Run a linear-elastic FEA on a pressure-containing component and it’s common to get a result that says the design fails — calculated stress above yield at a local hot spot — on a part that, in reality, has years of safe service behind it or would clearly survive a hydrotest. That’s not a wrong answer;
Elastic-Plastic vs. Linear-Elastic FEA: When Do You Actually Need Limit-Load Analysis? Read More »
A flanged connection that looks fine — bolts torqued to spec, gasket seated, no visible gap — can still be one thermal cycle or one pressure surge away from a leak path. Visual inspection and correct installation torque confirm the joint was built right; they don’t confirm it was designed right for the loads it
Flange Bolted-Joint Analysis: Why “It Passed Visual Inspection” Isn’t a Compliance Check Read More »
You don’t need to run an FEA to know whether the one you’ve been handed is any good. You need to know what’s supposed to be in it, and what its absence means. This is written for the person on the receiving end of an analysis report — procurement, project management, a client’s engineer who
How to Read an FEA Report: A Non-Engineer’s Guide to Stress Plots and Margins Read More »
API 6A and API 6D both cover valves used in oil and gas service, and it’s a common point of confusion which one applies to a given piece of equipment. The short version: it comes down to where the valve sits. API 6A governs wellhead and tree equipment; API 6D governs pipeline valves. Same broad
API 6A vs. API 6D: What’s the Difference Between Wellhead and Pipeline Valve Standards? Read More »
A wellhead stack is a set of stacked pressure-containing spools and hangers, and the names of the main components — casing head, tubing head, hanger — get used constantly without always being explained. Here’s what each one actually does, and how they fit together. The basic idea: a wellhead is stacked, not built as one
Wellhead Equipment 101: Casing Heads, Tubing Heads, and Hangers Explained Read More »
Wellhead equipment often outlives the paperwork that qualified it. A stack installed fifteen or twenty years ago can still be structurally sound while the code edition it was designed to, the field’s production plan, or the equipment’s own service history have all moved on since. The question isn’t whether the equipment still works — it’s
When Does Legacy Wellhead Equipment Need Design Re-Qualification? Read More »
A choke and kill manifold looks like a dense cluster of valves, chokes, and pipe spools, and sizing one properly means working through several interlocking decisions at once — pressure rating, choke sizing, redundancy, and line routing — each of which constrains the others. Here’s what actually goes into that. Start with the pressure rating
Choke and Kill Manifold Design: What Actually Goes Into Sizing One Read More »
A lot of equipment in service today only exists as 2D drawings — some scanned from paper originals, some in a CAD format the original software can no longer open. It still works, and the drawings still technically describe it. So it’s a fair question why you’d spend money turning that into a parametric 3D
2D to 3D: Why Convert Legacy Drawings to Parametric CAD Models? Read More »
A subsea tree does the same fundamental job as a surface tree — controlling flow from the wellbore — but almost everything about how it’s designed to do that job is different, driven by one basic constraint: nobody can walk out and manually operate it. That single difference cascades into how it’s actuated, monitored, sealed,
Subsea Tree vs. Surface Tree: Key Design Differences Engineers Should Know Read More »
AR/VR training gets pitched with a lot of enthusiasm and not much specificity about what it’s actually good for. It’s worth separating the genuine advantage from the novelty, because the honest answer is: it depends heavily on what you’re training for, and for the wrong use case it’s an expensive way to reproduce a manual
AR/VR for Operator Training: Does It Actually Reduce Incidents? Read More »