A Case Study: Profiling Gas Production in the Tubing/Casing Annulus, Using Noise/Temperature Logging Techniques

To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/casing annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs. Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile. Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/casing annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe. In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator. Introduction In general, tight-gas developments require a dense spacing of wells, ranging from a few to several wells per section. On these wells, regulators often require that a production-logging survey be acquired periodically. In Canada these requirements vary from province to province. Often, in the absence of regulatory requirements, operators must determine if the relative contribution of each completion zone continues to deliver gas as originally identified in logs. These tight-gas reservoirs are usually completed over several zones in stacked-pay, and each zone has varying subsurface qualifiers. These qualifiers can include different system permeability, stress distribution, and natural fractures—all tend to increase the delivery anisotropy between zones, especially when all zones are commingled. This anisotropy in producibility can create early water loading of some zones or even complete loss of production from zones within the first 3 months of a well being placed on production. It is critical to run a periodic flow profile that assists in predicting earlier-than-expected termination of the completed net pay. If remediation is required, corrective action could include refracturing, or if the well is liquid loading, then running a plunger or foam injection could be recommended. The water flowback during production usually becomes a hindrance to effective gas lift, forcing operators to run production tubing deep immediately from the onset of the production. Deep-run tubing, which is hung past the deepest set of perforations, can help lift the liquids and delay liquid loading in wellbore. Gas inflow is directed downward within the tubing/casing annulus, thereby lifting the liquid buildup from the wellbore as the gas is produced up the tubing. Normally monitoring is performed using downhole production-logging tools (PLT) to provide a production profile across the perforated intervals. These tools must be exposed to the wellbore and be run within the flowstream to measure fluid flow rates,