whynotchemeng : Graduate

During the last month I have continued to be heavily involved in the detailed design on a subsea tie-back to produce a gas reservoir back to an existing offshore platform. Part of this project is to supply a Hydraulic Power Unit (HPU).

For those of you who are not too familiar with the workings of hydrocarbon production from a subsea tie-back, the well is drilled and completed on the seabed with a subsea template, manifold and control module. It is these systems that contain all of the master wing valves and subsea safety valves. As these valves lie on the bottom of the seabed they are controlled from the surface by using hydraulic fluids pumped through umbilicals piggy-backed to the production flowline. The fluids are pumped to the subsea control manifold and then turn the valves before being expelled to the sea (don't worry though, these hydraulic fluids meet all the correct environmental regulations and restrictions!).

The HPU is the skid that resides on the platform consisting of all the pumps and hydraulic fluid tanks etc. that supply these valves. This past week I have spent in the subsea vendors factory where the HPU has been fabricated. Prior to offshore installation it is the job all involved parties to send witnesses along to a Factory Acceptance Test (FAT) to ensure that the kit does what it was designed to do and is safe to install on the facility.

The FAT involved: checking all equipment was correctly tagged and installed in the correct orientation etc.; calibrating all level and pressure instrumentation; testing all instrumentation loops; hydrotesting pipes and tubing; ensuring all alarms function correctly and any executive actions (or process trips) correctly execute when mimicing the extremes of operation. All emergency shutdown actions are also tested.

With these checks made and signed-off the equipment is fit to be installed on the platform. Any items that need to be resolved prior to installation that the FAT showed were not acceptable go onto a "PUNCH LIST". The vendor will then action each of these items and will be signed off prior to the equipment being installed.

The next few weeks for me are going to be involved around site installations and commissioning of equipment. When I return I shall post some information on this blog regarding those. Until then.....

For those of you who are regular readers you may have noticed that I have been a bit sporadic with my posts of late due to work committments. Hopefully though I should be able to get back on schedule with a post a month.

For this one I thought I would take a small amount of time to talk about relief systems; more specifically relief valves and their sizing. I remember when I was at university that I understood the concept of pressure relief valves (PRVs) and why they were employed (as we don't engineer inherently safe designs) but that was really the limit of my understanding. Hopefully this small post will give you help if you have to do any relief valve sizings in design projects etc.

The main industry standard for PRV sizing is API 520 Part 1. This standard gives a really good overview about pressure relieving devices and explains how you size the orifice inside the PRV controlling the release of overpressure. It also gives guidance on the type of relief scenarios you need to consider, i.e. blocked outlet, fire impingement on a vessel, etc.

Lets take an example of a reactor with a design pressure of 200 barg. The PRV may be set to 200 barg so that in an instance where the maximum allowable operating pressure is exceeded the pressure in the vessel the design case is not exceeded.

The standard guides you through how to determine backpressures on the relief valve (e.g. hydraulic loads on the outlet of the valves caused by other flows or frictional losses in the downstream vent system) and other overpressures which lead you to a set of relieving conditions for the device. These conditions in addition to the reliving fluid properties allow you to calculate the required effective discharge area of the PRV.

This area is then translated into an orifice size from which you can determine the valve body size from a source such as the GPSA Databook. Following this method allows you to obtain all of the necessary process design information for a PRV datasheet. If you want to take it one step further, API 520 Part 2 describes the method for sizing the inlet and outlet pipework to the PRV. The sizes are a function of pressure loss and velocity constraints.

If anyone would like more information feel free to add a comment to the post. Until next time.....

Apologies for the delay since the last posting; work has been busy and I was allowed to take a week's leave to go skiing...well deserved in my opinion!!! So a quick update on what I have been doing in the past few weeks and a look forward to the next month.

Since my last post I have been continuing with the detailed design phase of the gas-condensate subsea tieback project I am working on (details of the job can be found in previous entries). I have spent time in a HAZOP (hazard and operability) safety study providing process support to review our design; completed calculations to provide Instrument Engineers with process data for Venturi/Coriolis flow meters, pressure relief valves, etc; looked in the HP/LP interfaces and pressure protection over the design. I shall touch more on HP/LP interfaces in the next entry: what they are and how they are managed. Hopefully this would be useful consideration for those of you about to do design projects.

Over the next month the detailed design shall be tapering off so a lot of my job will consist of checking vendor information that comes back from the equipment/instrument orders to ensure that everything being fabricated meets the required specfications.

Until then....

Since Christmas I have been busy continuing with the detailed design phase of a new subsea tieback. In place of the usual entry that I write detailing the extents of my day job, today I thought I would provide an insight into the economic and technical drivers behind using a subsea tieback. This entry I suppose is aimed at students who have yet to have much experience in the economic criteria used to evaluate projects.

To take a quick step-back: a quick explanation of a subsea tieback. In the early days of offshore exploration and production of hydrocarbon fluids a platform would typically be constructed to produce from one field (if large), or 2-3 at most if they were in close vacinity. Today, multiphase resevoir fluids can be transported through pipelines over 100's of kms before reaching a reception facility. In the case of the subsea tieback I am working on the receipt of fluids occurs at an existing fixed jacket platform.

Fluids exist in the resevoir in multiple phases: i.e. immiscible liquids, miscible liquids, vapour, water, solids etc. meaning that transporting them in the their raw state requires no immediate separation. By flowing them back to an exisiting platform the costs of the project can be significantly reduced as no offshore production facility needs to be constructed. Alternatively, the subsea line could be directed to an existing/new onshore facility which makes construction/logistical costs a lot less.

Issues with flowing the fluids in multiphase fashion primarily occurs outside of normal operation, i.e. transient operations such as start-up, shutdown, pigging etc., but can also occur in normal operation. Two of the main issues are hydrate formation and intermittent liquids production, known as slugging.

Hydrates form at low temperatures and high pressures and can block lines presenting very expensive/hazardous problems. These conditions can exist in a subsea pipelines prior to start-up or after a prolonged shutdown. In this instance the reservoir can pressure up the line and fluid can cool down to the ambient temperature, i.e. conditions can fall inside of the hydrate formation envelope. To mitigate this the fluids can be inhibited with methanol, or other hydrate inhibitors, to bring the hydrate envelope inside the line conditions until the pressure reduces and temperature increases upon opening of the production choke valve.

Hopefully this small example provides a typical engineering trade-off for new subsea lines, i.e. cost savings versus scale/complexity of design. Next time I hope to give some insight into the extra-curricular life of a process engineering graduate.

I'm writing this blog around a week later than anticipated what with the frantic run to get work completed before year end. For the past while I have been busy with the detailed design stage of the subsea tie-back that I mentioned briefly at the end of my last entry. Largely this has involved simulation to determine the configuration of new topsides equipment and process conditions to size valves (FCVs, ESVs, etc.), design of HP-LP interface systems (studies of material specs, relief protection, start-up procedures), among a number of other tasks.

This has been a great learning experience for me and, to date, has been the closest work I have been involved in that mirrors the design projects completed as part of a chemical engineering degree. Obviously the level of detail that is acquired in this type of design work is an order of magnitude greater than that worked to an university, nonetheless one should not underestimate the value of the work completed in the university projects. For me personally the fundamental design skills I gained at university, albethey comparitively rudimentary, have provided me with a substantial foundation on which to rely on.

Other than the work side of the job the past 2 weeks have seen the start of Christmas celebrations in the office with 3 different lunches and/or evenings out. As I have now finished for the festive period (to take 3 lovely weeks off!) I can say that I might get a chance to fully recuperate before my feet hit the ground running again in the new year. Seasons greetings.......

After returning from my two week induction I began the next phase of my graduate training (for those of you who have don't know I work for one of the energy majors). The new role sees me seconded to a design contractor who my company employ to manage and deliver engineering projects for a number of our offshore assets.

In the contractors I am working in the guise of a process engineer and am already getting involved in a number of projects for various assets. In the first couple of weeks I was closing out workpacks from the offshore turnaround season. The turnarounds occur in the summer when the platforms come down for a few weeks to perform essential maintenance and modifications. The contractor office provides these packs, detailing scopes of work etc., as I was tasked with closing out the process engineering sections of these. This involved tasks such as "as-building" P&IDs (piping and instrumentation diagrams) to update the master drawings.

Since then I have been doing a whole variety of things including line specification calculations (for the EU Pressurised Equipment Directive), calculations for producing instrument datasheets, process modeling and simulation etc.

In the next month I shall be working on a FEED (front-end engineering design) project to install a subsea tieback. This simply means a pipeline to transport reservoir fluids from a satellite subsea well pad to an existing offshore facility. This will offer me experience in a number of new areas of engineering design; a time I'm sure will prove to be both challenging and interesting.