(79913)_Understanding_Formation_(In)Stability_During_Cementi(5)

钻井固井

SPE/IADC 79913 Figs. 4 through 10. Fig. 4 first shows the net effect of 1% KCl brine on the shale after it was stabilized by 8% NaCl. Due to the imbalance in the salinity, the 1% KCl brine resulted in a net flux of water into the shale as exhibited by the increase in pore pressure. Each subsequent increase in KCl was then able to reduce the pore pressure, with 8% (slightly over 1 molar equivalent) returning the pore pressure to its original state. Higher concentrations of KCl resulted in a reduced pore pressure, indicative of a net flux of water flowing out of the shale.

The sequence of fluids in Fig. 5 shows that the polymeric fresh-water-based cement spacer showed a very slight upward trend in pore pressure. Adding KCl to the next sequence resulted in a net decrease in pore pressure starting as soon as the exposure began. Although the pore pressure changes in this test are not significant in magnitude, the key finding is that net flux is no longer contributing to destabilizing the shale. Keep in mind that these tests were run at room temperature and the fluid mobility typically increases as a function of increasing temperature. Fig. 6 shows the same trends when testing cement filtrate.

The tests shown in Figs. 7 and 8 are slightly different in that the shale was sequentially exposed to a sodium silicate preflush (Fluid D), fresh water, and cement filtrate as would occur during a cementing job. Exposure to the sodium silicate resulted in an immediate and more pronounced decrease in pore pressure, compared to the previous tests. As soon as the sodium silicate was displaced by water and then cement filtrate, the pore pressure increased instantaneously and continued upward to a level greater than the overbalance. This behavior could result in a net destabilizing effect on the shale during cementing, especially if conditions are such that the shale can continue to pull filtrate from the unset cement slurry. Fig. 8 is a repeat of the test in Fig. 7, but with KCl in the cement filtrate. This test likewise shows the sudden increase with exposure to the fresh water spacer, but upon being displaced by the KCl-laden cement filtrate, the pore pressure stabilizes for several days. The upward trend resumes later when the ionic imbalance resumes, but this time period would exceed that of the cement hydration time.

Based on previous tests reported by Tare et al., the swelling tests shown in Table 1, and the results of Figs. 4 through 8, the issue to address next is whether salt is needed in cementing fluids, or can polymers play this role, or is the optimum system a combination of both salts and polymers. Other additives, such as glycols, may also be considered candidates in cementing fluids for the purpose of providing shale stability. Figs. 9 and 10 address only the cement filtrate effects with the same salt loadings, but with polymers added. While the pore pressure trends exhibited a net downward trend for both polymer tests, these two tests cannot differentiate between the effects of the salt and the effects of the polymer. The lack of negative results indicated by the swelling data of Table 1 shows that further testing will be needed to better quantify the application of polymers to efficiently affect fluid transport.

5

Conclusions

Based on the results of the tests conducted in this project, the following conclusions can be drawn:

Fresh water cementing fluids could potentially

increase near-wellbore shale instability caused by unhindered fluid pressure penetration.

While adopting the practice of adding low

concentrations of salts has been further quantified as being a positive step toward contributing to formation stability, salt solutions alone may not provide sufficient membrane efficiency, as is evident from the pore pressure transmission tests. Near-wellbore shale instability can be mitigated by

optimizing the properties (activity and membrane efficiency) of cementing fluids. In addition to long-acknowledged mud-removal

attributes, sodium silicate preflushes can play a much larger role in the cementing process by contributing to a higher membrane efficiency. Following a sodium silicate preflush with a fresh

water spacer can allow efficient transfer of water from the wellbore fluid into the shale, resulting in a time-dependent increase in near-wellbore pore pressure and a corresponding decrease in shale stability. Combinations of salts and sodium silicates in

cementing fluids can provide a simple and economical means for managing shale instability during the cementing process.

Acknowledgements

The authors would like to acknowledge Halliburton for permission to publish this paper. We also recognize Chee Tan, CSIRO, and Westport Technology International for providing test support, and Dorse Walton of Cabot Oil & Gas for providing well data.

References

1. Gambino, F.E. et al.: “Experimental Study of Fluid/Rock

Interaction Caused by Drilling and Cementing Filtrates in Carito Field,” paper SPE 65004 presented at the 2001 International Symposium on Oilfield Chemistry, Houston, Texas, 13-16 February 13-16.

2. Tare, U.A., Mody, F.K. and Tan, C.P.: “Mitigating Wellbore

Stability Problems while Drilling with Water-Based Muds in Deepwater Environments,” paper OTC 14267 presented at the 2002 Offshore Technology Conference, Houston, Texas, 6-9 May.

3. Mody, F.K. and Hale, A.H.: “A Borehole Stability Model To

Couple the Mechanics and Chemistry of Drilling Fluid/Shale Interaction,” paper SPE 25728 presented at the 1993 IADC/SPE Drilling Conference, Amsterdam, The Netherlands, 23-25 February.

4. Sherwood, J.D.: “Biot Poroelasticity of a Chemically Active

Shale,” Proc. R. Soc. Lon. A. 440, 365, (1993).

5. Gdanski, R.: “High-pH Clay Instability Rating,” paper SPE

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