FPU Mooring Footprint Reduction in Buzios Field: Key Driver to its Successful Subsea Layout

2021 ◽  
Author(s):  
Gabriel Rodrigues Cabral ◽  
Helvio Ferreira da Silva ◽  
Anderson Takehiro Oshiro ◽  
Leandro Cerqueira Trovoado ◽  
Thierry Hernalsteens ◽  
...  
Keyword(s):  
Production Systems ◽  
Economic Feasibility ◽  
Horizontal Projection ◽  
Mooring Lines ◽  
Large Reservoir ◽  
Field Development ◽  
Well Design ◽  
Production Wells ◽  
High Production ◽  
Flexible Risers

Abstract Buzios field development has the potential to implement several production systems due to large reservoir volumes. Considering the oil specification, the drive to use standard solutions already in place in Pre-salt area, associated with the high production indexes of the wells, Petrobras decided to tie back all production wells in satellite configuration. These facts, together with geological hazards in the area, lead to a potentially congested seabed scenario. Hence, FPU positioning has been challenging and demanding innovative engineering solutions to optimize FPU mooring as to overcome these challenges and enable FPU positioning close to wells. This optimization gave birth to new issues, such as risk of clashing between mooring lines and lazy-wave flexible risers. Integrated riser and mooring lines dynamic analysis, together with subsea layout assessment were performed to ensure technical and economic feasibility. Furthermore, due to the Buzios reservoir, well design requirements and subsea layout specificities, all FPU were located on the edge of the reservoir and flexible risers were tied back mainly from only one board of each FPU. Hence, enhancing clearance between bow and stern mooring clusters and the optimization of the risers’ configuration were of paramount importance for enabling most of the risers’ connections on the desirable board. FPU mooring optimization led to up to 30% of mooring lines’ radius reduction (horizontal projection), and an average of up to 500m per flowline reduction, saving CAPEX, OPEX and increasing the return on investment.

Riser Top Loads on Turret Moored FPSO

2009 ◽  
Author(s):  
Felipe de Arau´jo Castro ◽  
Carlos Magluta ◽  
Gilberto Bruno Ellwanger
Keyword(s):  
Production Systems ◽  
Wind Waves ◽  
Model Tests ◽  
Structural Damping ◽  
Mooring Lines ◽  
Load Variations ◽  
Campos Basin ◽  
Loading Case ◽  
Flexible Risers ◽  
Important Design

In the Campos Basin, offshore Brazil, catenary flexible risers are extensively used in marine production systems. One of the most important design phases of these systems is the riser extreme top load analysis, which provides results for riser and accessory designs as well as input for structural analysis of platform supports. In addition to the riser’s characteristics (weight, diameter, structural damping, axial and bending stiffness), riser top loads depend on several other factors, such as platform static and dynamic behavior, including the collective effect of lines (mooring lines and risers) drag and damping, platform motion, connection support position and environmental loading cases. This study is based on the results from a model test and numerical analysis of a typical turret moored FPSO system, with catenary risers and mooring lines. This test was programmed to evaluate the consequence of each of the above mentioned parameters on flexible riser top loads. Model tests were performed in the MARIM (Maritime research Institute Netherlands) wave tank to represent the offshore system in 850 meter water depth and included loading case tests combining wind, waves and current in different relative directions (collinear, crossed and transversal). The analysis of the model tests results indicated significant variations in the platform behavior, when the drag and damping generated by the risers and mooring lines were taken into account. Additional analyses were performed, based on numerical simulations of the top load variations (axial, shear tension and moment), induced by movement changes (added drag and damping caused by risers and mooring lines) and to evaluate the influence of vessel heading on top load results.

Prospects for the development of agrarian production systems in in the Right Bank Polesie of Ukraine

2018 ◽  
Vol 2 (95) ◽  
pp. 69-72
Author(s):  
Yu.A. Tarariko ◽  
L.V. Datsko ◽  
M.O. Datsko
Keyword(s):  
Agricultural Production ◽  
Production Systems ◽  
Economic Feasibility ◽  
Capital Investments ◽  
Resource Potential ◽  
Grain Processing ◽  
Processing And Storage ◽  
The Right ◽  
And Storage ◽  
Agricultural Production Systems

The aim of the work is to assess the existing and prospective models for the development of agricultural production in Central Polesie on the basis of economic feasibility and ecological balance. The evaluation of promising agricultural production systems was carried out with the help of simulation modeling of various infrastructure options at the levels of crop and multisectoral specialization of agroecosystems. The agro-resource potential of Central Polesie is better implemented in the rotation with lupine, corn and flax dolguntsem with well-developed infrastructure, including crop, livestock units, grain processing and storage systems, feed, finished products and waste processing in the bioenergetic station. The expected income for the formation of such an infrastructure is almost 8 thousand dollars. / with a payback period of capital investments of 2-3 years.

Blockage Remediation in Deep Water Pipelines

2002 ◽  
Author(s):  
Ca´ssio Kuchpil ◽  
Marcelo A. L. Gonc¸alves ◽  
Antoˆnio C. P. Ferreira ◽  
Roberto S. Albernaz ◽  
Cla´udio S. Camerini ◽  
...  
Keyword(s):  
Low Temperatures ◽  
Production Systems ◽  
Operational Conditions ◽  
Deep Waters ◽  
Water Pipelines ◽  
Pros And Cons ◽  
High Production ◽  
Organic Deposit ◽  
Production Losses ◽  
Exothermal Chemical

Flow assurance is an important issue in the design and operation of production systems in deep waters. The implementation of prevention and remediation methods is necessary mainly due to the low temperatures, high production pressures, long tie-ins and oils prone to organic deposit formation. Despite the development and improvement of these prevention and remediation techniques, failures or exceptional operational conditions can lead to the complete blockage of the submarine flowlines, risers or equipment. Although the complete blockage is not frequent, the related production losses generally are high; furthermore, the technical difficulties and the costs involved in the removal of blockages can be high. The steps to the remediation of subsea blockages are the localization, identification and removal methods. Due to the variety of problems, the different subsea layouts and surface facilities, it is not possible to have a general recipe for all problems. This paper presents some blockage remediation cases, including the localization and blockage remediation methods. The blockage localization methods used for the blockage removal cases described in this paper are the following: a) the echo of pressure pulses reflected at the blockage and b) a tool that detects the pipeline diameter variation with the pipeline pressure variations. The field results for these methods and the pros and cons of the methods are discussed. The remediation methods described are the following: external heating, internal intervention and exothermal chemical reaction using gravity.

Development of efficiency increase methods for water injection

2020 ◽  
pp. 57-60
Author(s):  
K.I. Mustafaev ◽  
◽  
◽  
Keyword(s):  
Water Injection ◽  
Cost Effective ◽  
Current Interest ◽  
Residual Oil ◽  
Production Well ◽  
Field Development ◽  
Oil Reserves ◽  
Production Wells ◽  
Efficiency Increase

The production of residual oil reserves in the fields being in a long-term exploitation is of current interest. The extraction of residual oil in such fields was cost-effective and simple technological process and is always hot topic for researchers. Oil wells become flooded in the course of time. The appearance of water shows in production wells in the field development and operation is basically negative occurrence and requires severe control. Namely for this reason, the studies were oriented, foremost, to the prevention of water shows in production well and the elimination of its complications as well. The paper discusses the ways of reflux efficiency increase during long-term exploitation and at the final stages of development to prevent the irrigation and water use in production wells.

scholarly journals Gas Injection Optimization to Increase Oil Production at MRA PT. PHE ONWJ

2021 ◽  
Vol 2 (2) ◽  
pp. 75
Author(s):  
Harry Budiharjo Sulistyarso ◽  
KRT Nur Suhascaryo ◽  
Mochamad Jalal Abdul Goni
Keyword(s):  
Gas Injection ◽  
Economic Feasibility ◽  
Feasibility Analysis ◽  
Offshore Platforms ◽  
Total Production ◽  
The North ◽  
Artificial Lift ◽  
Production Wells ◽  
Java Sea ◽  
Gas Lift

The MRA platform is one of the offshore platforms located in the north of the Java Sea. The MRA platform has 4 production wells, namely MRA-2ST, MRA-4ST, MRA-5, and MRA-6 wells. The 4 production wells are produced using an artificial lift in the form of a gas lift. The limited gas lift at the MRA Platform at 3.1 MMSCFD makes the production of wells at the MRA Platform not optimal because the wells in the MRA Platform are experiencing insufficient gas lift. Optimization of gas lift injection is obtained by redistribution of gas lift injection for each. The results of the analysis in this study indicate that the optimum gas lift injection for the MRA-2ST well is 0.5552 MMSCFD, the MRA-6 well is 1.0445 MMSCFD, the MRA-5 well is 0.7657 MMSCFD, finally the MRA-4ST well with gas injection. lift is 0.7346 MMSCFD. The manual gas lift in the MRA-4ST is also replaced based on an economic feasibility analysis to ensure that the gas lift injection for each well can be kept constant. The redistribution of gas lift carried out by the author has increased the total production rate of the MRA Platform by 11,160 BO/year or approximately USD 781,200/year. Keywords: Gas lift; Insufficient; Optimization

scholarly journals A practical method for planning large number of horizontal wells with a reservoir model for a field development plan

2021 ◽  
Vol 10 ◽  
pp. 17-32
Author(s):  
Guido Fava ◽  
Việt Anh Đinh
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Simulation Software ◽  
Production Performance ◽  
Development Plan ◽  
Regular Pattern ◽  
Production Forecast ◽  
Advanced Technique ◽  
Large Reservoir ◽  
Field Development

The most advanced technique to evaluate different solutions proposed for a field development plan consists of building a numerical model to simulate the production performance of each alternative. Fields covering hundreds of square kilometres frequently require a large number of wells. There are studies and software concerning optimal planning of vertical wells for the development of a field. However, only few studies cover planning of a large number of horizontal wells seeking full population on a regular pattern. One of the criteria for horizontal well planning is selecting the well positions that have the best reservoir properties and certain standoffs from oil/water contact. The wells are then ranked according to their performances. Other criteria include the geometry and spacing of the wells. Placing hundreds of well individually according to these criteria is highly time consuming and can become impossible under time restraints. A method for planning a large number of horizontal wells in a regular pattern in a simulation model significantly reduces the time required for a reservoir production forecast using simulation software. The proposed method is implemented by a computer script and takes into account not only the aforementioned criteria, but also new well requirements concerning existing wells, development area boundaries, and reservoir geological structure features. Some of the conclusions drawn from a study on this method are (1) the new method saves a significant amount of working hours and avoids human errors, especially when many development scenarios need to be considered; (2) a large reservoir with hundreds of wells may have infinite possible solutions, and this approach has the aim of giving the most significant one; and (3) a horizontal well planning module would be a useful tool for commercial simulation software to ease engineers' tasks.

Feasibility Study on the Implementation of CO2-EOR Coupled with Sequestration in Trinidad via Reservoir Simulation

2014 ◽  
Author(s):  
J.. Narinesingh ◽  
D. V. Boodlal ◽  
D.. Alexander
Keyword(s):  
Primary Production ◽  
Oil Recovery ◽  
Net Present Value ◽  
Fluid Model ◽  
Gas Production ◽  
Economic Feasibility ◽  
Utilization Rate ◽  
Optimum Number ◽  
Field Development ◽  
Co2 Eor

Abstract The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad. A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined. Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified. Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied. The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months. For CO2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.

Recommendations for the multilateral wells design selection in various geological conditions based on lessons learned

2021 ◽  
pp. 159-167
Author(s):  
A. A. Zernin ◽  
E. S. Ziuzev ◽  
A. S. Sergeev ◽  
R. M. Khismatullin ◽  
M. A. Starikov
Keyword(s):  
Lessons Learned ◽  
Energy Conditions ◽  
Reservoir Properties ◽  
Field Development ◽  
Well Design ◽  
Well Efficiency ◽  
Geological Conditions ◽  
Efficiency Estimation ◽  
Design Selection ◽  
First Time

The authors of the article have summarized the experience of multilateral well application, performed an efficiency analysis of multilateral wells vs horizontal wells in Rosneft Oil Company's fields with various subsurface architecture. The algorithm for multilateral well efficiency estimation, compared to other type of well completions, was developed. This algorithm is based on the selection of areas for well locations with similar reservoir properties, reservoir energy conditions, and reservoir development conditions to evaluate production startup parameters, decline rates, cumulative parameters for the areas of over 6 month production. A matrix of multilateral well applicability in various geological conditions was generated, and recommendations for preferable well design were made. This type of analysis was conducted for the first time due to collection of sufficient statistical data, because of a multiple increase in the amount of drilling complex wells in the recent years. The obtained results provide an opportunity to design an efficient field development system for new assets, perform an adjustment of brownfields development systems, select multilateral well design for certain geological conditions based on lessons learned.

Buzios FPSO Experience: Standardization and Perspectives for Our Next Generation of Pre-Salt FPSOs

2021 ◽  
Author(s):  
Mattoso Marcio de Padua ◽  
Pimenta Maiza Goulart
Keyword(s):  
Production Systems ◽  
Digital Transformation ◽  
Complete Analysis ◽  
Next Generation ◽  
Business Decisions ◽  
H2s Removal ◽  
Standard Design ◽  
Production Wells ◽  
Removal Technology ◽  
Startup Period

Abstract The purpose of this article is to present a set of experiences and challenges related to the current Buzios FPSOs and the perspectives offered by these related experiences, which should drive further enhancements for next generations of pre-salt production units. Buzios field is a giant oil discovery located at Brazilian southeast coast and has four production systems already in operation: P-74, P-75, P-76 and P-77. Throughout these projects, Petrobras observed technical and business opportunities that are going to lead improvements for next generation of Buzios field's FPSOs. These include enhancements on high production wells, H2S removal technology, vessel standardization, digital transformation solutions, design procedures improvements and several measures to strength the integration between design, construction, commissioning and operation phases. During the construction, commissioning and startup period of the Buzios’ current installed units, Petrobras identified technical issues that should be addressed in order to add value to the next generation of Buzios’ FPSOs. These experiences point out to the need of technical design improvements and reviews such as: change in technology of H2S removal from solid bed to membranes; a complete analysis of hull capacities and dimensions and standardization of the vessel; and a set of standardization methods and processes to develop the basic design - including aspects of digital transformation. The result was a standard design project called Reference Project ("Projeto de Referência" in Portuguese) that intends to be a reference for new units to be installed in Buzios field. This design also intends to be the basis to other projects in order to allow faster business decisions.

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