With more than 100 thousand square kilometers and representing about 58% of Brazil's oil and gas daily production in 2016, Campos Basin has proved its gigantism by producing 12 billion barrels of oil equivalent since 1977, extracted from the various concessions, like the giant fields of Marlim, Roncador and Jubarte. Comprising fifty-three production units, 711 wells and 14.8 kilometers of subsea pipelines, Campos Basin can be considered one of the largest offshore oil and gas complex operated by a single company in the world. In this context, considering the relevance of this oil province, this paper aims to present the journey of Campos Basin, summarizing the main challenges overcome in the last 40 years, the technologies developed, the strategies applied and the results obtained.
Chang, K. (The University of Western Australia) | Hossain, M. S. (The University of Western Australia) | Kim, Y. H. (The University of Western Australia) | Randolph, M. F. (The University of Western Australia) | Wang, D. (Ocean University of China)
This paper proposes a novel dynamically installed ‘fish’ anchor, adopting a geometry taken from nature, for economic and safer tethering of floating facilities in deep water. Every cross section of the fish anchor shaft is elliptical, leading to very low drag resistance during free fall through the water column, and also low resistance in penetrating the seabed sediments. The padeye is fitted on the widest part of the shaft to mobilise the maximum resistance area under operational loading. The fish anchor embedment depth during dynamic installation, and capacity under both monotonic and cyclic operational loading in calcareous silt were assessed through centrifuge model tests and large deformation finite element (LDFE) analyses.
During dynamic installation, the normalised tip embedment depth of the fish anchor was typically three times that for the torpedo anchors and 50 % greater than that for the OMNI-Max anchors. Under operational loading, the fish anchor dived deeper, reaching penetrations 20 to 60 % greater than achieved during installation. By contrast the torpedo anchors (for all mooring mudline inclinations) and the OMNI-Max anchors (apart from a single test with mooring mudline inclination of 0°) pulled out directly without diving, reflecting insufficient free-fall penetration in calcareous soil. Regardless of the padeye offset ratio and mooring mudline inclinations, the diving efficiency of the fish anchor, which dictates the potential gaining capacity, was significantly higher than that of the OMNI-Max anchor. The normalised net capacity of the fish anchor was significantly higher than obtained with the torpedo anchors regardless of mooring mudline inclinations, and comparable to that obtained with an OMNI-Max anchor for mooring mudline inclination 0°, after allowing for loading-unloading cycles experienced by the OMNI-Max DIA prior to a nominally monotonic loading test.
Dynamically installed anchors have yet to be used in calcareous silty sediments (e.g. offshore Australia). This is primarily because the anchor tip embedment depth in calcareous silt has been found to be only half of that in clay due to the naturally higher undrained shear strength gradient and high dilation-induced bearing and shaft resistance. During subsequent loading, the anchor then pulls out of the seabed, without diving. To achieve adequate capacity under operational loading, deeper penetration that allows anchor diving and better diving potential are therefore critical in calcareous silt. The fish anchor was found to dive in calcareous silt for mooring mudline inclinations < 38°, while by contrast the OMNI-Max anchor generally did not dive. As such, the fish anchor has the potential for efficient anchoring to allow economic development of oil and gas reserves in deep water with calcareous seabed sediments.
Laquini, S. (Petrobras S.A.) | Fernandes, P. Tavares (Petrobras S.A.) | da Costa, B. P. M. (Petrobras S.A.) | Delalibera, C. A. Armani (Petrobras S.A.) | Moura, P. H. S. (Petrobras S.A.) | Gonçalves, F. F. (Petrobras S.A.) | Costa, C. H. O. (Petrobras S.A.) | Oliveira, J. G. (Petrobras S.A.) | Pereira, M. C. (Petrobras S.A.) | de Oliveira, R. Caldeira (Petrobras S.A.)
This paper presents the technical solutions assessment and details of the first implementation of the prelaying procedure of flexible lazy wave risers, including buoyancy modules, before FPU arrival, on a Pre-Salt scenario. Flexible risers are easily handled due to the small bending radius allowed during installation phase. Despite of that, the water depth and differential pressure in Pre-Salt scenario result in several customized flexible pipe structures, which makes pre-lay much more complex. Other limitations regarding monitoring system, recovery strategy, hibernation conditions, commissioning, buoyancy modules design water depth and intention of pre-laying several risers also turn installation limitations in evidence. To overcome all these challenges, a hard work together with flexible riser suppliers and installer specialists had to be done to find a feasible way for pre-laying. The results obtained with assessment studies and first installations were crucial to mapping the risks and benefits associated to the pre-laying of flexible risers. A large part of the riser installation time is consumed by the required time to assemble the buoyancy modules on pipe.
The oil industry has faced growing demand for subsea facilities to enable the development of ultra deepwater oil fieds. The use of manifold is an alternative widely considered in subsea arrangements. In order to apply this alternative, it is necessary to follow a chain of project that demands special care since its manufacture, installation, commissioning, productive life and possible demobilization, being able to culminate with the removal of equipment from the location. These equipments, sometimes weighing a few hundred tons, require special attention during planning the installation. Thus, this paper proposes to present the challenges faced in the planning and installation of subsea equipments in deepwater, the evolution of the manifold installation techniques at Petrobras, as well as present the main installation methods currently used in Pre-Salt fields and new techniques in development for the installation of large subsea equipments.
Gaudin, Christophe (University of Western Australia) | Cassidy, Mark J. (University of Western Australia) | O'Loughlin, Conleth D. (University of Western Australia) | Tian, Yinghui (University of Western Australia) | Wang, Dong (University of Western Australia) | Chow, Shiaohuey (University of Western Australia)
The role of offshore anchors is to keep a floating facility on station. These facilities include oil and gas structures in deep water (e.g., floating production, storage, and off-loading platforms) and renewable structures in shallow water (e.g., wave energy converters). They can be located either directly on the seabed (e.g., gravity anchors) or deep within the seabed (e.g., plate anchors, torpedo anchors, suction caissons, and piles), with the choice of anchor reflecting the mooring requirements and the type of seabed sediments (Randolph and Gourvenec, 2011). Driven by both economic and technological considerations, the last three decades has seen the evolution of anchor technology and the emergence of new anchoring solutions to comply with - changing seabed conditions encountered in frontier regions; - changes in mooring configurations, operating water depths, and sea states; - increased holding capacity requirements associated with larger facilities; and - different loading conditions associated with offshore renewable energy devices. Notable examples of new anchor configurations, as shown in Figure 1 and concentrated on in this paper, include (i) vertically loaded anchors (VLAs) that penetrate into the seabed by being dragged over a distance of 50-150 m, (ii) suction embedded plate anchors (SEPLAs) that are installed in the soil to a targeted depth using a follower (typically a suction caisson), (iii) dynamically installed anchors that penetrate into the seabed by falling freely through the water column from a targeted height, and (iv) helical anchors that are "screwed" into the seabed. These complement the traditional pile and (more recently) the suction caisson, which have been commonly used for permanent deep offshore floating facilities. The mooring lines of anchors are installed either in a catenary configuration (e.g., for floating production storage and offloading) in which a significant horizontal load is applied to the anchor or in a taut or semitaut configuration with lines at 40
Dynamically Installed Anchors (DIAs) refer to anchors which can embed themselves by free-fall from a specified height above the seabed. They have been widely regarded as the most promising deepwater anchor concept in terms of several advantages over other anchors. First, it is economical because of ease fabrication, quick installation, and no requirement from external source of energy. Second, the installation cost is less depend on the water depth. Finally, the holding capacity is less sensitive to the soil undrained shear strength profile since higher seabed soil shear strength permit less penetration depths and vice versa. However, a degree of uncertainty still exists in relation to predicting the embedment depth and subsequent pull-out capacity especially the inclined pull-out capacity.
The pull-out capacity of DIAs can be dominated by the vertical or horizontal failure mechanisms or a combination of the two. When the combination controls, the DIAs are referred to as being under the inclined pull-out failure. This paper focuses on the inclined pull-out failure of DIAs. A series of finite element analysis on pull-out resistance of DIAs in normally consolidated clay was carried out. First, the numerical results were validated through experimental results and analytical empirical results. A proper method to model the inclined pull-out of DIA is illustrated. Then, a methodology for evaluating the inclined pull-out capacity of DIA is proposed based on the numerical parametric study. This method is capable of predicting pull-out capacity of DIA for various embedment depths and DIA aspect ratios. Finally, the design procedure for DIA is proposed.
"To produce the most viscous oil from completely unconsolidated sandstone in ultra deep waters". This summarizes the challenges to construct the wells to exploit the Atlanta field, Santos Basin, Brazil. The ultra deep water of 1550m, the use of a powerful subsea ESP with 1,600 HP, the need of long (850 m) open hole horizontal gravel pack (OHHGP), the low burial depth (800 m) resulting in low reservoir temperatures (100 F) and extremely low fracture gradient (0.50 psi/ft), the highest acidity of a crude (TAN=9.8) are some of the difficulties that had been overcome to drill, complete and test the first 2 production wells of the Atlanta Field.
Atlanta is a post-salt oil field located 185 km off the coast of Rio de Janeiro. The field was discovered in 2001 and during the same year a deviated well was drilled to test the eocenic sandstones. A cased hole gravel pack was installed in 90m of perforated interval. The completely unconsolidated sandstone showed high porosity (36%) and high permeability (5D). While the rock properties are excellent, the oil is heavy and viscous (14° API and 228 cP in reservoir conditions), with the highest acidity registered (TAN=9.8).
In 2006, a horizontal well was drilled to test the full potential of this kind of construction, which included and OHHGP, and to validate the field development concept. However, crucial problems were faced during the drilling and completion phase. Directional control problems led to two sidetracks. The horizontal section experienced massive fluid loss. Only part of the screens was run in the open hole. The attempt to pack the screens, with alpha-beta waves, resulted in a premature screen out leaving a SAS completion. Even after these problems, the well was tested, with solid production causing the ESP failure. The partially conclusive DST showed a severe damaged well, with high skin of 40.
The bad experience in constructing a horizontal well in these challenging conditions compromised the reliability of the project. But in 2012, a new operator decided to revisit this project. After considering technology improvements, an extensive preparation and a complete assessment of past operations were performed. Finally, in 2013 and 2014, 2 wells were drilled and, using the best technologies, 100% packed in the full horizontal length (800m) drilled. Both wells were tested showing zero skin.
This paper presents the main challenges and how they were overcome by using the best sand control techniques, resulting the successful construction, gravel packing and testing the first two production wells, recovering the reliability of the project and encouraging to move on to the next phase.
Won, Jonghwa (Daewoo Shipbuilding and Marine Engineering) | Kim, Youngho (The University of Western Australia) | Park, Jong-Sik (Daewoo Shipbuilding and Marine Engineering) | Kang, Hyo-dong (Daewoo Shipbuilding and Marine Engineering) | Joo, YoungSeok (Daewoo Shipbuilding and Marine Engineering) | Ryu, Mincheol (Daewoo Shipbuilding and Marine Engineering)
This paper presents the damage assessment of a free-fall dropped object on the seabed. The damage of a dropped object totally depends on the relationship of impact energy and the soil strength at the mudline. In this study, first, unexpected dropping scenarios were assumed varying the relevant range of the impact velocity, structure geometry at the impact moment and soil strength profile along the penetration depth. Theoretical damage assessments were then undertaken for a free-fall dropped event with a fixed final embedment depth of structure. This paper also describes the results from three-dimensional large deformation finite element (LDFE) analysis undertaken for the validation purpose. The analyses were carried out using the Coupled Eulerian-Lagrangian approach, modifying the simple elastic-perfectly plastic Tresca soil model. The validation exercises of each dropped scenario show a good agreement and the present numerical approach is capable of predicting the behavior of a free-fall dropped object.
FLNG facilities present a more onerous anchoring requirement than existing floating structures. Optimisation of the anchoring technology through improved design or through novel anchor types offers potential cost and risk benefits. These benefits may also be applicable to smaller moorings for MODUs and FPSOs. This paper uses concept–level design calculations of anchor capacity to compare different anchor technologies in the context of FLNG and MODU/FPSO applications. Also, new observations from physical modelling of chain–soil interaction are presented. Opportunities are identified for significant cost and schedule savings by adopting the alternative plate anchor technologies that are either suction or dynamically installed. Considering fabrication alone, the estimated costs are reduced by 70% for FLNG and 80% for MODUs relative to the conventional suction caisson option. When installation vessel costs are considered, the absolute cost saving could be far higher than from fabrication alone because installation could be from an anchor–handling vessel rather than a construction barge with a heavy lift crane. Torpedo anchors have also been considered, but are less attractive. Centrifuge model data and calculations of the shape and capacity of the embedded anchor chain suggest that there may be over–looked capacity from the mooring chain both on and within the seabed. At the same time, upscaling of embedded plates to the scale required for FLNG applications increases the amount of chain slack that would be released into the mooring during in service loading, and this effect requires consideration in the overall mooring system design. Research and development activities aligned with the opportunities for reduced cost and risk in anchoring design are set out.
Marsili, Marcelo Danemberg (Queiroz Galvão Exploraçã o e Produçã o S.A.) | de Góes Monteiro, Gabriel G. (Queiroz Galvão Exploraçã o e Produçã o S.A.) | Pedroso, Carlos Alberto (Queiroz Galvão Exploraçã o e Produçã o S.A.) | Neto, Salvador J. A. (Queiroz Galvão Exploraçã o e Produçã o S.A.) | de Almeida Ferreira, Igor (Queiroz Galvão Exploraçã o e Produçã o S.A.) | Rocha, Paulo Sérgio (Queiroz Galvão Exploraçã o e Produçã o S.A.) | Rausis, Mauro (Queiroz Galvão Exploraçã o e Produçã o S.A.) | Branco, Valter (Phase-Technologies)
Atlanta is a post-salt oil field located in the original Block BS-4 ring fence, 185 km off the city of Rio de Janeiro, in the Santos Basin, Brazil, under water depth of approximately 1550 m. However, Atlanta Field is not just another ultra-deepwater project; for its development, several other challenges shall be overcome, such as the low burial depth, its highly unconsolidated sandstone reservoir, the heavy and viscous crude flow assurance, the need for high power artificial lift pumping system, and the complex crude treatment at topsides, among others.
The field was discovered in 2001, followed by an appraisal program with a vertical well drilled yet in the same year to test the high porosity Eocenic unconsolidated sandstones and sample its heavy and viscous oil (14°API and 228 cP in reservoir conditions). In 2006, a horizontal well proposed to test the field development concept cast a shadow in the reliability of the project after facing several drilling, completion and production problems imposed by the high challenging environment. These included poor directional control leading to phase abandonment and well sidetracking, massive fluid loss, gravel packing failure, ESP operational issues, partially conclusive drill stem test (DST), and a severe damaged wellbore (skin = 40).
After considering technology improvements and revisiting development concepts, an extensive preparation and a complete assessment of past operations were performed. During 2013 and 2014 the consortium led the drilling, completion and testing of the first two horizontal producers planned for the field development. Wells were drilled with good directional control and barely any fluid loss, reproducing with great fidelity the proposed trajectory. They were both completed with sand control screens and gravel packed throughout the 800 m near horizontal (88°) section in the reservoir. A slant section of 80 m was constructed just before reaching the reservoir for electrical submersible pump (ESP) installation. The DSTs were conducted with ESP both near the reservoir and near the seabed to test the performance of different artificial lift concepts. Results confirmed the high reservoir permeability and the great performance of the drilling and completion phases, delivering the first two producers of the field with no formation damage. Productivity indexes for both wells were in the high end of the expected performance.
This paper presents a full review of the Atlanta Field, emphasizing its main challenges and how they were overcome by the successful construction and testing of the first two production wells, recovering the reliability of the project and encouraging the consortium to move on to the next phase. Also, the updated field development plan is described, highlighting the challenges to be faced during the next phase of the project.