Fluid & Gas Flow

New Processes Needlessly Reduce Recovery from Onshore Gas Fields, Part 5

November 19, 2014

Oil-and-gas-riskIn the last century it was rare for facilities engineers to be involved in wellsite equipment selection/design, procurement, installation, or operation and it was unheard of for a process engineer to have any role in wellsites at all. When I assumed a facilities engineering role that included field operation responsibilities in 1993, I was unable to find another facilities engineer within the company that had a significant non-project role with whom I could compare notes.

Today there are a dozen engineers practicing in that field whose combined scope of work roughly matches my job in 1993 (except the field has half as many wells today as it did 20 years ago due to divestments). This flood of bodies is a direct consequence of the imposition of process safety management (PSM) concepts on wellsites and disregards the risk density on onshore gas wellsites. A significant portion of the available time of this group is spent in meetings talking about PSM issues.

Historically, our industry has tended to have zero wellsite drawings for onshore gas wells. Today a piping and instrumentation diagram (P&ID) is a prerequisite to starting PSM reviews that may or may not lead to procurement. I recently saw a pre-construction P&ID that was marked "Rev 62." Granted that most of the revisions had been to correct miscommunications between the engineer and drafter, but others were significant changes to design philosophies and came about through protracted negotiations among a large number of highly paid engineers.

Direct billing for facilities engineering to that pre-spud well was over $125,000 - 15 years ago, that amount would have been more than the entire budget for surface facilities on a well with the mix of pressures, temperatures, and fluids that was expected. The budget for surface facilities for this well was $2 million; that very large sum has entirely a PSM focus, and none of it considers the needs of the reservoir at the location of that particular wellbore. I asked several of the engineers in the hazardous operations (HazOp) unit for this well, "Where in the field is this well located?" and none of the ones I asked was able to tell me - they were making decisions that were going to have a material impact on reservoir performance without even asking what the reservoir looked like in that area of the field.

Wellsite equipment design must deal with a wide range of operating conditions and considerable uncertainty. Both of these concepts are very difficult for PSM. This difficulty is addressed with "nominal conditions."

To allow PSM to appear to work, we define the wellsite nominal conditions with terms like "expected gas production will be 5 MMSCF/day [141 kSCM/day," "expected water production is expected to be 2,000 bbl/day [0.318 ML/day," "expected operating pressure will be 50 psig [345 kPa," and "expected operating temperature will be 100F [37.8C."

Using these assumed values you can meet the requirements of PSM. You can calculate erosion potentials, pressure drops, and corrosion allowances quite easily. It doesn't matter that when a particular well comes on production, the wellhead pressure might be 1,200 psig [8.27 MPa; the wellhead choke will beat that variability out of the process. The overriding principle is the assumption that we can (and must) force the reservoir to act just like a plant feed. "Normal" activities that could significantly increase gas production or decrease water production are simply not viable because the design conditions cannot accommodate higher pressures, higher temperatures, or higher flow rates. If you constrain "normal" small enough, then you can design equipment closer to design tolerances.

This focus on fictional "nominal conditions" leads us to "save money" by designing wellsite facilities that are significantly understrength. Reservoir pressure is irrelevant because we have a "spec break" that will slam shut if flowing wellhead pressure approaches 90 percent of the maximum allowable working pressure (MAWP) of the separator, which was built to accommodate a very low pressure nominal condition.

Selecting ASME B16.5 Class 150 pressure class (pressure rating 280 psig [1.931 MPa) for a wellsite production unit saves something like $5,000 over selecting ASME B16.5 Class 600 pressure class (nominal pressure rating 1,450 psig [10 MPa). That $5,000 forces installing a $10,000 spec break that includes an emergency shutdown (ESD) valve, programming, and a variable choke - the "savings" really don't stand up to scrutiny, but luckily the underlying assumptions of PSM preclude much scrutiny of the real costs. Prior to PSM, ASME B16.5 Class 600 class vessels, valves, and piping on wellsites were usual and ESD equipment was rare. We're "smarter" now. We spend millions of dollars to do a worse job than the last generation spent thousands to accomplish.

David Simpson, P.E., is the owner and principal engineer at Muleshoe Engineering. David is an MVP in the professional forums at www.eng-tips.com and is a member of the Engineering Writers Guild. This article was originally published on Engineering.com and is adapted with permission. For more stories like this please visit Engineering.com.

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