Operator Reviews Decommissioning Options for Deepwater Flowlines and Risers

2021 ◽  
Vol 73 (05) ◽  
pp. 45-46
Author(s):  
Chris Carpenter
Keyword(s):  
Water Injection ◽  
Pipeline System ◽  
Kuala Lumpur ◽  
Mooring Lines ◽  
Offshore Technology ◽  
Statutory Requirement ◽  
Process Plant ◽  
Pipeline Systems ◽  
Flexible Risers ◽  
Operational Activities

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30397, “Deepwater Flowlines and Risers Decommissioning,” by Azam Syah Jaafar, Ahmad Taqiyuddin Obaidellah, and Khairul Anuar Karim, Petronas, prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper reviews an operator’s deepwater field project offshore Mauritania, for which several techniques were considered with respect to decommissioning a subsea pipeline system at water depths of 700 to 960 m. Options included preservation for potential future use, leaving in situ, and full recovery. The paper covers only the operator’s deepwater subsea flowline and riser decommissioning experiences and reviews activities from planning and concept to operational activities such as pigging, flushing, cleaning, disconnection, and retrieval. Case Study The operator’s deepwater field is 80 km from the Mauritanian coastline. It has been in production since 2006 but has become uneconomical. The operator decided to cease production and subsequently conducted a field abandonment and decommissioning (A&D) study. The field was developed using subsea wells, manifolds, umbilicals, flexible flowlines, and flexible risers tied back to a permanently moored floating production, storage, and offloading (FPSO) vessel at a depth of approximately 800 m. The FPSO was moored by an external turret connected to three clusters of mooring lines attached to piles in the seabed. All subsea wells were connected to the FPSO by five flexible pipeline systems (including dynamic flexible risers) and one umbilical system. All flexible pipeline systems were meant for the transportation of production fluids, water injection, gas injection, and gas-lift services. Because the FPSO is a turret-moored type, in which the turret is externally positioned at the FPSO’s bow, all flexible risers were designed to decouple the load and motion at hangoff from touch-down point with a lazy-wave configuration. The lazy-wave configuration was obtained by clamping sets of buoyancy modules on the risers. The execution of abandonment and decommissioning work has been divided into two main scopes: restoration of well integrity by installation of deep and shallow set plugs and FPSO disconnection and demobilization, which covers subsea facilities, risers, umbilical and flowline flushing and cleaning, topside process plant flushing and cleaning, pipeline systems and mooring-lines disconnection and retrieval, and FPSO sailaway. A plan for disposal of all resulting waste also was incorporated. Guidelines, Rules, and Regulations No universal statutory requirement, standard, or recommended practice existed to fully address pipeline decommissioning. Nevertheless, countries with more-established offshore industries (e.g., Norway, United Kingdom, US) have developed local legislation and practices that have been implemented in these respective jurisdictions.

Nanotechnology Helps Decrease Pressure, Increase Injection in Offshore China Oil Field

2021 ◽  
Vol 73 (09) ◽  
pp. 58-59
Author(s):  
Chris Carpenter
Keyword(s):  
Water Injection ◽  
Injection Pressure ◽  
Gas Production ◽  
Oil Field ◽  
Water Flooding ◽  
Injection System ◽  
Bohai Bay ◽  
Reservoir Properties ◽  
Positive Effects ◽  
Offshore Technology

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30407, “Case Study of Nanopolysilicon Materials’ Depressurization and Injection-Increasing Technology in Offshore Bohai Bay Oil Field KL21-1,” by Qing Feng, Nan Xiao Li, and Jun Zi Huang, China Oilfield Services, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Nanotechnology offers creative approaches to solve problems of oil and gas production that also provide potential for pressure-decreasing application in oil fields. However, at the time of writing, successful pressure-decreasing nanotechnology has rarely been reported. The complete paper reports nanopolysilicon as a new depressurization and injection-increasing agent. The stability of nanopolysilicon was studied in the presence of various ions, including sodium (Na+), calcium (Ca2+), and magnesium (Mg2+). The study found that the addition of nanomaterials can improve porosity and permeability of porous media. Introduction More than 600 water-injection wells exist in Bohai Bay, China. Offshore Field KL21-1, developed by water-flooding, is confronted with the following challenges: - Rapid increase and reduction of water-injection pressure - Weak water-injection capacity of reservoir - Decline of oil production - Poor reservoir properties - Serious hydration and expansion effects of clay minerals To overcome injection difficulties in offshore fields, conventional acidizing measures usually are taken. But, after multiple cycles of acidification, the amount of soluble substances in the rock gradually decreases and injection performance is shortened. Through injection-performance experiments, it can be determined that the biological nanopolysilicon colloid has positive effects on pressure reduction and injection increase. Fluid-seepage-resistance decreases, the injection rate increases by 40%, and injection pressure decreases by 10%. Features of Biological Nanopolysilicon Systems The biological nanopolysilicon-injection system was composed of a bioemulsifier (CDL32), a biological dispersant (DS2), and a nanopolysilicon hydrophobic system (NP12). The bacterial strain of CDL32 was used to obtain the culture colloid of biological emulsifier at 37°C for 5 days. DS2 was made from biological emulsifier CDL32 and some industrial raw materials described in Table 1 of the complete paper. Nanopolysilicon hydrophobic system NP12 was composed of silicon dioxide particles. The hydrophobic nanopolysilicons selected in this project featured particle sizes of less than 100 nm. In the original samples, a floc of nanopolysilicon was fluffy and uniform. But, when wet, nanopolysilicon will self-aggregate and its particle size increases greatly. At the same time, nanopolysilicon features significant agglomeration in water. Because of its high interface energy, nanopolysilicon is easily agglomerated, as shown in Fig. 1.

scholarly journals Experimental and Numerical Vibration Analysis of Hydraulic Pipeline System under Multiexcitations

2020 ◽  
Vol 2020 ◽  
pp. 1-13
Author(s):  
Peixin Gao ◽  
Hongquan Qu ◽  
Yuanlin Zhang ◽  
Tao Yu ◽  
Jingyu Zhai
Keyword(s):  
Pressure Fluctuations ◽  
Fluid Motion ◽  
Fluid Pressure ◽  
Point Of View ◽  
Pipeline System ◽  
Base Excitation ◽  
Fem Method ◽  
Pipeline Systems ◽  
Pump Pressure ◽  
Improved Model

Pipeline systems in aircraft are subjected to both hydraulic pump pressure fluctuations and base excitation from the engine. This can cause fatigue failures due to excessive vibrations. Therefore, it is essential to investigate the vibration behavior of the pipeline system under multiexcitations. In this paper, experiments have been conducted to describe the hydraulic pipeline systems, in which fluid pressure excitation in pipeline is driven by the throttle valve, and the base excitation is produced by the shaker driven by a vibration controller. An improved model which includes fluid motion and base excitation is proposed. A numerical MOC-FEM approach which combined the coupling method of characteristics (MOC) and finite element method (FEM) is proposed to solve the equations. The results show that the current MOC-FEM method could predict the vibration characteristics of the pipeline with sufficient accuracy. Moreover, the pipeline under multiexcitations could produce an interesting beat phenomenon, and this dangerous phenomenon is investigated for its consequences from engineering point of view.

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 111-116 ◽  
Author(s):  
D. M. Stewart ◽  
A. J. G. Faulkner
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Maximum Flow ◽  
Oil Field ◽  
Injection Wells ◽  
Initial Development ◽  
Flexible Risers ◽  
Northern North Sea ◽  
The Uk ◽  
Gas Lift

AbstractThe Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

scholarly journals Hydraulic Engineering at 100 BC-AD 300 Nabataean Petra (Jordan)

Water ◽  
2020 ◽  
Vol 12 (12) ◽  
pp. 3498
Author(s):  
Charles R. Ortloff
Keyword(s):  
Water Supply ◽  
Flow Rate ◽  
Distribution Systems ◽  
Maximum Flow ◽  
Hydraulic Engineering ◽  
World Heritage Site ◽  
Maximum Flow Rate ◽  
Pipeline System ◽  
Supply And Distribution ◽  
Pipeline Systems

The principal water supply and distribution systems of the World Heritage site of Petra in Jordan were analyzed to bring forward water engineering details not previously known in the archaeological literature. The three main water supply pipeline systems sourced by springs and reservoirs (the Siq, Ain Braq, and Wadi Mataha pipeline systems) were analyzed for their different pipeline design philosophies that reflect different geophysical landscape challenges to provide water supplies to different parts of urban Petra. The Siq pipeline system’s unique technical design reflects use of partial flow in consecutives sections of the main pipeline to support partial critical flow in each section that reduce pipeline leakage and produce the maximum flow rate the Siq pipeline can transport. An Ain Braq pipeline branch demonstrated a new hydraulic engineering discovery not previously reported in the literature in the form of an offshoot pipeline segment leading to a water collection basin adjacent to and connected to the main water supply line. This design eliminates upstream water surges arising from downstream flow instabilities in the two steep pipelines leading to a residential sector of Petra. The Wadi Mataha pipeline system is constructed at the critical angle to support the maximum flow rate from a reservoir. The analyses presented for these water supply and distribution systems brought forward aspects of the Petra urban water supply system not previously known, revising our understanding of Nabataean water engineers’ engineering knowledge.

Designing Offshore Pipeline Safety Systems Utilising Flow and Pressure in Multi Design Pressure Pipeline Systems

2008 ◽  
Author(s):  
Gjertrud Elisabeth Hausken ◽  
Jo̸rn-Yngve Stokke ◽  
Steinar Berland
Keyword(s):  
Pressure Drop ◽  
Flow Measurement ◽  
Large Diameter ◽  
Pressure Sensors ◽  
Safety System ◽  
Pipeline System ◽  
Outlet Pressure ◽  
Pipeline Systems ◽  
Pipeline Safety ◽  
Design Pressure

The Norwegian Continental Shelf (NCS) has been a main arena for development of subsea pipeline technology over the last 25 years. The pipeline infrastructure in the North Sea is well developed and new field developments are often tied in to existing pipeline systems, /3/. Codes traditionally require a pipeline system to be designed with a uniform design pressure. However, due to the pressure drop when transporting gas in a very long pipeline, it is possible to operate multi design pressure systems. The pipeline integrity is ensured by limiting the inventory and local maximum allowable pressure in the pipeline using inlet and outlet pressure measurements in a Safety Instrumented System (SIS). Any blockage in the pipeline could represent a demand on the safety system. This concept was planned to be used in the new Gjo̸a development when connecting the 130 km long rich gas pipeline to the existing 450 km long FLAGS pipeline system. However, a risk assessment detected a new risk parameter; the formation of a hydrate and subsequent blockage of the pipeline. In theory, the hydrate could form in any part of the pipeline. Therefore, the pipeline outlet pressure could not be used in a Safety Instrumented System to control pipeline inventory. The export pressure at Gjo̸a would therefore be limited to FLAGS pipeline code. Available pressure drop over the Gjo̸a pipeline was hence limited and a large diameter was necessary. Various alternatives were investigated; using signals from neighbour installations, subsea remote operated valves, subsea pressure sensors and even a riser platform. These solutions gave high risk, reduced availability, high operating and/or capital expenses. A new idea of introducing flow measurement in the SIS was proposed. Hydraulic simulations showed that when the parameters of flow, temperature and pressure, all located at the offshore installation, were used; a downstream blockage could be detected early. This enabled the topside export pressure to be increased, and thereby reduced the pipeline diameter required. Flow measurement in Safety Instrumented Systems has not been used previously on the NCS. This paper describes the principles of designing a pipeline safety system including flow measurement with focus on the hydraulic simulations and designing the safety system. Emphasis will be put on improvements in transportation efficiency, cost reductions and operational issues.

Seismic Vulnerability Assessment and Retrofit of a Major Natural Gas Pipeline System: A Case History

2005 ◽  
Vol 21 (2) ◽  
pp. 539-567 ◽  
Author(s):  
Dharma Wijewickreme ◽  
Douglas Honegger ◽  
Allen Mitchell ◽  
Trevor Fitzell
Keyword(s):  
Natural Gas ◽  
Vulnerability Assessment ◽  
Seismic Vulnerability ◽  
Ground Improvement ◽  
Lateral Spreading ◽  
Gas Pipeline ◽  
Pipeline System ◽  
Seismic Vulnerability Assessment ◽  
Natural Gas Pipeline ◽  
Pipeline Systems

The performance of pipeline systems during earthquakes is a critical consideration in seismically active areas. Unique approaches to quantitative estimation of regional seismic vulnerability were developed for a seismic vulnerability assessment and upgrading program of a 500-km-long natural gas pipeline system in British Columbia, Canada. Liquefaction-induced lateral spreading was characterized in a probabilistic manner and generic pipeline configurations were modeled using finite elements. These approaches, developed during the early part of this 10-year program, are more robust than typical approaches currently used to assess energy pipeline systems. The methodology deployed within a GIS environment provided rational means of distinguishing between seismically vulnerable sites, and facilitated the prioritization of remedial works. While ground improvement or pipeline retrofit measures were appropriate for upgrading most of the vulnerable sites, replacement of pipeline segments using horizontal directional drilling to avoid liquefiable zones were required for others.

Overpressure Protections in Liquid Pipeline Hydraulic Design

2016 ◽  
Author(s):  
Alan X. L. Zhou ◽  
David Yu ◽  
Victor Cabrejo
Keyword(s):  
New Technologies ◽  
Pressure Control ◽  
Petroleum Products ◽  
Integrated System ◽  
Operating Conditions ◽  
Design Stage ◽  
Pipeline System ◽  
Protection Measures ◽  
Pipeline Systems ◽  
Pipeline Design

Continuous economic development demands safe and efficient means of transporting large quantities of crude oil and other hydrocarbon products over vast extensions of land. Such transportation provides critical links between organizations and companies, permitting goods to flow between their facilities. Operation safety is paramount in transporting petroleum products in the pipeline industry. Safety can affect the performance and economics of pipeline system. Pipeline design codes also evolve as new technologies become available and management principles and practices improve. While effective operation safety requires well-trained operators, adequate operational procedures and compliance with regulatory requirements, the best way to ensure process safety is to implement safety systems during the design stage of pipeline system. Pressure controls and overpressure protection measures are important components of a modern pipeline system. This system is intended to provide reliable control and prevent catastrophic failure of the transport system due to overpressure conditions that can occur under abnormal operating conditions. This paper discusses common pressure surge events, options of overpressure protection strategies in pipeline design and ideas on transient hydraulic analyses for pipeline systems. Different overpressure protection techniques considered herein are based on pressure relief, pressure control systems, equipment operation characteristics, and integrated system wide approach outlining complete pressure control and overpressure protection architecture for pipeline systems. Although the analyses presented in this paper are applicable across a broad range of operating conditions and different pipeline system designs, it is not possible to cover all situations and different pipeline systems have their own unique solutions. As such, sound engineering judgment and engineering principles should always be applied in any engineering design.

Interaction Between Flexible Risers and Mooring Lines within a Floating Production System

1990 ◽  
Author(s):  
Paul Anthony Brown ◽  
Ian Larsen ◽  
Ramesh Chandwani ◽  
Evandro Rossi Dasambiagio
Keyword(s):  
Production System ◽  
Mooring Lines ◽  
Flexible Risers

Designing Offshore Pipeline Systems Divided Into Sections of Different Design Pressures

2004 ◽  
Author(s):  
Gunnar Staurland ◽  
Morten Aamodt
Keyword(s):  
Uniform Design ◽  
External Pressure ◽  
Transportation Systems ◽  
Point Of View ◽  
Pipeline System ◽  
Operating Pressure ◽  
Pipeline Systems ◽  
Upstream Pressure ◽  
Transmission Pipeline ◽  
Design Pressure

Norwegian waters have been a main arena for development of subsea pipeline technology over the last 25 year. The gas transportation systems from Norway to continental Europe comprise the largest and longest sub sea pipelines in the world. Codes traditionally require a pipeline to be designed with a uniform design pressure between stations with overpressure protection capabilities. However, the downstream part of a very long gas transmission pipeline may, after commissioning, rarely, if ever, see pressures near the pressure at the upstream end. There is, therefore, a potential for cost reduction and capacity improvement if two, or several, sections of different design pressure could be used without having to implement sub sea pressure regulation and overpressure protection facilities at the point of transition between the different sections of design pressure. In determining the lower design pressure the shutdown of the pipeline outlet facilities, at any point in time allowing for a practicable, achievable delay for closure of the upstream inlet valve has to be taken into account. The settle out pressure in a “normal” shut-in situation shall then not exceed the lower design pressure. In addition, deep water pipelines are often designed to withstand buckling due to bending and external pressure during installation, and may therefore locally tolerate a much higher internal pressure than the pipeline was designed for. Transmission pipelines crossing deepwater areas may therefore be designed for two or more operating pressures along the pipeline, thereby optimizing the cost. Even more important, for already existing pipelines, the capacity may be significantly increased by utilizing the upstream heavy wall sections. The operating pressure range for a long offshore gas transmission pipeline is very wide compared to an onshore line, typically between an upstream pressure of 150–250 bar, and a downstream pressure of 60 to 80 bar over a distance of several hundred kilometers. It may take hours to notice the closure of a downstream valve on the upstream pressure. Unless the pipeline is extensively packed, it is obvious that the pressure drop along the pipeline may be taken into account by allowing a lower design pressure for downstream part than for the upstream part. Thereby, the investment cost can be reduced. This paper describes the principles of designing a pipeline system divided into sections of different design pressures from a hydraulic point of view. The basis is the offshore standard for designing submarine pipeline systems, DNV OS-F101. The focusing will be on improvements in transportation efficiency, cost reductions and operational issues.

Measuring the Effectiveness of Damage Prevention Techniques and Defining the Key Performance Indicators on Damage Prevention Efficiency

2012 ◽  
Author(s):  
Mark Piazza ◽  
Gina Greenslate ◽  
Nicolas Herchin ◽  
Laurent Bourgouin ◽  
Miriam Kuhn ◽  
...  
Keyword(s):  
Performance Indicators ◽  
Public Awareness ◽  
Prevention Programs ◽  
Key Performance Indicators ◽  
Pipeline System ◽  
Energy Transmission ◽  
Geographic Population ◽  
Pipeline Systems ◽  
Transmission Pipeline ◽  
Damage Prevention

Pipeline operators expend substantial efforts to develop, implement, and audit their Public Awareness and Pipeline Damage Prevention Programs. While the rate of pipeline damage incidents from third-party and outside force impacts has progressively declined over a period of several decades, these events remain a high priority for the pipeline industry and external stakeholders. There are multiple management and communications tools that are used to support Damage Prevention programs for energy transmission pipeline operations. These tools are applied to large pipeline systems that cross a range of geographic, population, and regulatory boundaries. These factors make it challenging to determine the effectiveness of the individual tools applied for damage prevention for energy transmission pipeline systems. This paper present the results of research performed through Pipeline Research Council International, Inc. (PRCI) to measure and quantify the effectiveness of the various damage prevention tools and techniques as they apply to energy transmission pipeline systems. The project focuses on data collection through a web-based platform to provide the basis to establish a set of Key Performance Indicators (KPIs) for assessing the effectiveness of the methods and techniques that are used as standard practices by most pipeline operators in their damage prevention programs. The research includes development of a consistent and systematic process and database for collecting information on damage and “near hit” incidents that are recorded by pipeline operators. Fault-tree analysis of these data is expected to show where improvements can be made (e.g., one-call center, ticket handling, operator response, contractor cooperation and diligence, locating and marking, monitoring). Improvements will be measured by PRCI by capturing and analyzing the data over a multi-year period. The key output of the project will be metrics that demonstrate which damage prevention activities are more effective in reducing impacts and “near hits” to pipelines and which activities positively contribute to the safe operations of the pipeline system.

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