Case History of Complex-Fracture Behavior in the Hanoi Trough, Vietnam
- C.L. Cipolla (Pinnacle Technologies Inc.) | M. Mayerhofer (Pinnacle Technologies Inc.) | B.L. Wilson (Anzoil NL)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- December 2000
- Document Type
- Journal Paper
- 284 - 292
- 2000. Society of Petroleum Engineers
- 2.2.2 Perforating, 2.7.1 Completion Fluids, 5.5.2 Core Analysis, 1.2.3 Rock properties, 3 Production and Well Operations, 4.1.2 Separation and Treating, 1.6 Drilling Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1.2 Faults and Fracture Characterisation, 5.6.2 Core Analysis, 5.2.1 Phase Behavior and PVT Measurements, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 5.5.8 History Matching, 5.1.1 Exploration, Development, Structural Geology, 1.8 Formation Damage, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation
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In this paper we present a detailed case history of complex fracture behavior in exploratory wells in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft. The initial three wells were drilled from the same pad, with bottomhole locations about 3,000 to 5,000 ft apart and a probable fault between the No. 1 and No. 3 well. The gas reservoirs encountered were slightly overpressured and varied significantly in quality, with permeability ranging from 0.01 to 1 md. The first three wells were fracture stimulated in an attempt to improve deliverability. However, only one of the three treatments was successful due to complex fracture behavior. A comprehensive data set consisting of core analysis, rock mechanical tests, pre- and post-fracture logs, geochemical analyses, pre- and post-fracture well tests, and detailed fracture modeling was compiled to understand fracture performance in this complex environment. Without such a complete data set, identifying the cause of the treatment failures would probably not have been possible.
Three fracture treatments were performed in the D14 area (Hanoi Trough, North Vietnam). Fig. 1 shows the approximate location of the wells. The treatments were pumped in gas-bearing sandstone intervals (oligocene, fluvial channel deposits) in the D14-1, D14-2, and D14-3 wells. One zone in each well was fracture treated at depths ranging from 10,100 to 11,600 ft true vertical depth (TVD). The reservoir pressure gradient was about 0.6 psi/ft, with reservoir temperatures ranging from 275 to 300°F. Reservoir permeability varied significantly among the three wells. The D14-1 well test in July 1996 showed a permeability of 1 md and the well produced 2 to 3 MMcf/D of gas prior to the fracture treatment. The D14-1 was shut-in for several months after the initial well test with 11.5 ppg calcium carbonate completion fluid in the wellbore.
A second well test was attempted in D14-1 in May 1997, but the well would not flow (it was assumed that the perforations were plugged with calcium carbonate completion fluid). HCl acid was spotted over the perforations, but flow could not be re-established. The permeability of the zone that was fracture treated in D14-2 could not be determined (because well test and production data were not available), but the zone appeared very tight (less than 0.01 md). The permeability of the zone that was stimulated in D14-3 was about 0.02 md and the prefracture flow rate was about 0.16 MMcf/D. The results of the fracture treatments varied. The first treatment was performed in December 1996 on D14-2 and failed due to equipment and operational problems that were corrected on subsequent treatments. Details of this first treatment are omitted for brevity. The second treatment was performed in May 1997 on the deepest, low permeability pay zone in D14-3. The treatment was successful, resulting in a 7-fold increase in production (from 0.16 to 1.1 MMcf/D). Post-fracture well test results confirmed the effectiveness of the fracture treatment and indicated a fracture half length of about 200 ft [consistent with the fracture half-length calculated from the three-dimensional (3D) fracture modeling analysis]. The third treatment was also performed in May 1997 in the upper pay zone of D14-1. The treatment failed because the fracture did not bypass the existing wellbore damage (from completion fluid). Prefracture test rates were about 2 to 3 MMcf/D in D14-1, while post-fracture rates were only 0.3 MMcf/D. Post-fracture rates for D14-1 were expected to be 10 MMcf/D.
The available core data from D14-3 and the results of the D14-3 fracture treatment did not indicate any severe formation damage problems that could explain the D14-1 performance. The fracture diagnostic tests indicated an extremely high minimum in-situ stress of about 0.95 psi/ft in the reservoir sands, resulting in uncertainties about fracture orientation and containment. The magnitude of the minimum in-situ stress cannot be solely attributed to reservoir overpressure and does not appear to be related to sand quality (clay content) or rock mechanical properties. Therefore, regional and/or local tectonics are the primary cause of the elevated state of stress.1
The poor post-fracture production in D14-1 was attributed to fracture initiation in the bottom portion of the perforated interval and either extreme downward fracture growth or horizontal fracturing. Therefore, the fracture treatment did not bypass the extreme completion fluid damage. Post-fracture temperature logs indicated that the majority of the gas was coming from the bottom portion of the perforations, while a re-analysis of the dip meter log showed a natural fracture/minor fault near the bottom of the zone. Post-fracture well test results showed that the fracture treatment was placed in very low permeability rock, while geochemical studies identified differences in composition between the pre- and post-fracture gas. Fig. 2 shows the two fracture treatment scenarios. A preponderance of evidence suggests that scenario 1 is the more likely.
D14-3 Fracture Treatment
D14-3 was perforated from 13,035 to 13,081 ft (TVD 11,557 ft midperforation) with 6 shots/ft (spf), 120° phasing. The well was treated down 3.5 in.-, 12.7 lbm/ft tubing. Well test and log data indicated a reservoir pressure of about 6,900 psi and a reservoir temperature of 300°F. The data from the diagnostic injections and minifrac are shown in Fig. 3 which shows that two step-down tests2 were conducted to determine near-wellbore friction and three flow pulses3 were performed to assist with fracture closure stress estimates.
The diagnostic injections and minifrac indicated a closure stress of 10,900 psi (0.945 psi/ft) and only minor perforation and near-wellbore friction (tortuosity). There were no proppant entry problems or excessive injection pressures evident during the D14 treatments; thus a detailed discussion of the step-down test results is omitted. Fig. 4 illustrates a typical square-root-of-time analysis of the pressure decline data. Table 1 summarizes the fluid volumes pumped during the D14 treatment, while Table 2 summarizes the fracture modeling results. For reference the base fluid system for all gelled or borate crosslinked fluids consisted of 50 lbm/Mgal guar polymer, 2% KCl, 10 lbm/Mgal gel of stabilizer, 5 gal/Mgal of surfactant, and 0.5 lbm/Mgal of encapsulated breaker.
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