T.D. Williamson's SmartPlug isolates pressure in specific sections of pipelines and risers so that repairs or interventions can be carried out safely. Operated by remote control, the tool is certified "safety class high" in accordance with OS-F101 for submarine pipeline systems, the company said. It is certified and type approved by Det Norske Veritas to execute independent double-block isolation to provide a safe environment for divers while working near a pressurized gas pipeline.
A survey of pipeline industry publications generated a database of over 80 collapse tests of cold-expanded line pipe. The data are compared to casing collapse ratings per
Further investigation revealed that, for two operators, the vast majority of offshore surface casing is line pipe that has been cold-expanded without stress relief. Several risk mitigation alternatives were considered. In the short term, the risk can be managed through learning bulletins, design guidelines and operational procedures. The preferred mitigation is to change the collapse rating for cold-expanded line pipe used as casing. This is a long-term solution involving industry standards and the subsequent adoption through commercial design software.
The work described in this paper has led to a ballot change for the next edition of API TR 5C3. This paper is presented to provide drilling industry awareness of the lower collapse performance of cold-expanded line pipe and to add context for selection of an appropriate alternative rating.
In 2016 BP adopted a technology plan to investigate how efficiencies could be realized in the inspection area. The project termed UWIP (Under Water Inspection Program) was divided into two areas: Alternative inspection technology, Advanced inspection technology.
Alternative Inspection technology addresses the configuration of existing technology to deliver efficiencies
Advanced Inspection technology looks to near future opportunities that may be realized within a 5-year period.
This presentation primarily addresses the Alternative agenda, with focus on how the configuring of sensor packages onboard a variety of underwater vehicles has delivered data up to 8 times faster than traditional inspection methodologies. Termed FDII (Fast Digital Imaging Inspection) the concept aims to replace video with Laser / Stills and contact Cathodic Potential systems with Field Gradient.
The Advanced agenda presents BP progress in delivering unmanned, automated Unmanned Surface and Underwater Vehicle Systems into Inspection programs.
BP has undertaken three FDII campaigns, 2017/18 in North Sea and 2018 Trinidad, inspecting 825 pipeline kilometers. There are another two FDII programs scheduled in North Sea and Caspian regions in 2019. Data acquisition has significantly increased; however, data management techniques have had to be reviewed and adapted. Inspection and integrity contractors expect to receive data in traditional formats and their systems (as well as operators) are not configured to receive and interpret the new FDII data. Additionally, software houses are also behind the curve in allowing users to host and deliver to stakeholders.
FDII facilitates rapid data acquisition and operational teams are ready to grab credit for efficient execution. But data bottlenecks in editing, eventing and delivering data to stakeholders have removed some of the ‘shine’ from the project. For FDII to develop a step change is required in the data management.
FDII is a technique, it is not an inspection criterion. FDII lends itself to Fast ROV and AUV underwater vehicle developments which are also linked to operation from Unmanned Surface Vessels. BP has a stated goal that by 2025 all inspections will performed from unmanned systems. FDII is a technology that progresses us to that goal.
In the upstream production systems, the external corrosion management typically does not affect the definition of the whole gathering network system design. However, its role is crucial for the integrity of any steel structure.
The external corrosion is generally managed with external coatings or cathodic protection systems designed to provide a durable protection against corrosive environments (either onshore or offshore). Typical external coating materials are polypropylene, polyethylene (in case of polyolefin coating), fusion bounded epoxy (FBE) or, in specific applications, thermal sprayed aluminium (TSA).
In High Pressure and High Temperature (HP/HT) reservoir applications, usually located in deepwaters offshore where the ambient temperatures are low (i.e. high temperature gradient between inside the pipelines and external environment), the selection of a specific external coating material might have significant impact on the design specification of the installed hardware, with special focus on the pipelines. In fact, depending on different physical properties of the external coating technologies, those may introduce stronger or weaker insulating capabilities and will modify the pipelines U Value, which describes the capacity of the pipelines to exchange heat with the external environment (and consequently the design specification of the production network).
A Case Study is here presented where impacts on the pipeline design specifications based on the selection of different external coating technologies have been described. In particular, it is here shown how the application of coating materials with lower insulating performance, e.g FBE coating, can increase the heat exchange between the hot production fluid and the cold external environment, leading to faster cooldown of production fluid.
In this case, reduction in operating fluid temperature has been used to prevent internal corrosion issues (generally linked to top of the line corrosion), however it may also be used as mitigation of HP/HT related issues, e.g. lateral buckling. Main pros and cons of FBE applied as a standalone external anticorrosion coating have been described in this paper.
Shell in the UK has a vast network of more than 200 pipelines & umbilicals covering some 3000 kilometres. Historically, Shell has executed Side Scan Sonar Surveys along these pipelines using a Remotely Operated Towed Vehicle and subsequently followed up with ROV based surveys & inspections. However, in 2018, the respective Geomatics & Subsea Maintenance / Pipelines Departments decided to take advantage of new & emerging innovative technologies and compiled a minimal technical scope & tender document to tap into the latest that the market could offer. Consequently, Shell UK awarded DeepOcean (Norway) with a contract for their "Fast Digital Imaging Service" and embarked on a 45 day survey campaign. In 2019, the same subsea inspection project will be executed once again and the lessons learned ought to inspire and excite many different disciplines and communities, both internally within Shell and externally e.g OGA - Oil & Gas Authority & other valued stakeholders. The paper highlights the key technologies that were deployed and how the new deliverables & business insights take us down the road to Digitalisation including scope for future Machine Learning & Automation processes. Challenges arising from the acquisition and managing the associated data sets shall also be discussed. The speaker will spark dialogue at the end by asking the respective communities how robotics and artificial intelligence will change the industry landscape?
Subsea pipeline decommissioning for either abandonment or retrieval is hazardous for both divers and the marine environment. This presentation reports on the development of a Fast Intervention Tool (FIT) for pipeline decommissioning by Webtool with input from Chevron Energy Technology Company. The FIT reduces the risks to divers and enables a quicker operation while avoiding the need for a containment dome during pipeline cutting and retrieval.
Sophisticated measures are taken to reduce the hazards to divers and the impact on the marine environment during pipeline decommissioning. Yet, traditional cutting technologies can undermine these best intentions. Diamond wire or other types of saw are time consuming and prone to jamming as the pipe moves during the cut. The containment dome used to catch contaminants that leach out during cutting and retrieval cannot "follow" the pipe as it is retrieved via a crane, therefore additional measures are needed to plug or seal to the pipe end before retrieval. The Fast Intervention Tool presented here addresses these shortcomings.
The FIT combines lifting, crimping, injection and cutting in a single deployment frame which also contains the hydraulic control system. Deployed using a barge crane, the FIT assembly is lowered over a pipeline on the seabed, with either a diver or ROV to position it. The FIT cycle time to lift, crimp, inject sealant and cut is under 1 hour (excluding vessel or set up time) after which the pipe can now be safely recovered topside without leakage. The spike injector and blades will perform a number of cycles, therefore running costs are low; the only major consumable cost is the sealant itself. Webtool has completed FIT conceptual design and in-house development and testing and is now preparing a working prototype for hyperbaric and sea trials.
Safer and more environmentally friendly method of pipeline decommissioning.
The UK and the international community have an increasing interest in the benefits of a hydrogen-based economy. Existing and emerging technologies that are inherently carbon-neutral and potentially carbon-negative are increasingly attractive, given the challenge of meeting climate targets to prevent climate change and build a clean growth strategy. The integration of clean energy technologies across the UK Continental Shelf (UKCS) can increase the flexibility of the energy system, driving efficiency, cost reduction and enhancing the value of natural resources.
There are over 250 platforms and 45,000 kilometres of pipeline installed within the United Kingdom Continental Shelf (UKCS). As these assets near the end of their economic life oil and gas operators are planning to decommission these facilities in an efficient and cost-effective manner. Current cost forecasts for this activity exceed £58bn with approximately 50% borne by the operators and 50% borne by UK taxpayers.
The Hydrogen Offshore Production (HOP) project identifies an alternative to decommissioning by providing re-use options for offshore infrastructure while addressing the national challenge of a low carbon energy supply. In doing so, the project will prove the feasibility of several decentralised hydrogen generation, storage and distribution options that collectively provide a scalable offshore hydrogen production solution, whilst offsetting a portion of decommissioning costs that are currently forecast for all offshore assets and infrastructure.
HOP will tackle the challenge of bulk hydrogen production by (1) proposing viable environmental and economic technology solutions to be deployed offshore, (2) developing a new Industrial Hydrogen Production test site to both prove the industrial benefits and to aid commercialisation of emerging technology and, (3) conducting market analysis and producing the business case for the transformation of existing offshore infrastructure, re-purposing assets and demonstrating the viability for decentralised generation of hydrogen.
As part of the project, an Industrial Hydrogen Production test site will be established with Flotta (Orkney Islands) being proposed as the location. This will provide a test bed for technology, fast-tracking its development and providing a route for accelerated commercial deployment. Within a region of considerable renewable energy generation, the island of Flotta is ideally placed to benefit from local expertise, existing supply chain and advanced technology solutions. For example, the Industrial Hydrogen Production test site would greatly benefit from lessons learnt at the nearby Orkney Water Testing Centre.
There are few deepwater-pipeline operators with expertise in pipeline repairs. This paper describes a strategy developed and implemented on deepwater-pipeline intervention, based on a deepwater operational experience built over a decade. The market for subsea vessel operations in field development; inspection, repair, and maintenance (IRM); and subsea well intervention is expected to grow 63% during 2012 to 2016.
Low prices will constrain maintenance and modifications in the coming year. However, maintenance can only be delayed so long, leading to a long-term outlook of growth in the market for maintenance, modifications, and operations. There are few deepwater-pipeline operators with expertise in pipeline repairs. This paper describes a strategy developed and implemented on deepwater-pipeline intervention, based on a deepwater operational experience built over a decade. Compared to the US industrial average downtime ranging from 3% to 5%, the oil and gas industry’s estimated downtime ranges from 5% to 10%,indicating that improvement is needed in reliability and maintenance of facilities, equipment, and processes.
If sanctioned and developed, the deepwater Pecan field would be Ghana’s fourth producing offshore field. First oil is expected 35 months after sanction, which could come as early as this year. The steel pipe manufacturer agrees to deliver outer pipes for pipe-in-pipe flowlines for a pair of recently-announced Aker BP projects in the Norwegian Sea. Oilfield Services: How Much Consolidation is Yet To Come? The recent upswing in M&As in the oilfield services sector may be a harbinger of more to come as operators push for capex and opex control.