Please note that the paper does not include Figure 4, which was omitted from the conference proceedings, and is not available.
Because depletion drive and partial water drive gas-condensate reservoirs diminish in pressure with production, flow conditions are continuously changing. Choosing the optimum tubing size for this type of wells can be made easier by use of a nodal analysis program to aid in identifying production velocities. More specifically, the seemingly intuitive conclusion that smaller tubulars will always be required during the latter stages of production in order to unload liquids may not be correct. In particular, when flowing bottomhole pressures on high productivity wells reach the low values of 500 to 1,000psi, fluid loading considerations can become insignificant when compared to frictional losses caused by the unusually high velocities found at these low pressures. Nodal analysis is indispensable for identifying these situations. By performing a few basic sensitivity runs on bottom hole pressure and liquid yields, a confident recommendation can generally be made on whether one tubing size will serve the life of the well or if a size change is advised later in the well life.
Presented is a case history of the Goodrich #1 well located in East Bayou Postillion Field, Iberia Parish, Louisiana. The well produced from a partial water drive gas-condensate reservoir known as the Planulina P4 Sand which occurs at a depth of 14,300 feet in the subject well. The production interval is approximately 200 ft. thick and the well initially produced at rates in excess of 25 MMCFPD through 3 1/2" tubing. After approximately 15 years of service, the tubing failed in 1990 and the well was worked over to replace the 3 1/2" tubing with 2 7/8" tubing. The smaller tubing was believed to be capable of depleting the reservoir from the now 900 psig bottom hole pressure down to roughly 500 psig abandonment pressure. However, after only two years of service, the 2 7/8" tubing developed a leak and the well had to be worked over again to replace the tubing. Prior to the second workover the bottom holepressure was measured at 680 psig and a diagnostic caliper survey was run. The survey revealed that the leak was not a fluke and that significant wall loss existed over the entire tubing length. Nodal analysis was run prior to the second workover which revealed that, since the previous workover, the well had been producing from the 2 7/8" tubing at rates far in excess of erosional velocity. Further, the nodal results indicated that 3 1/2" tubing was still the optimum size to deplete the reservoir in spite of the greatly reduced reservoir pressure. The 2 7/8" tubing was then pulled and replaced with 3 1/2 tubing and the well was returned to production at rates 40% higher than before. From that point, another 1,800 MMCF was produced before final abandonment in late 1995 at 480 psig bottom hole pressure.
Fig. 1 is a graph of the production history for the Goodrich #1 which is one of fourteen wells that have produced a combined cumulative of over 267 BCF from the Planulina P-4 Sand Unit. The reservoir had been on production for nearly six years when the Goodrich #1 was drilled and completed in 1975. Therefore, it is fairly safe to state that the reservoir was known to be a depletion drive(later it would be determined that the expandable water layer below was ineffective in sustaining reservoir pressure, but nonetheless eventually moved into each producer causing them to water out). By the time the subject well was completed, several of the offset wells had been potentialed at rates indicative of a high productivity reservoir. Therefore the water and condensate yields could be estimated with a fair degree of accuracy. Given this data then, it might have been obvious that a well capable of production in excess of 25MMCFPD would require 3 1/2" tubing. However, when the well went off production in mid-1990 with a bottom hole pressure of 900 psig, the decision on what size tubing to replace the 3 1/2" tubing with was probably not so obvious. Before going off line in 1990, the well was producing 2.7 MMCFPD plus 12 BF/MMCF and had produced a cumulative of 47,000 MMCF, 568 MBC and 100 MBW. Although finding a 14,300's deep sand producing with only 900 psig shut in bottom hole pressure may be a rarity, the techniques used to choose the replacement tubing size are the same (aside from mechanical safety margins) regardless of depth or pressure. It is not known whether the prior operator examined the problem using a nodal program, but in any case the smaller 2%" tubing was chosen and the well was returned to production at a greatly diminished rate of 1.8 MMCFPD plus associated fluid. Because the smaller tubing was used, another problem was accentuated to problematic proportions: the produced gas contained approximately 1.9% CO2 At first inspection, this may not appear to be a major concern since the first tubing string (N-80 grade) had lasted 15 years. One may expect similar service from the 2 7/8", N-80 replacement string.