachable parts of the reservoirs, have become producible by using horizontal wells. The target of the reservoir management was to maximise the long-term profit of the field by acceleration of reserves, reduction of gas and water coning, and by effective use of depleted gas reservoirs and existing vertical wells. In this paper we have summarised the reservoir management approach to enhance the value of the field. In a complex turbidite sandstone reservoir the oil production capacity is doubled by infill drilling of horizontal wells. This has added 5.0 Million bbl of incremental reserves. In a multilayered part of reservoir Algyo-2 W-2, approximately 1.2 Million barrel of by-passed reserves have became producible after 25 year water injection. By reducing gas and water coning in the reservoirs Csongrad-Del-1and 2, the oil production rates and the efficiency of well utilisation have been increased. The depleted Maros-1 sandstone reservoir is now used for underground gas storage and existing gas wells were re-entered and completed to achieve higher daily peak rates. A gas cap exists in the most part of the oil reservoirs. Development of the gas production well pattern started in the early 90's. By decreasing the number of wells, improving the daily gas production capacity, and speeding up the exploitation of gas cap reserves, the NPV value was maximised. In all cases, to reduce costs, existing vertical wells were re-entered and so the over all value of the assets was improved. Introduction The horizontal and multilateral wells have been a revolutionary breakthrough in the hydrocarbon industry of the world as well as in Hungary. The first horizontal well was drilled in Hungary in 1989. In the 90's, the number of horizontal wells have been increased significantly in the world. In Hungary, 60 horizontal wells had been drilled so far, of which 46 are in the largest hydrocarbon field, Algyo Field, in the Pannonian basin. Tab. 1 shows the areal distribution of the wells. The increase in the number of horizontal wells in the last ten years can be seen in Fig. 1. In 1995 only 16 horizontal wells were operated in Hungary but their number has almost quadrupled. Similarly to the rest of the world, also in Hungary, the size of the newly discovered oil and gas reservoirs is becoming smaller and smaller each year. So to replace the reserves, one has to maximise reserves from the operating, mature fields by the application of the EOR/IOR methods. In the case of the depleted gas reservoirs, the development of the underground gas storage facilities means new possibilities. Their development is required due to enhanced market demand and the seasonal nature of the gas demand. In all of the cases listed here, the horizontal well technology is applied as a very important reservoir management tool. We would like to present the example of the Algyo fieldwhere the different applications of horizontal wells were used as reservoir management tools in the different reservoir types.

No abstract

No abstract