Typically offshore operations fall into one of three categories, Shallow water operations, where water-depth is smaller than 1,000ft, deep-water where water-depth is deeper than 1,000ft but under 5,000ft and, finally, ultra-deep water is anything over 5,000ft. Modelling different upstream oil and gas operations obviously brings different challenges – what are these challenges?
Water depth impacts the upstream oil and gas operations in a number ways, including the following;
- Water-depth plays an important role on the type of technology can be used to produce from the wells. For example, fixed platforms are typically used to produce from shallow waters
- The deeper your well, the more energy is required to bring the production up. This is one of the reasons why subsea systems are so important and there is a
The Energy Information Agency, in the United States, has summarised a list of major types of offshore oil rigs. This is a bit old but I could not find another reference.
Anyways, let’s try to summarise and update accordingly:
Different type of platforms
Fixed platform: fixed directly into the seabed, fixed-platform consists of a tall, steel structure known as a “jacket”. The jacket rises all the way up to support the topside/deck. Fixed-platforms offer stability and it holds everything out of the water. The main drawbacks are: low mobility, thus require a large field to justify the investment and cost.
Jack-up rig: this platform offers an alternative to the fixed-platforms for fields where the expected production cannot justify a permanent platform. The “Jack-up” platform is a floating platform which is towed into position by barges. After positioning the platform, the system lowers its supporting legs down to the sea floor, raising the rig above the water’s surface. The height can be adjusted taking into account waves and weather – pretty cool video here.
Jack-up Platform Oil drilling platform in the Mediterranean
Compliant tower: Compliant-tower rigs are very similar to fixed platforms with one specific feature: they shift with the wind and water almost as if they were floating. Their “base” is taller and narrower, and their jackets are broken into two or more sections, with the lower part serving as the base for the upper jacket and surface facilities. This allows this type of platform to operate at greater depths.
Floating Production system: these are platforms that are partly above the surface while pumping up oil from deep wells – almost like pretty big vessels. In order to keep these platforms in position, the rig requires an advanced mooring system and/or dynamic positioning system (using computer-coordinated thrusters to keep them in place). FPSOs, an example of Floating Production Systems, can be a conversion of an oil tanker or can be a vessel built specially for the application. These floating production systems are used in water depths from 600 to 6,000 feet and offer the mobility that fixed-platforms couldn’t offer. These production systems are typically connected by risers – there are different types of risers. These platforms are my favourite.
Floating Production Storage and FPSO Schematic
Offloading (FPSO) platform
Tension-leg platform: A tension-leg platform (TLP) or extended tension leg platform (ETLP) is a vertically moored floating structure. The platform is tethered to the seabed by a number of tendons that are kept in tension to suppress the heave motions, and the tension ensures that the platform remains virtually horizontal.
Subsea system: with the advent of deep and ultra-deep water production, a lot of processing systems have been moved to the seabed in order to save “lifting” cost. A subsea system may comprise of a number of modules such as separation, pre-treatment or manifold. One the main challenges relates to the maintenance strategy.
Spar platform: spar-platform uses a single, wide-diameter cylinder to support a surface deck from the sea floor – these structures are pretty impressive. This platform is named after the tall, vertical “spar” (aka mast) of a sailing ship which about 90 percent of its overall structure is hidden underwater. Spar cylinders are available at depths up to 3,000 feet, but existing technology can extend this to about 10,000 feet, making them one of the deepest-drilling types of offshore rigs in use.
So these can be summarised with the following schematic:
upstream oil and gas operations
What are the challenges for performance forecasting/advanced RAM studies?
From a modelling perspective, each one of these platforms will present different types of system which will impact directly on the model. For instance, systems where the water depth is too large may require a “powerful” Water Injection/Gas Injection system.
When looking at water injection systems, one of the most important parameters is expected water production rate (or production profile). From a performance forecasting and reliability perspective, the more water you have running through your system, the more stress is put on the components, which may increase the number of failures. Furthermore, the transient spare capacity – the difference between the capacity of the system and the actual flow – will dictate how failures will be impacting the overall production. For example, if a 2×50% water injection system is operating at a degraded state, let’s say there is a failure in one production arm, but amount of water that needs to be injected at the point in time is small, this might Not? impact the production at all. However, if the same production arm is down 5-10 years later, this might actually represent a critical failure.
Additionally, the maintenance strategies involving some of these systems are very specific.
Subsea systems are a perfect example of how maintenance strategy can be completely different depending on the technology implemented. We wrote about this a while ago – you can refer to this article “Getting deep in maintenance – subsea maintenance strategy”.
The maintenance priority in Maros plays an important role when trying to model the maintenance strategy of subsea systems. Maros comprises of three different levels of Job priority. The Job priority is set in terms of a numbering hierarchy in which Priority-1 is the highest; Priority-2 is the next important and so on up to priority 15. The priority levels are further split into three group levels:
- (Emergency) includes all events with priorities 1 – 5
- (Current/Next Shift) includes priorities 6 – 10
- (Non-Critical/Next Opportunity) includes priorities 11 – 15
The significance of the three levels relates to the maintenance operations philosophy.
When there is a backlog of repair tasks a utility will conduct all its level-1 jobs at a given location. If there is still a backlog of level-1 jobs at other locations then these will be attended in preference to any level-2 tasks outstanding on the current location. Level-3 repairs will not initiate a demand for a utility to be mobilized, such work will only be conducted at convenience when a suitable utility is on location for other duties – this describes exactly how the maintenance strategy for subsea systems is carried out.
Quick case study: Maintenance resources
For example, imagine that you are responsible for the maintenance of a subsea manifold requires a ROV as a maintenance resource. This could also be the actual manifold that needs to be replaced.
Block Flow Diagram in Maros – simple oil production
As aforementioned, the Level 3 Job Priority represents a “location-based” type of priority. So, in the Resource View tab, you could set up a number of locations for the different wells (or regions where repairs will be triggered when more than one manifold fails).
Multiple locations – Resource View
Finally the maintenance logic will be represented by conditional elements with a critical maintenance profile – this will trigger the resources to go to the specified location and replace the module. The conditional element can be used to represent the time to repair the manifold replacement or you could use the actual time to repair of the elements.
All of this could be connected to operational cost, capital expenditure and revenue lost, turning the maintenance study into a lifecycle cost analysis study.
Have a look at this video; it explains exactly the modelling scenario you would like to have.
To watch video, please click here
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Source: DNV GL
