The Campos Basin in Brazil is one of the most challenging areas for completions in the world due to the lack of formation consolidation, the large percentage of fines present in the reservoir, the heavy oil, the low frac gradients, the low net-to-gross ratio, the low bottomhole temperatures and the requirement for pressure maintenance. The development of the Albacora Leste Field in the ultra deep water Campos Basin was a key component of Brazil's drive to achieve petroleum self sufficiency by 2006. Because of the challenges presented by the heavy oil and the large geographical extension of the reservoir, the decision was made to develop the field with horizontal openhole gravel packs for both producers and injectors. Fifteen production wells and eleven injector wells were drilled and completed in the field. As a result of the perceived technical complexity of the development, and requirement to maximize completion efficiency, the operator chose to maximize the integration of the services by bundling their acquisition from a single integrated services supplier, rather than contracting the required well construction services in a discrete manner, as had been traditionally done in the Campos Basin. Horizontal openhole gravel packs, as planned for the development of Albacora Leste, were already an established and successful completion technique in the Campos Basin. However, the Albacora Leste wells were amongst the longest attempted in the basin, and due to the combination of the ultra deep water and limited sediment thickness, had significantly lower frac gradients than previously experienced. The challenges of minimizing placement pressures, accurate modeling of gravel placement, rat hole mitigation, and injection well clean-up all had to be addressed. The solutions developed to meet these multiple challenges will be presented in this paper. Introduction With an area of 141 km2 (34,842 acres) and OOIP of around 3,800 million barrels(1), the giant Albacora Leste field is the 4th biggest field in Campos Basin. The field was discovered in 1986. However, at that time, the development of a field challenged by ultra deep water, heavy oil, and completely unconsolidated sands in a complex turbiditic reservoir, was beyond the technical capacity of our industry. Consequently, the development was delayed until 2002, to enable Petrobras to develop the necessary technology and expertise to meet these challenges. In 1998, the appraisal well 4-RJS-477 was drilled and put on an extended well test (EWT). The well was completed with a cased hole gravel pack (CHGP), and the oil production pumped to a neighboring platform. This EWT required the deployment of the world's first Electric Submersible Pump (ESP) designed for use in ultra deep water. Due to the geological complexity (resulting from a complex turbidity depositional system, mainly represented by channels, lobes and overbank facies and the action of later erosive channels) and complex distribution of fluids saturation in the reservoir, 7 pilot wells were drilled during the planning phase, prior to 2002. This pilot program led to a development plan with 16 horizontal producer wells, with lateral extensions around 650 m and 14 horizontal injector wells, with lateral extensions ranging from 650 m to 800 m. Further analysis added one producer and one injector into a new portion of the reservoir.
This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Houston, Texas 3–6 October 1999.
The sand control completion is the last step in the well construction. It is the step that turns the well from an expense to a revenue generating asset. While every sand control completion is designed for success, things don't always go to plan during the installation, and the technical and commercial results are sometimes less than perfect. Failures can range from minor issues that can be easily remedied to catastrophic events that put the entire well, and investment, at risk. Regardless of severity, it is critical that all failures are analyzed to determine the root cause, prevent them from being repeated and protect asset value. The success of a sand control installation should not be assumed and can only be confirmed with a thorough review of all available job data. This paper introduces several case studies of failures that occurred during sand control installations and details the investigative process and techniques used to identify the root causes. Examples include events such as screen/wash-pipe damage, bridging, hole collapse, and packer seal failure. This analysis provides key insights into downhole events and mechanisms that can be used to minimize risk and improve future completions.
This paper presents the first case study on using chemical tracers for flow profiling a subsea horizontal well with an open hole gravel pack lower completion in Enfield field, Australia. The principle of the technology involves positioning a number of different tracer materials, each at specific locations along the length of lower completions, prior to lowering downhole. The tracers are selected to be soluble in either crude oil or water. Upon well start up, oil samples are taken at the surface over a short period of time. These samples are analysed to determine tracer presence. The presence of one or a combination of unique tracers within the oil sample, along with the known location of each tracer downhole, allows qualitative information to be generated about fluid flow in the well. Chemical tracers for flow profiling were chosen for ENA03L1, an oil well intersecting a number of fault blocks in the south of the Enfield field to:Provide direct proof of fluid flow from different fault blocks;Improve understanding of well clean up of a horizontal well, especially the contribution from the toe of the well; andDetect the location of water breakthrough. Results showed that within four hours of the initial clean up, all oil soluble tracers were detected, providing positive confirmation that the intervals tagged, including the toe of the well, were contributing to the overall production. Using tracers for flow profiling horizontal well provides the following benefits: Enables flow position to be verified in long horizontal wells; and Comparatively inexpensive when compared to horizontal well production log costs. This case study recounts the design, installation, analysis, results and subsequent learnings of the project.
The Enfield development was the first oil field to be put into production in the Greater Enfield Area. These fields lie in deep water off the North West Cape area of Western Australia. Operated by Woodside on behalf of the Enfield Joint Venture, this was the first oil field development for Woodside requiring horizontal open hole completions with sand control. The challenge for this project was to deliver early oil production from a low well count with wells producing from an unconsolidated and faulted formation containing shale. The remote location posed an additional challenge for the development. SPE 127394A key feature of Enfield is the presence of faults in the reservoir that act as flow barriers during production and injection. Due to lack of aquifer connectivity, the development concept for Enfield uses a line drive type water injection pattern, with a row of injectors near the oil-water contact and another row of injectors up-dip near the gasoil contact. Seawater is used for water injection, and this has been combined with produced water after breakthrough in the oil producers. Produced gas is compressed and injected into the gas cap, excluding fuel gas for power generation. (Ali et al. 2008, Hamp et al 2008 Geology and Formation DescriptionAt Enfield, the Macedon sandstone can be divided into upper and lower reservoir units, based on seismic architecture and sedimentology. The upper unit, which extends across the field and varies in thickness between 10 to 20 m, is characterised by very friable, fine to medium grained sandstones. They are generally massive, clean and homogeneous with rare bedding features and occasional shale intra-beds. The lower unit is more confined and can be up to 50 m thick consisting of stacked packages of very fine to fine grained relatively clean sandstones. They have more internal sedimentary structures (e.g. laminations and cross-bedding) with shale interbeds locally preserved between the cleaning-upward packages.The sandstones are interpreted to have been deposited from a series of high-density, rapidly deposited, sandy turbidity currents (submarine sand avalanches), initially infilling the existing seabed topography before becoming more unconfined and expanding areally. The intra-reservoir shale beds represent background deposition between the turbidite flows.
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