Slightly more than 10 years after its discovery, Lula Field has the world's largest oil production in ultra-deep waters. This impressive goal was achieved through a robust reservoir-oriented strategy to minimize risks and maximize value during the fast-track development of this giant field. The strategy used in the development of the Lula Field, which aims at attaining a recoverable oil volume of billions of barrels, is described in this work. The methodology applied encompasses four steps. The first step consists on performing an adequate data acquisition during exploratory and early development phases. The acquired data guided the second step, which is the implementation of pilot projects to gather important dynamic information and to anticipate profits. The third step is the deployment of definitive production systems based on robust drainage strategies, built under different reservoir scenarios. The fourth step is production management through the application of innovative technologies in ultra-deep offshore environment, such as water alternating gas (WAG) wells, 4D seismic monitoring, and massive use of intelligent completion. Seismic data and special processing enabled the identification and characterization of the reservoirs located under a thick saline formation. The drilling of reservoir data acquisition wells along with extended well tests was important to appraise critical reservoir regions and to verify communication between different reservoir zones. Extensive fluid sampling and advanced thermodynamic modeling allowed the understanding of Lula Fields complex fluids. Two pilot projects were positioned over 20 km apart from each other on this extensive reservoir, allowing interference tests between the pilots and new drilled wells. Afterwards, eight following production systems were conceived using previously acquired data and flexibilities to accomplish modifications into the project based on new information acquired during the drilling campaign. An example of this flexibility strategy was the empowerment of the reservoir team to propose a specific well drilling sequence and schedule. This allowed the use of newly obtained information from one well to the next, even in a fast track development scenario, in order to optimize productivity and sweep of the reservoir. At last, the reservoir management has already presented promising results related to the control of injected and produced fluids in FPSOs with longer production history. The steps herein presented allowed the successful development of Lula Field, which has nowadays seven FPSOs producing around 800 kbpd. The most recent FPSO started operation in May 2017 and is still ramping up. Together with the remaining FPSOs to be deployed, it is expected that Lula Field will reach a peak of production of around 1 million bpd. Such production levels were never achieved before in a single ultra-deep water field.
Recently discovered oil fields in the Pre-salt area in the Santos Basin, offshore deepwater Brazil, contain a huge volume of hydrocarbons in carbonate rocks, mostly of microbial origin, with pronounced heterogeneity, without any analogues in the world. The fluid usually presents expressive levels of contaminants and a significant compositional grading, laterally and vertically. This complexity denotes how challenging is to define robust development plans and suitable recovery mechanisms. In order to adequately address these issues and optimize the hydrocarbon recovery, the development strategy was supported on three pillars: (i) extensive data acquisition; (ii) strong interpretative work on the geological characteristics which impact fluids displacement and (iii) adoption of comprehensive recovery mechanisms and strategies, adequate for the various scenarios generated in the studies. The data acquisition program includes, at first, a high resolution seismic data acquisition and interpretation. Well information comprises conventional logs, image logs, cores, downhole fluid samples, sidewall cores, pressure transient tests. Additionally, for each area candidate for a production system, an extended well test is performed, with on-line interference tests with neighboring appraisal wells, aiming to evaluate the dynamic properties in terms of areal and vertical connectivity, as well as to anticipate potential problems regarding formation damage, fluid composition variation and flow assurance. Even with this comprehensive data acquisition, the complexity of reservoir rock sustains a large range of uncertainty in their properties, which will only be reduced throughout the productive life of the field. Therefore, the second pillar of the field development is built through a deep dive on the data by the geoscientists, in order to extract the geological attributes that impact the displacement and sweep efficiency of the oil. This goal is not always possible to obtain in a straight and deterministic way, but often through multiple possible scenarios. This is referred mainly to features as horizontal permeability distribution, presence of faults and barriers, vertical communication, fracture corridors, high permeability channels, among others. For the construction of the third pillar, a strong synergy between the disciplines of geoscience and reservoir engineering is necessary, so that the geological interpretation is incorporated and applied to the flow simulation model and, the most important, support the design of robust strategies to optimize oil recovery, under uncertainty conditions. When information is considered as perfect, it is immediately incorporated into the plan. Otherwise, multiple scenarios will persist for a longer period, making it necessary to apply strategies that can be effective in different conditions, and can be matched as soon as the real scenario is revealed. This paper describes the approach adopted for the development of the Pre-salt fields, supported by the aforementioned three pillars, and detail...
Since the beginning of the Santos basin pre-salt commercial production, in December 2010, more than 1 billion barrels of high quality oil have been extracted from these ultra-deep water carbonate reservoirs. To enable and accelerate production, Petrobras and its partners applied advanced and innovative technologies in various areas of engineering. This paper focuses on the reservoir strategies conceived during the design phase of the Lula and Sapinhoá development projects and their application in these fields. The authors highlight practices and processes whose extensive use, in this type of scenario, were not standard. Among these, the dynamic characterization of the reservoirs by the use of long-term tests coupled with remote monitoring of pressure; water and gas production control by alternating injected fluids; intensive use of intelligent completion; convertible wells to accelerate production growth (ramp-up); CO2 injection from the start of production; rock-fluid interaction tests; optimization of well stimulation and many others. Knowledge acquired during the first seven years of commercial production and the actions implemented to manage the reservoirs reflect on the production plateau extension and the final length of their expected productive life. The collection and analysis of static and dynamic data proved to be valuable to reduce uncertainties and support further development decisions. Integrated effort contributed to risk mitigation, production maintenance and increased forecasted final recovery. The results obtained emphasize the importance of an effective reservoir management approach to maximize production and recovery. Concepts adopted are clarified through practical examples showing the advantages and gains from their implementation. The final message is that safe and viable operation of ultra-deep offshore fields benefits from additional investments in acquiring specific reservoir data. Their integrated analysis using advanced and up-to-date techniques is considered essential to maintain and improve asset values.
The continued increase in oil demand associated with the growing concern about the greenhouse gases has been an additional driver for CO 2 injection into oil reservoirs. The application of this EOR method usually occurs at a later stage in the development of a field in which the operating surface facilities were normally not specified to manage high levels of CO 2 . Therefore, the aim of this work is to evaluate, by proper fluid characterization and compositional reservoir simulation, the benefits and risks of CO 2 injection in a particular sector of an offshore reservoir, surrounded by production units not fully specified to deal with elevated concentrations of CO 2 .The presented workflow, combining reservoir engineering analysis with production equipment aspects, can be applied to any target field for a CO 2 injection project. However, it is even more relevant for mature offshore fields, where a CO 2 production growth leading to the necessity of replacing all production facilities would probably make the project fail economically.For the particular field analyzed in this article, the deployment of a production unit able to inject CO 2 from an external source in an undrained region of the reservoir, hydraulically connected to an area already in production, would bring benefits not only to the region where the injection would occur but also to the adjacent area. The CO 2 migration to the neighboring area decreases the levels of CO 2 to be processed in the new platform plant, allowing its technical and economic feasibility, as well as increases the recovery factor of the adjoining area, without reaching levels of CO 2 and gas flow rates beyond the limits of the plant already in operation. Furthermore, the reservoir's capacity to retain CO 2 , acting as a carbon sink, is also evaluated.This study thus presents an integrated workflow for an optimal CO 2 injection project design, considering not only the benefits in terms of recovery in the target area of the project, but analyzing the impacts and risks to surrounding areas.
This paper presents the successful history of Lula NE Pilot Project, a challenging megaproject with an aggressive time-driven schedule, faster than industry average, that demanded new technology development in a scenario of uncertainty. The area is part of the supergiant Lula field, located in the pre-salt region of Santos Basin, Southeast Brazil, 300 km off the coast of Rio de Janeiro state, in 2000 m water depth. It is a joint venture with Petrobras as the Operator, and BG E&P Brasil and Petrogal Brasil as partners. The project was designed as a Pilot aiming to test some new concepts for the production development in the pre-salt area. In terms of subsea gathering system, an innovative concept was deployed, combining flexible flowlines lying on sea floor, with rigid steel catenary risers (SCR) supported by a buoy positioned 250 m below sea level. The drainage plan considered eight oil producers, some of them with intelligent completion, one gas / CO2 injection well and five water alternating gas (WAG) injectors (two subsea WAG manifolds were also installed). A balanced approach between data acquisition and facilities flexibility made possible to face the many reservoir and production uncertainties. Details of the development concept will be discussed, as well as the main results obtained so far, highlighting the strategies adopted in order to mitigate risks and the influence of the acquired information to the following projects in the area. The chartered FPSO Cidade de Paraty started production in June 2013, with an oil capacity of 120,0 bpd, and a gas plant able to process up to 5 million m3/d of gas with 35% content of CO2. Despite all challenges faced, the project was delivered on time, with plateau attained in September 2014.
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