Fluid & Gas Flow

New Processes Needlessly Reduce Recovery from Onshore Gas Fields, Part 3

November 5, 2014

Oil-and-gas-riskSupply chain management is integrally linked with environmental management. The underlying reason for this linkage is that if an oil and gas company is not dealing with shutdowns for spill assessment/remediation, then its ability to supply units of production will be more reliable. Since the oil and gas industry has decided to misapply these concepts to tools of production, the current bid process will always select the vendor with the ISO 14001 (Environmental Management Systems) certification over one without that certification.

Maximizing oil and gas recovery requires proper use of reservoir energy. The in situ hydrocarbons that we intend to monetize reside within reservoirs. Every portion of every reservoir has quirks that are unique. Individuals can learn these quirks and how to treat a particular well to maximize profit and minimize problems if they are allowed to do so. This learning curve can only be accessed through effective drilling processes, effective completions, effective surface facilities, and effective operating processes and procedures.

The first decision to install equipment or piping that is incompatible with full reservoir pressure, temperature, or fluid chemistry shifts the focus to looking away from the reservoir.

For example, with a reservoir pressure of 1,300 psig [8.96 MPa, if you select ASME B16.5 Class 600 pressure class (nominal pressure rating 1,450 psig [10 MPa) for your equipment and piping, it is unlikely that the reservoir can hurt the equipment - process-safety equipment and processes would be minimal if required at all. No chokes. No emergency shutdown (ESD) valves or logic. You would be able to operate the well in a way that would maximize long-term profitability (which may or may not require throttling flow, but that becomes a normal engineering/operations decision, not a process safety decision).

For the same reservoir pressure, if you build your surface facilities for ASME B16.5 Class 150 pressure class (nominal pressure rating 280 psig [1.931 MPa), then a wellhead choke is essential, ESD equipment and logic are mandatory. With the required chokes and ESD installed, you are precluded from considering the needs of the reservoir in your operating decisions - opening the choke poses too much risk of over-pressurizing the production equipment.

All reservoirs have a "pressure window" that maximizes ultimate recovery through optimizing the use of reservoir energy. This window can only be found through experimentation and is often somewhere around a flowing bottomhole pressure equal to one-half of average reservoir pressure. Exploiting this knowledge requires an understanding of average reservoir pressure and current flowing bottomhole pressure. To be able to quantify the pressure window, you need to have knowledge of both of these pressures.

We don't know of any effective way to measure reservoir pressure. In some reservoirs, we have the ability to economically determine it. For example, in coalbed methane (CBM, known as coalseam gas or CSG in Australia), nearly all of the gas in place is adsorbed to the surface of the coal. The amount of gas adsorbed to a unit mass of coal at a given pressure is a physical parameter of the coal and is determined through core analysis. This value is a key parameter in reserves estimating, and the reservoir engineers go to great pains to determine it with the lowest possible uncertainty.

The result of this analysis is a curve known as the Langmuir Isotherm, which plots gas-in-place versus average reservoir pressure. This means that with cumulative production, you can estimate a current reservoir pressure at any point in time after first production. Shale gas reservoir pressure is somewhat more complex than CBM since there is a significant void volume that holds both gas and liquids, but it is still possible to do a competent material balance. Tight gas and conventional gas have proven resistant to material balance evaluation, but classical reservoir engineering tools can be applied to predict pressure based on such tools as a pressure build-up.

Flowing bottomhole pressure is a parameter that we have several ways to determine. We can compare tubing-head pressure to casing-head pressure, calculate friction loss from tubing-head pressure and flow rate, run pressure bombs, or install downhole gauges. Any of these approaches can get us pretty close to actual values.

Having a reliable estimate of both average reservoir pressure and flowing bottomhole pressure lets us determine the pressure window through experimentation. These experiments require us to be able to manage flowing tubing pressure without regard to the artifacts we've installed downstream of the wellhead. With today's intolerance to risk, these experiments are exceedingly difficult to conduct and/or implement the results. With process safety management, it can require an management of change, critical drawing review, and hazardous operation review to change a flowmeter's effective range; procedures require controls to look first at the capability of downstream equipment before you can evaluate pressure upstream of a choke, etc.

My recent attempts to conduct this experiment in a CBM/CSG field met with total failure when any improvement in gas flow resulted in an emergency-shutdown trip - the ESD logic included a trip when flow rate in a 60-second period exceeded the flow rate in the previous 60-second period by more than 5 percent (the trip was designed to detect and minimize the effects of a downstream pipe rupture). Changing the trip setpoint was estimated to be an 18-month process.

Historically, the ESD would not have existed on very many wells, and where ESD was needed, the field would have been provided with a range of values for setpoint and delays that could be adjusted as part of normal operations.

READ: New Processes Needlessly Reduce Recovery from Onshore Gas Fields, Part 2

New Processes Needlessly Reduce Recovery from Onshore Gas Fields, Part 1

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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