In gas condensate wells, liquid reinjection during a buildup test can be mistaken for dual porosity or condensate banking in the reservoir.

When pressure-testing a well from the surface, it is important to be able to differentiate between pressure changes caused by wellbore effects and the pressure response from the reservoir. It also is critical to recognize these differences in downhole gauge data. When testing gas condensate or volatile oil wells, downhole gauges can respond to the same things that affect surface data.
Unfortunately, the downhole gauge data are almost never questioned, regardless of the actual depth at which the gauge is set. During analysis or test interpretation, artifacts in the bottomhole pressure data such as phase redistribution and temperature-related phase or density changes, which should be attributed to the wellbore, often are mistaken for dual porosity or condensate banking in the reservoir. In gas condensate reservoirs, the most common of these effects, which shows up during a buildup test if the reservoir pressure has dropped below the dew point, is the phenomenon of liquid fallback and reinjection.
This is what happens in the wellbore during this process:
• while the well is under production, the gas lifts the liquids. If the gas rate is above the critical unloading velocity, there will be no liquid column in the well;
• when the well is shut in, the gas rate becomes zero;
• the liquid that was being lifted by the gas falls to the bottom of the well;
• if enough liquid is present, a liquid column will form in the well. (Data collected with a pressure gauge that is above the liquid column will not reflect the true reservoir and bottomhole pressure);
• if gas is the continuous phase in the reservoir, gas will bubble through the liquid and force the liquid into the formation. The liquid column height will decrease with time. (If a liquid is the continuous phase in the reservoir, reinjection will not occur); and
• once the liquid level drops to the perforations, the wellbore will contain single-phase gas from the surface to the perforations. Pressure data acquired from the surface then will become valid.
The plot used to diagnose whether reinjection is occurring is a semi-log plot with shut-in time on the x-axis and linear pressure on the y-axis (Figure 1). Starting from the left side of the plot, the reinjection "signature" is:
1. pressure initially builds (mostly a skin effect in a high-permeability reservoir);
2. pressure peaks and becomes flat or drops (liquid column building);
3. pressure makes a "J" or hook-shape (liquid column reinjecting); and
4. pressure breaks over to a much less steep slope (liquid column gone).
As an example of this mechanism, consider the test data in Table 1, acquired using a SPIDR system at the surface and a dual quartz downhole bomb on a gas condensate well in the Gulf of Mexico. Midperf depth was 12,913 ft (3,938 m).
The well was a straight hole on the Gulf of Mexico continental shelf. The gas rate prior to shut-in was about 7.5 MMcf/d. The well also was producing 410 b/d of 47° API condensate and 15 b/d of water. The downhole gauge was run to the X nipple at 12,770-ft (3,895-m) MD; flow was not interrupted to run the gauges. The SPIDR was installed on the blowdown valve of the wireline lubricator. After the downhole gauge had been on the bottom for 30 minutes, the well was shut in at the manual wing valve. The SPIDR data then were converted from wellhead pressure (WHP) to bottomhole pressure (BHP), and the data were compared to the measured downhole gauge data (Table 2).
For the flowing BHP conversion, Data Retrieval Corp.'s (DRC's) mist flow algorithm was used. As can be seen in Table 2, the calculated flowing BHP was within 3 psi of that measured with the downhole bomb. On the buildup, DRC's thermal decay algorithm was used to correct for changes in density related to wellbore cooling. In addition, DRC's wellbore flash calculation was performed to determine the amount of condensate that would remain in solution with the gas phase as well as the amount that would drop out and fall to the bottom of the well (and reinject into the formation). The difference in the calculated shut-in BHP and measured shut-in BHP was 17 psi.
The interesting thing about this test showed up in an overlay plot of the buildup data sets. Based on the liquid yield and the fact that the wellbore and reservoir pressures were below the dew point, some sort of reinjection effect was expected in the SPIDR data. Closer inspection revealed reinjection effects in the downhole gauge data as well.
In Figure 2, the downhole gauge data is plotted vs. the calculated BHPs on a Cartesian scale. Starting at the end of the shut-in and working back, the SPIDR data and the bomb data track each other for the last 18 hours of the buildup test. However, they do not match during the first 8 hours. DRC engineers suspected liquid reinjection in the SPIDR data, but were curious as to what was going on with the bomb data. It looked valid for the first 2 hours, or at least it looked like a normal buildup. Then the pressure fell for 2 hours and increased slightly for about 4 hours, before increasing again at the point where the SPIDR data converges with it (8 hours).
The semi-log plot of the SPIDR data showed the reinjection signature - it initially builds, then becomes flat (and drops slightly) and is followed by a "J" or hook-shape, which then breaks over and behaves like normal buildup data. In this case, the bomb data actually looked good for the first 1 1/2 hours. Then, the pressures dropped and became flat for a few hours until they hooked up and then tracked the SPIDR data (Figure 3).
So while DRC had an acceptable explanation for what was going on in the SPIDR data, it was still necessary to find out what was causing the bomb data to look strange. It turned out the explanation was related to the location of the bomb.
What happened
When the well was shut in, almost all of the condensate (92%) being carried up by the gas fell back down the wellbore. The liquid formed a column, which had an initial height of 280 ft (85 m), according to calculations, above midperf. The downhole gauge was set 140 ft (43 m) above midperf. Thus, the downhole gauge had single-phase liquid between it and the perforations for the first 2 hours of the buildup test. Then, as the liquid level dropped below the downhole gauge, the measured pressure decreased and began showing reinjection effects, which the SPIDR had shown throughout the buildup (since the liquid level was between it and the perforations the whole time).
How to analyze this
Analyzing a well test where the pressure gauge is above a moving liquid level can be difficult, especially since well-test software is not designed to deal with it. Basically, the way to do it is to wait until the reinjection period has passed and hope no boundaries were hit before the liquid level dropped to the perfs. In the Gulf of Mexico example, the downhole bomb data appeared valid for the first couple of hours and had the same midtime slope at 1 hour (with single-phase liquid to the perfs) as it did at 10 hours (with single-phase gas to the perfs). This indicated no boundaries were encountered during the reinjection period. So, in this case engineers were able to provide analysis for the downhole bomb and the SPIDR data.
To solve the problem
The first recommendation is to conduct the well test early. The best way to deal with liquid fallback and reinjection is to avoid it. Thus, for a gas condensate well, test the well before the reservoir pressure gets below the dew point. If there isn't a liquid phase in the wellbore, there won't be anything that can fall back and ruin the test. An additional advantage to testing before phase behavior becomes an issue is that it provides a good idea of how long it takes to hit the first boundary. If later buildup tests show that reinjection ended before hitting the first limit, the test should be easy to analyze.
Secondly, do a drawdown. In general, the best way to test a well is with a drawdown. Constant choke drawdown pressures are less affected by phase behavior and changes in density or temperature than buildup pressures. However, if poor-quality mechanical strain or piezoelectric strain silicon and sapphire gauges are used on high-temperature wells, inadequate thermal compensation of the gauge can cause significant errors in the pressure. Besides, managers complain much less when a well is tested while producing. The only problem is that the well must be shut in prior to the drawdown, so it's best to wait for scheduled downtime.
To get valid drawdown data, the flowing WHP has to be 2.2 times the line pressure to ensure critical flow through the choke. If the well is "riding the line," the drawdown data will not be isolated from downstream disturbances, and therefore may not be valid. To summarize, if the flowing tubing pressures are 2.2 times greater than the line pressure, do a buildup followed by a drawdown. In this fashion, P* can be calculated from the buildup, and skin, permeability and boundaries can be calculated from the drawdown. This is the most reliable method to get accurate quantitative analysis on wells that may exhibit reinjection effects.
The third recommendation is to do a two-rate test. These tests should yield some general numbers for skin and permeability, but usually provide less reliable quantitative results. To perform the test, put gauges in or on the well and record flowing pressures at a given choke size. After the choke is reduced, a pseudo-buildup can be recorded and analyzed using effective rates and a few other mathematical shenanigans related to superposition theory. These tests should be attempted only if it is impossible to get valid drawdown data.
Finally, if boundaries aren't hit before reinjection has finished, just ignore the section of data that isn't valid and analyze the portion of the data that is.
Be careful
Many strange things that go on during well tests show up in surface and downhole gauge data. Some of them happen in the wellbore; some happen in the reservoir. An understanding of fluid behavior in both places is critical for accurate well test analysis. In gas condensate reservoirs, liquid fallback and reinjection poses significant problems to test design and interpretation. It is easier to design a test program to get the results needed from the test. If the reservoir pressure is below the dew point, liquid fallback and reinjection is going to happen. Expect it; don't assume everything observed in the surface or downhole gauge data actually happened in the reservoir.

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