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Abstract One of the most challenging problem in reservoir management for mature steam flood Area in determining hydrocarbon potential left in the reservoir is the management decision for go and no go project. Duri Area 11 is located in Central Sumatera and operated by PT. Caltex Pacific Indonesia. This area is the north from the primary Duri Steam Flood (Area 1, 2, 3, 4, 5, 6, 7, and 8). The Problem in mature steam area was the reservoir is heating up and has indication of smectite clay in Rindu formation, and experience of steam eruption in Surrounding Area (9, 10). In fact, the oil recovery become lower and the production cost become higher. The Extensive analysis was needed starting from 4D Seismic, geology model interpretation, fault seal analysis, geomechanics, reservoir characterization, steam chest prediction and the economic before the government give approval to develop the field. Phasing development option will be implemented to reduce the potential of loss money as a possible option. The integrated high grading area was combined with economic analysis to propose reliable decision. The change of development plan scenario will give different investment and producing in which initial POD was full development become phasing development. The changing plan will be affected to government and contractor share. The monitoring, and production analysis respond, steam temp, pressure and referable reserve at each phase development will support in improve production performance and economic field. Based on the experienced and integrated approvals technology and economic, the real picture of development of Duri Field as a mature steam flood with unpredicted steam eruption has been solved and changed the no prospect development to prospect development. Introduction Duri field is located in Central Sumatera, the site of the world's largest steam flood, is operated by PT. Caltex Pacific Indonesia. The field is divided into 13 development areas. Ten of these areas, Area 1 to 10, have been under steam flood. The Duri steam flood began with area 1 in 1985. The area 11 is the north from the primary Duri Steam Flood (Area 1–10). The Problem in mature steam area was the reservoir is heating up and has indication of smectite clay in Rindu formation, and experience of steam eruption in Surrounding Area (9, 10). (Figure 1).
Zhong, Liguo (Northeast Petroleum University) | Zhang, Shoujun (Liaohe Oilfield) | Wu, Fei (Liaohe Oilfield) | Lang, Baoshan (Liaohe Oilfield) | Liu, Heng (Liaohe Oilfield) | Liu, Tao (Daqing Oilfield) | Liu, ShuXia (Daqing Oilfield) | Gao, Wenlong (Greatwall Drilling)
Abstract Horizontal well steam injection is effective to recover heavy oil for its large reservoir contact. To date, more than 150 horizontal wells have been drilled in Shuguang oil region, most of them are operated in steam stimulation and SAGD processes, and completed with slotted liner at length from 100 m to 500 m. But it is much challenging to recover oil from reservoir along horizontal well proportionally because of steam characteristics, large well length and reservoir heterogeneity. Results of simulation and field temperature testing show that only about half of reservoir along horizontal wellbore is recovered well, and average OSR (defined as ratio of oil production to steam injection) is less than 0.28, and it is not satisfying for the large cost of horizontal well drilling and completion. Furthermore, steam crossflow between wells and pressure depletion in local reservoir well steamed could also result in reduction in oil production and OSR. To improve horizontal well steam injection, separated-zones horizontal well steam stimulation technology is developed, in which temperature sensitive packers, outlets, pressure sensitive valves and ball sealers are involved. The steam injection of different zones separated by packer(s) could be regulated or controlled according to engineering design. There are four techniques developed including dual-zones steam injection in sequence or at one time, selected zone steam injection, and simultaneous multizones steam injection. In order to investigate temperature and steam injection of different reservoir zones along horizontal well in different steam stimulation process, experiment, numerical simulation and field testing are carried out in past three years. In this work, laboratory experiments are carried out with large simulation apparatus packed with sampled oil sand and equipped with temperature sensors and pressure sensors at first. Secondly, structure of steam injection pipes and steam injection scheme are optimized based on numerical simulation, and primarily reservoir selection requirements are also provided. Thirdly, result of application of separated-zones steam injection to 76 wells and monitoring of temperature and pressure is presented, and considerable improvement of steam injection and heavy oil recovery obtained. At last, the future of intelligent separated-zones horizontal well steam injection is prospected.
During the past 15 years, steam-injection processes have become an importantmeans of exploiting heavy oil reserves. Traditionally, these processes havebeen classified as either steam soaks or steam drives. With combinations, suchas presoaking drive wells and partially driving steam soaks, the distinction isnot always applocable. Furthermore, our experience auggests that oil/steamratios from most mature processes converge to a calue determined only byreservoir and steam properties and time.
To date, the steam-soak process has proven the more attractive, partlybecause the immediate response allows an early evaluation of a reservoir andpartly because oil rates from initial soak cycles tend to be better than latercycles. Successful steam soaks are limited to reservoirs where natural recoverymechanisms (gravity drainage, pressure depeletion, and solition gas drive)areineffective because of the low oil mobilities.
Successful steam drives require (1) good conformance, (2) a means ofstarting the process because high oil saturations can limit injectivityseverely and prevent effective initial reservoir heating, and (3) sustainedhigh injectivity throughout the process life. Unlike steam soaks, steam drivesdo not respond until built-up oil banks and heat reach the production wells.Because peak production rates may not be observed for several years after thestart of injection, piloting is expensive and expansion to full scale issoemwhat hazardous. For those reasons, screening methods that predict ultimateoil/steam ratio are useful in planning new projects or in modifying existingones.
In the past, steam injection has been applied to a wide spectrum ofreservoir conditions, many of which have proven unsuitable. In retrospect, wecan explain the varied response withh a simple mathematical model thatincorporates reservoir and steam properties in the prediction. This paperdescribes the model and compares prediction from it with laboratory and fieldresults.
Tao, Ye (Northwest University) | Zhao, Liwen (JSC Karazhanbasmunai) | He, Kai (JSC Karazhanbasmunai) | Duan, Lian (China University of Petroleum) | Zheng, Qiang (Xinjiang Oilfield Company of Petrochina) | Zhao, Libin (Xinjiang Oilfield Company of Petrochina)
Abstract The block S of K oilfield in Kazakhstan is a shallow common heavy oil reservoir. The steam flooding technology has achieved a relatively good development effect in oilfield development. However, due to factors such as reservoir heterogeneity, well spacing, and injection and production parameters, there are phenomena such as low sweep efficiency, short stable production period, and varying effective time during the steam flooding process. The effects of steam injection rate, well bottom steam dryness and production-injection ratio on the development effect of steam flooding in shallow common heavy oil reservoirs are studied by numerical simulation. The results show that in order to achieve the ideal effect of steam flooding in shallow common heavy oil reservoirs, firstly, the steam injection rate is greater than or equal to 1.0t/(d*m*ha); secondly, dry degree of bottom-hole steam is greater than or equal to 30%; thirdly, the production-injection ratio is greater than or equal to 1.1, and when all three indicators are satisfied, the efficient development of steam flooding can be realized. The practice of steam flooding development and adjustment in S oilfield has proved that the numerical simulation results are in line with the expected development effect and through demonstration and comparison of alternative technology schemes of steam flooding, the development effect of water-steam alternating slug flooding is superior to that of hot water flooding, intermittent steam flooding and continuous steam flooding. The technology of water-steam alternative injection is recommended as the development mode conversion at the later stage of steam flooding. The above conclusions can be referenced in the steam flooding development of similar reservoirs.