In gas storage or high-pressure gas wells, annular pressure is an unavoidable threat to safe, long-term resource production. The more complex situation, however, is multiple annular pressure, which means annular pressure happens in not only one annulus but two or more. Such a situation brings serious challenges to the identification of well integrity. However, few researches analyze the phenomenon of multiple annular pressure. Therefore, this paper studies the mechanism of multi-annular pressure to provide a foundation for its prevention and diagnosis. Firstly, the multi-annular pressure is classified according to the mechanism and field data. Then the failure mechanism and function of the wellbore safety barriers in the process of passage formation are analyzed. Finally, some suggestions are put forward for identifying and controlling multi-annular pressure. The results show that gas storage wells and high-pressure gas wells have the conditions to generate pressure channels, which leads to the expansion of annular pressure from a single annulus to multiple annuli. The pressure channel is composed of the tubing string, casing string, and a cement mantle, and the failures among the three have causal and hierarchical relationships. According to the channel direction, it can be divided into two types: tubing-casing annulus to casing annulus and casing annulus to the tubing-casing annulus, of which the former is more harmful. Some measures can be considered to prevent pressure channeling, including improvement of cementing quality, revision of maximum allowable annular pressure, and suitable frequency of pressure relief.
Annular pressure is an important issue in well quality due to its high risk and relatively wide distribution. Up to now, this phenomenon has been reported in deepwater wells [
As shown in
First is wellhead movement. According to modeling analysis [
As stated above, it is important to get a clear understanding of multiple annular pressure in gas storage wells and high-pressure gas wells, thus providing support for the indemnification and mitigation of multiple-annular pressure. However, annular pressure can be caused by different mechanisms, like thermal expansion and cement integrity failure or tubing leakage. But available research rarely studies multiple annular pressure; most studies appraise one kind of annular pressure in one annulus. For example, Maiti et al. [
These available researches are helpful in determining the sources of annular pressure, but it is difficult to judge multiple-annular pressure. Therefore, this paper conduct innovative work on the calcification and mechanism of multiple annular pressure. The cases are introduced to use field data to analyze multiple annular pressure. The risks are also compared and evaluated. The failure mechanism and function of wellbore safety barriers are analyzed to get the reason for the pressure channel. Combined with the conditions of gas storage, wells, and high-pressure gas wells, some suggestions are put forward for identifying and controlling multiple-annular pressure. This paper will reveal the formation mechanism of the pressure channels among multiple annuli. Theoretical and technical supports will also be provided for the identification of pressure channels and the prevention of multi-annular pressure.
Despite that the phenomena observed in the wellhead are similar, the mechanisms of annular pressure are all different and can be divided into four kinds. As shown in
No. | Cause | Pressure source | Pressure channel | Pressure power | Recovery after releasing |
---|---|---|---|---|---|
1 | Operation | Shrinkage of annular volume | / | Pressure imposed by operation | No |
2 | Thermal expansion | Annular liquid | Heat transfer | Heat from production fluid | No |
3 | Cement integrity failure | High pressure fluid | Comprehensive permeability of cement | Pressure different between two ends of cement | Yes |
4 | Tubing leakage | High pressure fluid inside tubing string | Leakage points in tubing string | Pressure difference at leakage point | Yes |
Annular temperature would increase after the well is put into production because the production fluid brings heat from deeper within the formation. So the liquid in the annulus tends to expand but is then trapped by the annulus. Therefore, annular pressure increases to compress the liquid, thus keeping the volumes of liquid and annulus equal [
Annular pressure caused by thermal expansion is also called trapped annular pressure. For trapped annular pressure, there is no fluid exchange outside. It can be mitigated by many measures, including thermal-isolate fluid or pipe, releasing thermal-expanded liquid, and optimizing fluid properties. Moreover, the pressure would not rebound once it is mitigated.
One of the cement’s functions is to isolate the formation fluid. However, the cement is not exactly qualified for this function. Once the cement loses its integrity, the formation would invade the annulus along with the cement. This would be more severe for gas wells because gas is easy to channel. Many researchers use comprehensive permeability to present the failure degree of cement integrity, but it cannot reflect the complex process of fluid transportation within the cement. But comprehensive permeability can be used in the model of annular pressure caused by cement integrity.
As shown in
According to field data, tubing leakage is the top reason for annular pressure in gas wells. The type of tubing leakage includes corrosion holes, thread leakage, packer leakage, and tubing body fractures. Sometimes, there are several leakage points in the tubing string. High-pressure gas enters the tubing-casing annulus through the leakage point(s) in the tubing string, so annular pressure increases accordingly. Usually, the small hole model is used to describe the leakage degree of tubing string leakage point, as expressed by
The gas leakage through the tubing string leakage point(s) is also propelled by pressure differences. Likewise, it will also recover after annular pressure is released, so it is also called sustained annular pressure. Moreover, the recovery speed is usually faster than the speed of annular pressure caused by the cement integrity failure.
According to the analysis in
Classification | Tubing-casing annulus A-annulus | Casing annulus (B, C, D…) | Connection & Risk |
---|---|---|---|
1 | Thermal expansion | Thermal expansion | No well barrier fails. |
2 | Thermal expansion | Cement integrity failure | Annuli are not connected by pressure channel. |
3 | Cement integrity failure | Thermal expansion | Annuli are not connected by pressure channel. |
4 | Cement integrity failure | Cement integrity failure | Annuli are connected by pressure channel. Casing and cement are the potential channel. |
5 | Tubing string leakage | Thermal expansion | Annuli are not connected by pressure channel. |
6 | Tubing string leakage | Cement integrity failure | Annuli are not connected by pressure channel. |
7 | Tubing string leakage | Tubing string leakage | Annuli are connected by pressure channel. Tubing, casing and cement are the potential channel. |
Here, several types of multiple-annular pressure require extra explanation and analysis. Type 1, Type 2, Type 3, and Type 5 all contain annular pressure caused by thermal expansion, which the B-B test can diagnose a B-B test. B-B test is shorted for pressure bleeding-buildup test. The annular pressure caused by thermal expansion would not re-buildup after bleeding, while annular pressure caused by well integrity failure dose. Usually, the sustained annular pressure in A-annulus is caused by a tubing string leakage or leakages. Still, sometimes the integrity failures of production casing and the cement are also the potential reasons, just like Type 4. For example, sustained A-annular pressure appeared in the high-pressure wells of the Elgin and Franklin field in the UK’s North Sea [
Two typical cases are used to illustrate the multiple-annular pressure in gas storage well and high-pressure gas wells. The first case is DZ gas storage in North China. This gas storage has 14 injection-production wells and five production wells. As shown in
Well | A-annular pressure | B-annular pressure |
---|---|---|
D2-1 | 4.5 MPa | 6.0 MPa |
D2-2 | 5.2 MPa | 1.1 MPa |
D2-3 | 8.0 MPa | 6.4 MPa |
D2-4 | 12.5 MPa | 13.9 MPa |
D5-3 | 7.8 MPa | 4.8 MPa |
D5-1 | 13.3 MPa | 2.2 MPa |
D6-1 | 5.7 MPa | 1.8 MPa |
D6-3 | 11.6 MPa | 2.1 MPa |
The other case is a high-pressure gas field in Northwest China. This gas field is faced with serious well integrity failure problems, and many advanced technologies have been previously conducted. Therefore, some gas wells are monitored in order to continue production under higher than desired annular pressure.
According to the above analysis, it can be noted that multiple-annular pressure is a critical issue regarding gas storage wells, as well as for high-pressure gas wells. The major kind of annular pressure is sustained annular pressure caused by a gas channel or channels. As a result, one of the reasons for the multiple-annular pressure is that pressure channels connect the annuli. Here, the pressure channel is analyzed in order to prevent multiple-annular pressure from building up.
The well barriers between nearby annuli are tubing, casing, and cement, so the pressure channels also consist of them. The pressure channels can be divided into two kinds: the first consists of tubing, casings, and cement. The gas leaks from tubing through the leakage point, so A-annular pressure increases. Next, the gas invades into B-annulus through casing leakage points and through damaged cement, so B-annular pressure also increases, respectively. Likewise, the pressure can also expand to C-annulus. The other consists of just casing and cement. Gas invades into the casing annulus leading to greater, more sustained casing annular pressure. The gas then invades into the nearby annulus through casing leakage point(s), which can be either the tubing-casing annulus or nearby casing annulus. As a result, multiple-annular pressure appears in gas storage wells or high-pressure gas wells. To explain why the pressure channel generates then, it is necessary to understand how the related well barriers lose their integrity as well.
The integrity failure of tubing can be attributed to three factors, including load, environment, and tubing quality. The load includes the gravity of the tubing string, stimulation operation, tubing shock, annular pressure caused by thermal engineering, and formation deformation. The environment represents temperature and corrosive fluid. The tubing quality refers to its materials and manufacturing technology. Under the above factors or combination, the tubing may lose its integrity. Research showed that stress corrosion crack is a major type of tubing integrity failure that occurs in high-pressure gas wells. Other types are thread seal failures, tubing body deformation, etc.
The failure of cement integrity can be attributed to cement slurry properties, cement quality, perforation, corrosion, temperature, and pressure changes [
For gas storage, many of the wells are old wells. After years and years of production, these old wells have integrity problems to various degrees, like casing damage and cement integrity failure. Moreover, the gas storage well is serviced as an injection and production well. The production rate is usually very high, and the injection pressure is also very high. This leads to remarkable alternating loads and threatens the integrity of the tubing, casing, and cement. The high-pressure gas well is usually a deep or even ultra-deep well, so the temperature is high and the pressure system is complex. Deep wells need longer drilling times, and as a result, the casing may be quite worn. For example, the casing at a depth of 1600 m in DB301 was well worn. The reservoir contains H2S or CO2 in part of the high-pressure well, such as the Puguang gas field. Also, the tubing suffers from a rather complex load due to the combination of gravity, temperature, and the water h mer effect. All of the conditions mentioned above lead to the formation of one or more pressure channels.
Here, a deep gas well is selected as the case study to illustrate the pressure channel and multiple-annular pressure. This well is 6605 m deep. The reservoir pressure and temperature are 110 MPa and 147°C, which is a typical high-pressure and high-temperature gas well. This well was put into production on 28th, May 2016. At that time, A-annular pressure was 40.11 MPa, and B-annular pressure was 40.03 MPa. Tubing pressure was 87.30 MPa, and the highest production rate approached was 50 × 104 m3/d.
As shown in
Multiple-annular pressure could be seen after the well was put into production. At that time, this was annular pressure caused merely by thermal expansion. Here is the analysis: first of all, no flammable gas was reported in the annulus. Secondly, the change of annular pressure was determined by the production rate; the annular pressure decreased when production stopped and then increased again after production was restarted once more. Third, the values of the annular pressure in the A-annulus and B-annulus were close, which is a characteristic of the annular pressure caused by thermal expansion. The multiple-annular pressure, therefore, was not of high risk at that time.
However, the situation changed on 19th, August 2016. The pressure channel formed, and annular pressure was sustained. The gas escaped from the tubing string and then entered B-annulus. Here is the analysis. First, the annular pressures were related to the tubing pressure. The sudden increase of A-annular pressure led to a sudden decrease in the tubing pressure. The pressure channel was tubing, casing, and cement. Second off, flammable gas was reported in A-annulus, as well as in B-annulus. The pressure channel was tubing, casing, and cement.
The integrity failure of the tubing string was verified after the tubing string was lifted to the ground. Four leakage points were found in the tubing string. First is a hole at a depth of 1910 m. The second is the tubing deformation at the depth of 6093.86 m. The third is the tubing deformation at the 6381 m, which is under the packer. Forth is a longitudinal crack in the tubing body from 6381∼6391 m, which is also under the packer. However, the first two leakage points are the key for the sustained A-annular pressure. The casing cannot be lifted from the ground. However, the high pressure in A-annulus and poor cement quality create a very easy circumstance that could bring about eventual casing integrity failure. Moreover, the highest A-annular pressure was over 80 MPa, according to
Cement integrity failure is also not difficult to explain. Besides the cement quality, the high pressure in A-annulus was already in the process of bringing about micro-annulus, even if the cement quality was perfect. For the pressure in C-annulus, the quality of cement behind 365.12/339.72 mm casing can be seen in
Depth, m | Cement quality | Depth, m | Cement quality |
---|---|---|---|
12.0∼36.5 | Free casing | 3241.1∼3321.3 | Poor |
∼2605.6 | Poor | ∼3331.8 | Medium |
∼2714.7 | Medium | ∼3346.7 | Poor |
∼2788.7 | Poor | ∼3354.2 | Medium |
∼2908.3 | Medium | ∼3419.6 | Poor |
∼2938.4 | Poor | ∼3516.9 | Medium |
∼2974.7 | Medium | ∼3586.8 | Poor |
∼3014.1 | Poor | ∼3609.9 | Medium |
∼3025.1 | Medium | ∼3632.6 | Poor |
∼3034.8 | Poor | ∼3644.9 | Medium |
∼3069.4 | Medium | ∼3649.7 | Good |
∼3110.1 | Poor | ∼3925.0 | Medium |
∼3161.5 | Medium | ∼4045.0 | Poor |
∼3192.6 | Poor | ∼4052.0 | Not evaluated |
∼3241.1 | Medium |
Annular pressure can be divided into four particular kinds. They are each caused by operation; annular liquid thermal expansion, cement integrity failure, and tubing string leakage. Accordingly, multiple-annular pressure can be classified into seven types, but not all the types of multiple-annular pressure are caused by pressure channels. Type 7 is at the highest risk because the pressure from tubing is high and may exceed MAAP of the outer annului. The pressure channel mainly consists of the tubing string, casing, and cement. The integrity failure of the tubing can be attributed to three factors, including load, environment, and tubing quality. Casing integrity failure can also be divided into tubing body and thread failure. The failure of the cement integrity can be attributed to cement slurry properties, cement quality, perforation, corrosion, temperature, and pressure change. Field data shows that multiple-annular pressure is one of the most serious challenges for both gas storage and high-pressure wells. They have the conditions for the formation of pressure channels. This case study verified the analysis of multiple-annular pressure and pressure channels. To prevent multiple-annular pressure, however, some measures are recommended to prevent multiple-annular pressure, including improvement of cement quality, control of A-annular pressure fluctuation, and the greater enhancement of tubing string integrity.
Cross section area of cement mantle, cm2
Height of gas column, m;
Comprehensive permeability of cement, μm2
Length of cement mantle, cm;
Isothermal compressibility of annular liquid, MPa−1
Gas solubility of annular liquid, m3/m3
Gas temperature under standard conditions, K
Annular liquid column pressure, MPa
Gas pressure under standard conditions, MPa
Annular pressure, MPa
Annular pressure in the iteration of (
Annular temperature, K
Annular volume, m3;
Total gas volume invading into annulus under standard conditions, m3
Gas compressibility factor under standard conditions, dimensionless
Gas compressibility factor in annulus, dimensionless
Gas viscosity under average pressure difference, mPa·s
Gas compressibility factor under average pressure difference, dimensionless
Annular pressure, MPa
Volume change of annulus, m3
Increase of annular temperature, °C