Coiled Tubing With Real-Time-Measurement Tools Helps Overcome Stimulation Problems
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The treatment in a deepwater, frac-packed well with fiber-optic-equipped coiled tubing (CT) and a rotating, hydraulic high-pressure jetting tool achieved successful stimulation of a 500-ft-long frac-packed zone after several previous failures using different techniques. By using CT equipped with fiber optics and downhole measurement tools, engineers were able to perform a data-driven operation based on real-time bottomhole measurements and distributed-temperature surveys. This successful treatment improved productivity by 75% compared to the well before treatment.
Diagnostic work indicated that a well had considerable skin and flow impairment. Several acid treatments had been bullheaded into the well since initial completion. The treatments were ineffective, either producing no material results or producing only short-lived improvements with a quick return to original conditions.
Slickline diagnostic work conducted on the well indicated the possible presence of a mechanical obstruction or fish of some sort near the bottom of the lower lobe of a sand package in the well. However, lacking correlated depth measurements, it was unclear whether this obstruction was below the entire producing zone or high enough to obstruct some of the lower screen section.
The formation consists of two lobes of one sand package at an approximate angle of 33°. On the basis of log data and core samples, the permeability of the formation across these lobes was highly variable. On the basis of that variability, it was believed that the most likely scenario was that the upper portion of the lower lobe was the highest-conductivity region of the completion and that the previous acid treatments had mostly been stimulating that portion of the well to the detriment of other areas. It was believed that the more-laminated-looking pay in the upper lobe, in particular, was underperforming.
Several problems had to be overcome to make another stimulation successful:
- There was uncertainty about exactly what the production problem was with the well.
- Conducting the stimulations would incur high cost.
- Excessive interruptions of new well-drilling operations would threaten to put production from new wells behind schedule.
- The fracture pressure of the zone was 12,700 psi, but the pore pressure was 12,100 psi, leaving only a small pressure margin to perform an operation at matrix injection rates.
A solution that allowed for real-time monitoring of the treatment was desired so that the reasons for the previous stimulation failures could be determined. In addition, it was hoped that a way to correct those points of failure could be developed while the operation was in progress, to produce improvements and negate the need for additional treatments. A variety of methods could be used to gather data on the operation: electric line, CT with electric line or fiber-optic cable installed, or digital slickline. However, only the CT option offered any reasonable expectation to be able to alter the treatment after it was started. Traditional CT with electric line installed in it was considered for the operation but rejected. Ordinary electric-line cable has poor resistance to acid. This can be overcome by cladding the electric line in plastic or polymer armor. However, this increases the outer diameter of the electric-line cable, greatly reducing fluid pumping capacity through the CT. This would reduce the potential opportunity to alter the course of the treatment once started and would limit the ability to clean the screens themselves with tools installed on the CT. Traditional electric line also lacks the ability to sense changes in temperature across the length of the cable. This capability is critical to obtaining detailed information about where fluids are entering and exiting the wellbore. Without this capability, electric-line-equipped equipment can only determine fluid entry and exit where the downhole tools are located at any given time.
CT with fiber-optic cable installed would allow real-time data gathering as well as the opportunity to pump down the CT pipe at high enough rates to potentially adjust the treatment. It would allow for much-more-effective screen cleaning of the completion than the option of electric line in CT. It would also allow the use of distributed-temperature sensing to determine where along the 500-ft gross formation length the fluids were going.
All the various data-collection instruments saw valuable actual use during the course of the operation—not merely functioning but gathering actionable information.
After tripping past the lowermost perforation at 23,660-ft depth, the CT hit an obstruction at 23,674 ft. This obstruction was the fish or debris previously noted by slickline work in the well. The use of the tension-and-compression sub was important in avoiding a potential stuck-pipe situation. Because the item required extra pull to get off or out of, it is easy to imagine a scenario in which the CT could have gotten stuck without the immediate data and feedback from the tool downhole as to what was happening.
In this case, the debris was deep enough in the well that all of the screen assembly could be stimulated effectively without risk. Having casing-collar-locator data was important for confirming this.
Before the stimulation began, baseline distributed-temperature data were gathered so that the subsequent treatment could be evaluated properly.
When used in the field, these data were compared with the actual data gathered during pumping operations. Temperature data for a pumping operation such as this can be gathered in one of two ways: by comparing the baseline temperature to the amount of cooling after the stage is pumped or by comparing the temperature after the stage is pumped to the speed at which it heats back up toward the baseline. The first set of data was gathered by pumping a 171‑bbl ammonium chloride preflush into the formation. All this fluid was pumped through the CT with the tool near the bottom of the lower zone at 23,610 ft and at a constant rate of 1.1 bbl/min so that rate-diversion effects and depth-diversion effects are eliminated from the subsequent data. The preflush is important to push reactive brines away from the near-wellbore region before any acid or other reactive material is pumped into the well. In this case, it is also important information because it provides a snapshot of the as-found condition of the formation because nothing had been done yet to change the injection profile of the formation.
The data available from this operation in the field after the 171 bbl of preflush show regions that had greater cooling and warmed up more slowly, indicative of regions that had greater amounts of fluid injected into them. The most obvious and unexpected point of interest is that the upper lobe, in particular the upper portion of the upper lobe, had the highest injectivity. This was not what was thought to be the case before the operation began. Immediately after the full acid treatment was completed, the data were processed. This information was correlated with the volumes of fluid pumped to develop a map showing how much fluid was actually injected to each portion of the zone.
The fully processed data provide more-detailed information about where the fluids went into the well, clearly showing that the top of the upper lobe took the greatest volume of fluid, even though the entry point of fluids into the well is at the bottom of the interval of investigation at 23,610 ft.
The CT was reciprocated across the intervals of interest while these stages were pumped so that the screens could be cleaned by the fluid-jetting action of the high-pressure rotating wash nozzle and to aid in diversion. Rate increased from 1.0 to 1.2 bbl/min through the course of the treatment as breakdown of the formation allowed increased pump rates. Compared with the as-found condition of the well, the upper portions of the lower lobe showed greatly increased fluid entry. This indicated that it was being effectively stimulated.
The treating line from the stimulation vessel to the rig lacked a digital flowmeter, and pump rates varied from 0.5 to 9.0 bbl/min. This combination of varying rate without closely spaced data on the actual rates from one point to another prevented the fluid invasion from being calculated as it had been for other stages of the operation. Nevertheless, a clear pattern could be seen. Diversion caused by screen cleaning in the CT pumped stages, foam diversion, and rate assist had moved the primary points of fluid entry from the upper lobe in the preflush stage to the upper portion of the lower lobe in the stages pumped through the CT. This resulted in a more-balanced profile in the bullheaded stages, with the first significant fluid entry to the lower portions of the lower lobe. Because of the data gathered during the CT-injected phases of the treatment, the size of the foam diverter stage in the bullheading phase of the operation was increased to try to block off the upper portions of the well because it was clear that they had already been effectively stimulated or never needed stimulation. It appears that this objective was achieved.
Well productivity improved from approximately 4,000 to 7,000 BOPD with no water. The improved rate was accompanied by a rise in the producing tubing pressure, but total rate was restricted to maintain a consistent drawdown and avoid completion damage. This rate has been sustained for more than 9 months after the treatment. Previous treatments dropped back to the baseline decline rate after only a few weeks of production. The operating envelope for operations of this sort was expanded, and a methodology to evaluate future operations was determined.
Coiled Tubing With Real-Time-Measurement Tools Helps Overcome Stimulation Problems
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