| Title | A Demonstration of the Feasibility of Acid Well Utilization: the Philippines' Well MG-9D Experience |
|---|---|
| Authors | R.R. Villa, Jr., F.L. Siega, M.M.M. Olivar, N.D. Salonga, M.S. Ogena, S.E. Garcia, B.C. Bu±ing, K.A. Lichti, S.P. White and N. Sanada |
| Year | 2000 |
| Conference | PNOC-EDC Geothermal Conference |
| Keywords | |
| Abstract | Well MG-9D produced acid chloride-sulfate fluid which proved to be very corrosive to pipelines. Its pH ranged from 2.26 to 5.90 during discharge testing. Simulation of downhole chemistry trends suggests that as the fluid moves towards the surface, the pH significantly drops from 4.2 to 3.4 starting at a depth of 800 mMD. The shift in fluid acidity is caused by the formation of acid-sulfate water from the dissociation of H2SO4. In August and September 1999, a testing on corrosion control options for acidic wells was conducted in Mahanagdong well MG-9D. The first test started with the determination of the fluids natural corrosivity through discharge testing on July 4, 1999. Water and gas samples were collected and sets of metal coupons were immersed in a test section to determine the effects of the fluid acidity to different types of piping materials. At the same time, UT measurements to monitor the pipe wall thinning were conducted. The results showed a significant thinning rate up to 1.0 mm/day based on UT measurements and 0.5 mm/yr to 3.7 mm/yr based on the material loss of the metal coupons. Similar results were obtained using a series of on-line corrosion monitors. The second test was conducted on August 26, 1999 by injecting NaOH solution into the wellbore to neutralize the acidity of MG-9D fluid using a ╝-inch Incoloy 825 tubing set at a depth of around 205 mMD. Due to the limitation of the tube diameter, the volume of NaOH injected did not raise the pH to a significantly higher value. The third test was subsequently conducted on September 7, 1999 using a 1-inch sucker rod tubing set at around 20 mMD using a more concentrated NaOH solution. The results showed a significant increase in pH of the discharge fluid from 2.87 to 4.05. This was coupled also by a decline in thinning rate of the pipeline wall as indicated by the UT measurement and on-line corrosion monitors. |