Bringing the 1st BP Operated Subsea to Shore Gas Field into Production: Flow Assurance Lessons Learned

2009 ◽  
Author(s):  
Amrin Fadila Harun ◽  
Norris C. Watt
Keyword(s):  
Lessons Learned ◽  
Flow Assurance ◽  
Production Flow ◽  
Gas Field

Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout

2021 ◽  
Author(s):  
Vinicius Gasparetto ◽  
Thierry Hernalsteens ◽  
Joao Francisco Fleck Heck Britto ◽  
Joab Flavio Araujo Leao ◽  
Thiago Duarte Fonseca Dos Santos ◽  
...  
Keyword(s):  
Deep Water ◽  
Technology Use ◽  
Capital Expenditure ◽  
Lessons Learned ◽  
Internal Diameter ◽  
Flexible Riser ◽  
Flexible Pipe ◽  
Injection Wells ◽  
Gas Field ◽  
Field Development

Abstract Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned. This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts. The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers. Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections. As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.

Offshore Gas Field Development Strategy and Flow Assurance Prediction and Optimization in Harsh Environment

2018 ◽  
Author(s):  
Humoud Almohammad ◽  
Abdullah Al-Derbass ◽  
Abdulaziz Alsubaie ◽  
Mohammed Bumajdad ◽  
Abdulaziz Al-Khamis ◽  
...  
Keyword(s):  
Development Strategy ◽  
Harsh Environment ◽  
Flow Assurance ◽  
Gas Field ◽  
Field Development

Flow-Induced Vibration in Subsea Jumper Subject to Downstream Slug and Ocean Current

2016 ◽  
Vol 138 (2) ◽  
Author(s):  
Yaojun Lu ◽  
Chun Liang ◽  
Juan J. Manzano-Ruiz ◽  
Kalyana Janardhanan ◽  
Yeong-Yan Perng
Keyword(s):  
Modal Analysis ◽  
Dominant Role ◽  
Production Equipment ◽  
Vibration Response ◽  
Ocean Current ◽  
Flow Assurance ◽  
Production Flow ◽  
Flow Induced Vibration ◽  
Element Analysis ◽  
Internal Production

This paper presents a multiphysics approach for characterizing flow-induced vibrations (FIVs) in a subsea jumper subject to internal production flow, downstream slug, and ocean current. In the present study, the physical properties of production fluids and associated slugging behavior were characterized by pvtsim and olga programs under real subsea condition. Outcomes of the flow assurance studies were then taken as inputs of a full-scale two-way fluid–structure interaction (FSI) analysis to quantify the vibration response. To prevent onset of resonant risk, a detailed modal analysis has also be carried out to determine the modal shapes and natural frequencies. Such a multiphysics approach actually integrated the best practices currently available in flow assurance (olga and pvtsim), computational fluid dynamics (CFD), finite element analysis (FEA), and modal analysis, and hence provided a comprehensive solution to the FSI involved in a subsea jumper. The corresponding results indicate that both the internal production flow, downstream slugs, and the ocean current would induce vibration response in the subsea jumper. Compared to the vortex-induced vibration (VIV) due to the ocean current and the FIV due to the internal production flow, pressure fluctuation due to the downstream slug plays a dominant role in generating excessive vibration response and potential fatigue failure in the subsea jumper. Although the present study was mainly focused on the subsea jumper, the same approach can be applied to other subsea components, like subsea flowline, subsea riser, and other subsea production equipment.

Validation and Analysis of Past PVT Studies from a Complex and Mature Offshore Asset in Trinidad

2014 ◽  
Author(s):  
D.E.. E. Bagoo ◽  
M.L.. L. Ramnarine ◽  
C. J. Rodriguez ◽  
M.. Hernandez
Keyword(s):  
Joint Venture ◽  
Material Balance ◽  
Flow Assurance ◽  
Production Flow ◽  
Sulphur Compounds ◽  
Pvt Data ◽  
Facilities Design ◽  
Production History ◽  
Paper Form ◽  
Fluid Behaviour

Abstract In 2005, NGC, Petrotrin and Repsol E&P T&T Ltd. as joint venture partners, acquired the TSP asset with Repsol as the operator. The three fields, Teak, Samaan and Poui, have been in production for over 40 years and are highly complex, extremely compartmentalized and consist of over 10 different sands and reservoirs. Over 100 PVT files for the three fields are available; most of which were done in the 1970's by different labs using different protocols and procedures. All files were handed over in paper form which needed digitization as well as validation. Valid PVT data provides vital information for the characterization of reservoir fluids. The establishment of fluids' physical and PVT properties help determine in situ and stock tank volumes, strategies for production, flow assurance issues for facilities design and provides guidelines for effective and efficient reservoir management throughout the life of the asset. Numerous techniques exist for assessing and evaluating the quality of PVT data. This paper will describe the best practices used to validate TSP PVT data, such as the material balance tests and the Y-function linearity tests as well as the applications of the validated data through examples and case studies. Some of which include the development of trends which can be extrapolated for use in new prospects, infill and developmental drilling. Additional benefits include the recognition of flow assurance issues such as wax and sulphur compounds and the sampling and design of relevant PVT experiments for new wells. Production history combined with valid PVT data provides a powerful tool to help in the prediction of expected fluid types and fluid behaviour as pressure changes in planned new wells. It also provides additional technical support for which improvements to the fluid sampling program can be made to acquire the most representative fluid samples from the reservoir.

Flow Assurance Challenges for China’s First Deepwater Gas Field Development in South China Sea

2020 ◽  
Author(s):  
Lawrence Khin Leong Lau ◽  
Kun An ◽  
Xian Di Tang ◽  
Fei Jian Luo ◽  
Yang Yang ◽  
...  
Keyword(s):  
South China Sea ◽  
South China ◽  
Flow Assurance ◽  
Gas Field ◽  
Field Development ◽  
China Sea

DEEPWATER GAS FIELD PRODUCTION FROM SUBSEA WELLS INTO COMPRESSED NATURAL GAS CARRIERS THROUGH A HYBRID RISER TOWER

2005 ◽  
Vol 45 (1) ◽  
pp. 45
Author(s):  
J-F. Saint-Marcoux ◽  
C. White ◽  
G.O. Hovde
Keyword(s):  
Natural Gas ◽  
Eddy Currents ◽  
Gas Production ◽  
Lessons Learned ◽  
Concept Design ◽  
Vertical Load ◽  
Gas Field ◽  
Compressed Natural Gas ◽  
Field Development ◽  
Field Production

This paper addresses the feasibility of developing an ultra-deepwater gas field by producing directly from subsea wells into Compressed Natural Gas (CNG) Carrier ships. Production interruptions will be avoided as two Gas Production Storage Shuttle (GPSS) vessels storing CNG switch out roles between producing/storing via one of two Submerged Turret Production (STP) buoys and transport CNG to a remote offloading buoy. This paper considers the challenges associated with a CNG solution for an ultra-deepwater field development and the specific issues related to the risers. A Hybrid Riser Tower (HRT) concept design incorporating the lessons learned from the Girassol experience allows minimisation of the vertical load on the STP buoys. The production switchover system from one GPSS to the other is located at the top of the HRT. High-pressure flexible flowlines with buoyancy connect the flow path at the top of HRT to both STP buoys. System fabrication and installation issues, as well as specific met ocean conditions of the GOM, such as eddy currents, have been addressed. The HRT concept can be also used for tiebacks to floating LNG plants.

Effects of Economic Analysis on Re-Development of a Gas Field - Lessons Learned From a Reservoir Simulation Study

2012 ◽  
Author(s):  
Agha Hassan Akram ◽  
Arshad Majeed ◽  
Zaid Ashraf ◽  
Waqar A. Khan ◽  
Shah Abdur Rahman
Keyword(s):  
Economic Analysis ◽  
Simulation Study ◽  
Reservoir Simulation ◽  
Lessons Learned ◽  
Gas Field

scholarly journals Design of Flowline, Separator, and Slug Catcher in X Field

2018 ◽  
Vol 1 (3) ◽  
Author(s):  
I Gede Dian Aryana ◽  
Muhammad Taufiq Fathaddin ◽  
Djoko Sulistyanto
Keyword(s):  
Multiphase Flow ◽  
Oil And Gas ◽  
Slenderness Ratio ◽  
Transport Processes ◽  
Hydrodynamic Conditions ◽  
Production Flow ◽  
Gas Field ◽  
Oil And Gas Field ◽  
High Production ◽  
High Possibility

<p>The use of the pipeline is the safest method in sending oil and gas from one area to another in oil and gas transportation system. The only challenge is to keep the pressure drop in the pipeline as small as possible to avoid high pressure differences. This pressure difference can result in reduced production flow rate and affect the flow pattern in the pipeline. The condition can lead to high possibility of a slug on pipelines that drain multiphase flow. Slug becomes one of the main concerns transport processes multiphase flow in pipelines. The emergence of slug in the pipeline could cause an unstable hydrodynamic conditions will continue to affect the liquid level in the inlet separator and cause flooding in the separator. Some of the conclusions mainly on the diameter of the pipeline, the size of the slug catcher and the size of the separator obtained from the calculation based on the study of literature and simulations with software HYSIS and OLGA. Design slug catcher to accommodate the number of processes that occur in the production transportation of X oil and gas field through a pipeline 10 inches along the 12 km with 20.68 m3 volume of slug using 3 (three) finger with diameter 28 inches and length of 10 meters each. For the separation process of oil and gas in the first five (5) years of X oil and gas field  which has a high production of oil and condensate will require separator with 30 inches diameter, seam to seam height of 8.1 ft or 2.5 meters, with retention time for 2 minutes and the 3.2 slenderness ratio of the vertical separator.</p>

Sign in / Sign up

Export Citation Format

Share Document