Flow-Rate Behavior and Imbibition in Shale
- Dongmei Wang (University of North Dakota) | Raymond Butler (University of North Dakota) | Hong Liu (University of North Dakota) | Salowa Ahmed (University of North Dakota)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2011
- Document Type
- Journal Paper
- 485 - 492
- 2011. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.6.9 Coring, Fishing, 4.3.3 Aspaltenes
- Flow Behavior, Shale, EOR, Imbibtion
- 3 in the last 30 days
- 1,996 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, we are studying oil flow through and, especially, brine intake into shale to displace oil. Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre shale in North Dakota, USA. We studied porosity, permeability to oil, permeability to water, and spontaneous brine intake for the Pierre shale. We found that porosities for Pierre shale cores were relatively high--from 25 to 35%. Porosities for our measurements of Bakken cores averaged less than 3%. Bakken oil imbibed into dry Pierre shale cores (up to 5 mm in thickness) to the same extent as could be achieved by forced injection of oil (i.e., achieving the same oil saturations for both processes). Permeability to a clean mineral oil (Soltrol 130TM) was higher than for Bakken oil--apparently because of deposition of wax/asphaltenes/particulates on the Pierre core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3.32×10-5 to 2.19×10-4 md when injecting Bakken oil and from 4.85×10-4 to 2.34×10-3 md when injecting Soltrol 130. Permeability to Bakken oil for a Bakken core (with no water present) averaged 4.84×10-4 md. In Pierre shale and Bakken cores with thicknesses ranging from 0.65 to 5 mm, permeabilities were basically independent of flow rate, in agreement with expectations from the Darcy equation. Saline brine spontaneously entered into oil-saturated Pierre cores, yielding recovery values up to 41% of original oil in place (OOIP). During exposure to brine, our results indicated an increase in permeability--presumably by mineral dissolution during forced brine injection and by cracking (possibly caused by clay swelling) during spontaneous brine intake. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Before these studies, we feared that exposure to brine might reduce shale permeability because of clay swelling. The laboratory results will help during a current study of surfactant and brine imbibition in the Bakken formation.
|File Size||477 KB||Number of Pages||8|
Cheatham, C.A. and Nahm, J.J. 1990. Bit Balling in Water-Reactive ShaleDuring Full-Scale Drilling Rate Tests. Paper SPE 19926 presented at theSPE/IADC Drilling Conference, Houston, 27 February-2 March. http://dx.doi.org/10.2118/19926-MS.
Chen, Y.Q. and Li, Y. 2001. Petroleum Reservoir Engineering,38-51. ISBN 7-5021-3329-1.
Chenevert, M.E. and Sharma, A.K. 1993. Permeability and Effective PorePressure of Shales. SPE Drill & Compl 8 (1): 28-34;Trans, AIME, 295. SPE-21918-PA. http://dx.doi.org/10.2118/21918-PA.
Cramer, D.D. 1986. Reservoir Characteristics and Stimulation Techniques inthe Bakken Formation and Adjacent Beds, Billings Nose Area, Williston Basin.Paper SPE 15166 presented at the SPE Rocky Mountain Regional Meeting, Billings, Montana, USA, 19-21 May. http://dx.doi.org/10.2118/15166-MS.
Gosnold, W.D. 1990. Heat Flow in the Great Plains of the United States.J. of Geophysical Research 95 (B1): 353-374. http://dx.doi.org/10.1029/JB095iB01p00353.
Luffel, D.L., Hopkins, C.W., and Schettler, P.D. Jr. 1993. MatrixPermeability Measurement of Gas Productive Shales. Paper SPE 26633 presented atthe SPE Annual Technical Conference and Exhibition, Houston, 3-6 October. http://dx.doi.org/10.2118/26633-MS.
Luo, Y., Davidson, B., and Dusseault, M. 1996. Measurements In Ultra-lowPermeability Media With Time-varying Properties. Paper EUROCK-1996-157presented at the ISRM International Symposium (EUROCK '96), Turin, Italy, 2-5September.
Matthews, C.S. and Russell, D.G. 1967. Pressure Buildup and Flow Tests inWells. Monograph Series, SPE, Richardson, Texas, USA, 1.
Murphy, E.C., Nurdeng, S.H., and Bruce, J. 2009. North Dakota StratigraphicColumn. Bismark, North Dakota, USA: North Dakota Geological Survey.
Neuzil, C.E. 1993. Low fluid pressure within the Pierre Shale: A transientresponse to erosion. Water Resour. Res. 29 (7): 2007-2020.http://dx.doi.org/10.1029/93WR00406.
Osisanya, S.O. 1995. Estimation of Average Permeability of Shale fromSwelling Data. J Can Pet Technol 34 (8): 50-55. JCPT PaperNo. 95-08-05. http://dx.doi.org/10.2118/95-08-05.
Pitman, J.K., Price, L.C., and LeFever, J.A. 2001. Diagenesis and FractureDevelopment in the Bakken Formation, Williston Basin: Implications forReservoir Quality in the Middle Member. US Geological Survey Professional Paper1653, Version 1.0, US Geological Survey, Washington, DC.
Reyes, L. and Osisanya, S.O. 2002. Empirical Correlation of Effective StressDependent Shale Rock Properties. J Can Pet Technol 41 (12):47-53. JCPT Paper No. 02-12-02. http://dx.doi.org/10.2118/02-12-02.
Sanyal, S.K., Pirnie, R.M. III, Chen, G.O., and Marsden, S.S. Jr. 1972. ANovel Liquid Permeameter for Measuring Very Low Permeability. SPE J. 12 (3): 206-210. SPE-3099-PA. http://dx.doi.org/10.2118/3099-PA.
Tang, G.-Q. and Firoozabadi, A. 2002. Relative Permeability Modification inGas/Liquid Systems Through Wettability to Intermediate Gas Wetting. SPE ResEval & Eng 5 (6): 427-436. SPE-81195-PA. http://dx.doi.org/10.2118/81195-PA.