Evaluating the Damage Caused by Calcium Sulfate Scale Precipitation During Low- and High-Salinity-Water Injection
- Mohamed A. Mahmoud (King Fahd University of Petroleum and Minerals)
- Document ID
- Society of Petroleum Engineers
- Journal of Canadian Petroleum Technology
- Publication Date
- May 2014
- Document Type
- Journal Paper
- 141 - 150
- 2014.Society of Petroleum Engineers
- 4.3.4 Scale, 6.5.2 Water use, produced water discharge and disposal, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 5.5.2 Core Analysis, 1.8 Formation Damage
- damage, low salinity, calcium sulfate, high salinity, chelating agents
- 9 in the last 30 days
- 562 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
Scale deposition is a serious oilfield problem, when two incompatible waters interact chemically and precipitate minerals. Typical examples are seawater with a high concentration of sulfate ions and formation water with high concentrations of calcium, barium, and strontium ions. Mixing these waters may cause precipitation of calcium, barium, and/or strontium sulfate. The removal of the entire sulfate content from seawater might be a costly process and requires highly advanced techniques (nanofiltration). This study was conducted to investigate the damage caused by deposition of calcium sulfate precipitation and to describe the damage by use of the material-balance method, and then a new technique is proposed to prevent the damage caused by calcium sulfate scale. Coreflooding experiments were performed to assess the damage caused by calcium sulfate and a computed-tomography (CT)scan was used to locate the damage inside the core. Chelating agents, such as hydroxyl ethylene diamine triacetic acid (HEDTA), ethylene diamine tetra acetic acid (EDTA), and hydroxy ethyl imino diacetic acid (HEIDA), were used to prevent scale deposition in the Berea sandstone cores. The pressure drop across the core caused by scale precipitation will be predicted analytically. The results of the experimental data showed reduction of permeability by 20% from its initial value after seawater injection, caused by calcium sulfate precipitation. The results of the new analytical model showed that in approximately 1 month, the injection will stop or the injection pressure will exceed the fracture pressure of the formation. High-salinity-water injection caused severe formation damage, and the injectivity declined faster compared with the low-salinity-water injection. The material-balance calculations showed a good match between the experimental, field, and predicted data. The developed model of the pressure drop caused by calcium sulfate precipitation was used to predict the pressure drop across the core, and its result was in a good match with the experimental results. The new method was effective in preventing and removing sulfate precipitation.
|File Size||1 MB||Number of Pages||10|
Aliaga, D.A., Wu, G., Sharma, M.M. et al. 1992. Barium and Calcium Sulfate Precipitation and Migration Inside Sandpacks. SPE Form Eval 7 (1): 79-86. SPE-19765-PA. http://dx.doi.org/10.2118/19765-PA.
Atkinson, G., Raju, K., and Howell, R.D. 1991. The Thermodynamics of Scale Prediction. Presented at the SPE International Symposium on Oilfield Chemistry, Anaheim, California, USA, 20-22 February. SPE-21021-MS. http://dx.doi.org/10.2118/21021-MS.
Bayona, H.J. 1993. A Review of Well Injectivity Performance in Saudi Arabia's Ghawar Field Seawater Injection Program. Presented at the Middle East Oil Show, Bahrain, 3-6 April. SPE-25531-MS. http://dx.doi.org/10.2118/25531-MS.
Bezemer, C. and Bauer, K.A. 1969. Prevention of Carbonate Scale Deposition: A Well-Packing Technique with Controlled Solubility Phosphates. J Pet Technol 21 (4): 505-514. SPE-2176-PA. http://dx.doi.org/10.2118/2176-PA.
Carlberg, B.L. 1973. Solubility of Calcium Sulfate in Brine. Presented at the SPE Oilfield Chemistry Symposium, Denver, 24-25 May. SPE-4353-MS. http://dx.doi.org/10.2118/4353-MS.
Chen, T., Neville, A., and Yuan, M. 2004. Effect of PPCA and DETPMP Inhibitor Blends on CaCO3 Scale Formation. Presented at the SPE International Symposium on Oilfield Scale, Aberdeen, 26-27 May. SPE-87442-MS. http://dx.doi.org/10.2118/87442-MS.
Connell, D. 1983. Prediction and Treatment of Scale in North Sea Fields. MS thesis, Heriot-Watt University, Edinburgh, Scotland.
Essel, A.J. and Carlberg, B.L. 1982. Strontium Sulfate Scale Control by Inhibitor Squeeze Treatment in the Fateh Field. J Pet Technol 34 (6): 1302-1306. SPE-9628-PA. http://dx.doi.org/10.2118/9628-PA.
Fan, C., Kan, A., Zhang, P. et al. 2012. Scale Prediction and Inhibition for Oil and Gas Production at High Temperature/High Pressure. SPE J. 17 (2): 379-392. SPE-130690-PA. http://dx.doi.org/10.2118/130690-PA.
Frigo, D.M., Graham, G.M., Littlehales, I.J. et al. 2005. Design and Laboratory Testing of a Hybrid Scale-Inhibitor Package for an HTHP Gas-Condensate Reservoir. Presented at the SPE International Symposium on Oilfield Scale, Aberdeen, 11-12 May. SPE-94865-MS. http://dx.doi.org/10.2118/94865-MS.
Jordan, M.M., Collins, I.R., and Mackay, E.J. 2006a. Low Sulfate Seawater Injection for Barium Sulfate Scale Control: A Life-of-Field Solution to a Complex Challenge. Presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 15-17 February. SPE-98096-MS. http://dx.doi.org/10.2118/98096-MS.
Jordan, M.M., Johnston, C.J., and Robb, M. 2006b. Evaluation Methods for Suspended Solids and Produced Water as an Aid in Determining Effectiveness of Scale Control Both Downhole and Topside. SPE Prod & Oper 21 (1): 7-18. SPE-92663-PA. http://dx.doi.org/10.2118/92663-PA.
Kan, A. and Tomson, M. 2012. Scale Prediction for Oil and Gas Production. SPE J. 17 (2): 362-378. SPE-132237-PA. http://dx.doi.org/10.2118/132237-PA.
Li, Y.-H., Crane, S.D., and Coleman, J.R. 1995. A Novel Approach to Predict the Co-Precipitation of BaSO4 and SrSO4. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, USA, 2-4 April. SPE-29489-MS. http://dx.doi.org/10.2118/29489-MS.
Liu, S.-T. and Nancollas, G.H. 1971. The kinetics of dissolution of calcium sulfate dihydrate. J. Inorg. Nucl. Chem. 33 (8): 2311-2316. http://dx.doi.org/10.1016/0022-1902(71)80205-1.
Mackay, E.J. and Jordan, M.M. 2005. Impact of Brine Flow and Mixing in the Reservoir on Scale Control Risk Assessment and Subsurface Treatment Options: Case Histories. J. Energy Resour. Technol. 127 (3): 201–213. http://dx.doi.org/10.1115/1.1944029.
Mackay, E.J., Collins, I.R., Jordan, M.M. et al. 2003. PWRI: Scale Formation Risk Assessment and Management. Presented at the International Symposium on Oilfield Scale, Aberdeen, 29–30 January. SPE-80385-MS. http://dx.doi.org/10.2118/80385-MS.
Mahmoud, M.A. and Bageri, B.S. 2013. A New Diversion Technique to Remove the Formation Damage from Maximum Reservoir Contact and Extended Reach Wells in Sandstone Reservoirs. Presented at the SPE European Formation Damage Conference & Exhibition, Noordwijk, The Netherlands, 5-7 June. SPE-165163-MS. http://dx.doi.org/10.2118/165163-MS.
Mahmoud, M.A., Nasr-El-Din, H.A., and De Wolf, C. 2011a. Novel Environmentally Friendly Fluids to Remove Carbonate Minerals from Deep Sandstone Formations. Presented at the SPE European Formation Damage Conference, Noordwijk, The Netherlands, 7-10 June. SPE-143301-MS. http://dx.doi.org/10.2118/143301-MS.
Mahmoud, M.A., Nasr-El-Din, H.A., De Wolf, C. et al. 2011b. Sandstone Acidizing Using A New Class of Chelating Agents. Presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, USA, 11-13 April. SPE-139815-MS. http://dx.doi.org/10.2118/139815-MS.
Mahmoud, M.A., Nasr-El-Din, H.A., De Wolf, C. et al. 2011c. Evaluation of a New Environmentally Friendly Chelating Agent for High-Temperature Applications. SPE J. 16 (3): 559-574. SPE-127923-PA. http://dx.doi.org/10.2118/127923-PA.
Martell, A.E., and Smith, R.M. 1982. Critical Stability Constants, Vol. 5. New York: First Supplement, Plenum Press.
McElhiney, J.E., Sydansk, R.D., Lintelmann, K.A. et al. 2001. Determination of In-Situ Precipitation of Barium Sulphate During Coreflooding. Presented at the International Symposium on Oilfield Scale, Aberdeen, 30-31 January. SPE-68309-MS. http://dx.doi.org/10.2118/68309-MS.
Moghadasi, J., Jamialahmadi, M., Müller-Steinhagen, H. et al. 2003a. Scale Formation in Iranian Oil Reservoir and Production Equipment During Water Injection. Presented at the International Symposium on Oilfield Scale, Aberdeen, 29-30 January. SPE-80406-MS. http://dx.doi.org/10.2118/80406-MS.
Moghadasi, J., Jamialahmadi, M., Müller-Steinhagen, H. et al. 2003b. Scale Formation in Oil Reservoir and Production Equipment during Water Injection (Kinetics of CaSO4 and CaCO3 Crystal Growth and Effect on Formation Damage). Presented at the SPE European Formation Damage Conference, The Hague, The Netherlands, 13-14 May. SPE-82233-MS. http://dx.doi.org/10.2118/82233-MS.
Nassivera, M. and Essel, A. 1979. Fateh Field Sea Water Injection - Water Treatment, Corrosion, And Scale Control. Presented at the Middle East Technical Conference and Exhibition, Bahrain, 25-28 February. SPE-7765-MS. http://dx.doi.org/10.2118/7765-MS.
Oddo, J.E., Smith, J.P., and Tomson, M.B. 1991. Analysis of and Solutions to the CaCO3 and CaSO4 Scaling Problems Encountered in Wells Offshore Indonesia. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 6-9 October. SPE-22782-MS. http://dx.doi.org/10.2118/22782-MS.
OLI. 2013. OLI ScaleChem, http://www.olisystems.com/new-scalechem.shtml.
Rakhimov, A.Z., Vazquez, O., Sorbie, K.S. et al. 2010. Impact of Fluid Distribution on Scale Inhibitor Squeeze Treatments. Presented at the SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, Spain, 14-17 June. SPE-131724-MS. http://dx.doi.org/10.2118/131724-MS.
Shen, J. and Crosby, C.C. 1983. Insight Into Strontium and Calcium Sulfate Scaling Mechanisms in a Wet Producer. J Pet Technol 35 (7): 1249-1255. SPE-10597-PA. http://dx.doi.org/10.2118/10597-PA.
Spriggs, D.M. and Hover, G.W. 1972. Field Performance of a Liquid Scale Inhibitor Squeeze Program. J Pet Technol 24 (7): 812-816. SPE-3545-PA. http://dx.doi.org/10.2118/3545-PA.
Tahmasebi, H.A. and Kharrat, R. 2007. Prediction of permeability reduction rate due to calcium sulfate scale formation in porous media. Presented at the SPE Middle East Oil and Gas Show and Conference, Kingdom of Bahrain 11-14 March. SPE-105105-MS. http://dx.doi.org/10.2118/105105-MS.
Tomson, M.B., Matty, J., and Oddo, J.E. 1990. Scale Inhibitor Evaluations And A Mechanism Of Inhibition Of Sparingly Soluble Salts. Presented at the Annual Technical Meeting, Calgary, 10-13 June. PETSOC-90-55. http://dx.doi.org/10.2118/90-55.
Vetter, O.J.G. 1975. How Barium Sulfate Is Formed: An Interpretation. J Pet Technol 27 (12): 1515-1524. SPE-4217-PA. http://dx.doi.org/10.2118/4217-PA.
Vetter, O.J.G. and Phillips, R.C. 1970. Prediction of Deposition of Calcium Sulfate Scale Under Down-Hole Conditions. J Pet Technol 22 (10): 1299-1308. SPE-2620-PA. http://dx.doi.org/10.2118/2620-PA.
Warren, E.A. and Pulham, A.J. 2001. Anomalous Porosity and Permeability Preservation in Deeply Buried Tertiary and Mesozoic Sandstones in the Cusiana Field, Llanos Foothills, Colombia. J. Sediment. Res. 71 (1): 2-14. http://dx.doi.org/10.1306/081799710002.
Yang, L., Guan, B., Wu, Z. et al. 2009. Solubility and Phase Transitions of Calcium Sulfate in KCl Solutions between 85 and 100 °C. Ind. Eng. Chem. Res. 48 (16): 7773-7779. http://dx.doi.org/10.1021/ie900372j.