There exists in the pipeline industry a potentially catastrophic phenomenon known as ductile fracture. This report presents new technology which minimizes the effect of a ductile fracture if preventive measures fail.
SPE Members Abstract This paper reviews candidate selection, installation design, implementation, and production results of a 20,500 ft coiled tubing velocity string in the G. M. Shelton No. 2, a deep, low pressure, Gomez (Ellenburger) Field gas well. Introduction New advances in coiled tubing technology have generated an economic avenue for allowing continued production and obtaining additional reserves from gas wells with liquid loading problems. Improvements in coiled tubing manufacturing, wellhead and downhole accessories, and running equipment have provided the capability to install deep velocity strings. Installation of coiled tubing inside a gas well's existing production string reduces flow area, increases flow velocity, and improves the well's ability to unload liquids. Insufficient transport energy in the gas phase will result in liquid accumulation in and around the wellbore. This accumulation exerts a back pressure restricting reservoir inflow performance. Installation of a velocity string can be made without killing the well, killing the well and then jetting it on production, or by jetting a non-flowing well until production is initiated. Two coiled tubing velocity string applications were performed by Chevron in the Delaware Basin prior to the G.M. Shelton No. 2 installation (Table 1). The economic success and technological gains obtained from these two installations generated the incentive and data base to install the G. M. Shelton No. 2's velocity string. The G. M. Shelton No. 2 produces from the Gomez (Ellenburger) Field located in the Delaware Basin on the southwest flank of the Central Basin platform (Figure 1). Development of the Gomez (Ellenburger) Field was initiated in 1963. The G.M. Shelton No. 2 was completed during 1967. The well had an absolute open flow potential of 31 MMcf/D but initially produced at 4.7 MMcf/D. The production trend of the well showed no major production decline, only allowable effects (Figure 2). In October 1989, the well was acidized for the first time since initial completion with a loss in average daily production of 123 Mcf/D. After this stimulation attempt, the well produced an average of 100 Mcf/D using a surface intermitter set to produce two hours each day. Candidate Selection Analysis of the G.M. Shelton No. 2 was prompted because of its marginally economic production rate and the potential loss of 1.6 Bcf gas reserves (Figure 3). The well was determined to be liquid loaded after obtaining flowing and static bottom hole pressure data. This data showed the well's shut-in bottom hole pressure at approximately 2,200 psig, the development of a 3,500 ft liquid column under flowing conditions, and a reservoir drawdown pressure of 50 psig. Also, a sludge build-up was identified at 20,950 ft of which a sample was taken and analysis made. Although 65% of the well's perforations were below 20,950 ft, it was assumed that the sludge was not causing the production loss because of the Ellenburger formation's good vertical permeability in the Gomez Field. An initial review of the G.M. Shelton's P/Z data and production history, along with offset well histories, indicated that liquid loading occurred from induced fluids and water condensation versus reservoir water drive influx. Further analysis was performed using the Turner, Hubbard, and Dukler equation for continuous removal of liquids from gas wells and an in-house steady state multiphase flow simulator, "PIPEFLOW-2." It was determined that a production rate of 5.3 MMcf/D or greater was necessary for continuous removal of liquids under the well's existing tubular configuration. This critical production rate had not been achieved since 1971. P. 273^
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