1887

Abstract

Abstract

Substantial hydrocarbon reserves remain trapped in reservoirs that are characterized as tight, oil-wet, and fractured. The aforementioned reservoir characteristics are typical to shale formations, and significantly degrade hydrocarbon recovery efficiency because of well productivity, in addition to reservoir, capillary and sweep displacement efficiencies. In this paper an emphasis is made on identifying the governing reservoir force in tight oil formations at various development stages. The literature review in this paper captures scaling groups for capillary imbibition and several wettability modifiers. This is followed by an analysis, of scaling group limitations and the performance of wettability modifiers. A reservoir simulation model is built to evaluate capillary and viscous effects on oil recovery. Subsequently guidance for optimal reservoir development options is presented.

The optimization of well completion and well stimulation has significant impact on well productivity. It is noticed that there may be trade-off in tight formations between the dominance of viscous forces and the significance of decreasing capillary pressures. Although there is an increase in oil production rate, the cumulative oil production decreases slightly in all water wet conditions. The five well patterns can be categorized into well patterns comprising of three wells (shown in Figures 6a and 6c ) and six wells (shown in Figures 6b , 6d and 6e ). The highest cumulative oil production is well pattern ( Figure 6a ) duration 7 months, followed by well pattern ( figure 6e ) duration 3 months.

Oil-wet reservoirs hold considerable quantities of residual oil. However, during early development commercial quantities of available oil saturation are present in carbonate formations and pose low capillary pressures. Viscous forces govern oil recovery in tight oil formations during the initial stages of development (So >> Sor). Therefore, measures taken to reduce or overcome viscous forces yields higher incremental oil recovery compared with other reservoir forces. The precedence of well patterns should focus on well positioning rather than number of wells and operational expediency in managing draw-downs. Future work will evaluate the use intelligent completion technology to allow selective fractures stages in the horizontal well to undergo surfactant and low salinity water treatment by diffusion process during the well lifetime.

Loading

Article metrics loading...

/content/papers/10.2118/167742-MS
2014-02-25
2024-02-23
Loading full text...

Full text loading...

References

  1. Aladasani, A. and Bai, B.
    (2012a). Investigating Low Salinity Water Flooding Recovery Mechanism(s) in Sandstone Reservoirs: A Parametric Study Using Reservoir Simulation and Statistical Analysis. Proceedings of the 18th SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 14–18 April, SPE 152997.
    [Google Scholar]
  2. Aladasani, A., Bai, B. and Wu, Y.
    (2012b). Investigating Low-Salinity Water Flooding Recovery Mechanism(s) in Carbonate Reservours. Proceedings of the 2012 SPE EOR at Oil and Gas West Asia, Muscat, Oman, 16–18 April, 2012, SPE 155560.
    [Google Scholar]
  3. Bernard J.Bourbiaux and Francols J.Kalaydjian, Inst. Francais du Petole.
    Experimental Study of Cocurrent and Countercurrent flows in Natural Porous Media. Proceedings of the Annual Technical Conference and Exhibition, Houston, Texas, October 2–5, 1988, SPE 18283.
    [Google Scholar]
  4. C. U.Hatiboglu, SPE and T.Babadagli, SPE U. of Alberta.
    Primary and Secondary Oil recovery From Different Wettability Rocks by Countercurrent Diffusion and Spontaneous Imbibition. Proceedings of the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, 22–26 April, 2006, SPE 94120.
    [Google Scholar]
  5. C. U.Hatiboglu, SPE and T.Babadagli, SPE U. of Alberta
    . Experimental Analysis of Primary and Secondary Oil Recovery from Matrix by Counter-Current Diffusion and Spontaneous Imbibition. Proceedings of the SPE Annual Technical Conference and Exhibition, Houston, Texas, 26–29 September, 2004, SPE 90312.
    [Google Scholar]
  6. D.D.Cramer, BJ-Titan Services.
    Reservoir Characterization and Stimulation Techniques in the Bakken Formation and Adjacent Beds, Billings Nose Area, Williston Basin. Proceedings of the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers, Billings, Montana, May 19–21, 1986, SPE 15166.
    [Google Scholar]
  7. DongmeiWang, RayButler, and JinZhang, University of North Dakota; and RandySeright, New Mexico Petroleum Recovery research center/New Mexico Tech.
    Wettability Survey in Bakken Shale With Surfactant-Formulation Imbibition. Proceedings of the Eighteenth SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 14–18 April 2012, SPE 153853.
    [Google Scholar]
  8. D.Zhou, Chevron Petroleum Technology Co., L.Jia, Stanford University, J.Kamath, Chevron Petroleum Technology Cp. and A. R.Kovscek, SPE Members
    . An Investigation of Counter-Current Imbibition Processes in Diatomite. Proceedings of the SPE Western Regional Meeting, Bakersfield, California, 26–30 March, 2001, SPE 68837.
    [Google Scholar]
  9. E. J.Hognesen, SPE, S.Strand, SPE, and T.Austad, SPE, U. of Stavanger
    . Waterflooing of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition. Proceedings of the SPE Europec/EAGE Annual Conference, Madrid, Spain, 13–16 June 2005, SPE 94166.
    [Google Scholar]
  10. GauravSharma, Kishore K.Mohanty, University of Texas at Austin
    . Wettability Alteration in High Temperature and High Salinity carbonate Reservoirs. Proceedings of the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 30 October–2 November, 2011, SPE 147306.
    [Google Scholar]
  11. J.Chen, M.A.Miller and K.Sepehrnoori, The University of Texas, Austin, TX.
    Theoretical Investigation of Countercurrent Imbibition in Fractured Reservoir Matrix Blocks. Proceedings of the 13th SPE Symposium on Reservoir Simulation, San Antonio, Texas, 12–15 February 1995, SPE 29141.
    [Google Scholar]
  12. Kazemi, H., Gilman, J.R. and Elsharkawy, A. M.
    Analytical and Numerical Solution of Oil Recovery from Fractured Reservoirs with Empirical Transfer Functions. SPERE (May 1992) 219.
    [Google Scholar]
  13. Ma, S., Morrow, N. R. and Zhang, X.
    Generalized Scaling of Spontaneous Imbibition Data for Strongly Water-Wet Systems. J. Petroleum Science and Technology, (1977) 18, 165.
    [Google Scholar]
  14. Mattax, C.C. and Kyte, J.R.
    Imbibition Oil Recovery from Fractured Water Driver Reservoirs. Trans. AIME (1962), 225, 177.
    [Google Scholar]
  15. P.Zhang and T.Austad, U. of Stavanger
    . Waterflooding in Chalk: Relationship Between Oil Recovery, New Wettability Index, Brine Composition and Cationic Wettability Modifier. Proceedings of the SPE/EAGE Annual Conference, Madrid, Spain, 13–16 June 2005, SPE 94209.
    [Google Scholar]
  16. RobinGupta, P. GriffinSmithJr., LuHu, Thomas W.Willingham, Mauro LoCascio, J. JaneShyeh, and Chad R.Harris ExxonMobil Upstream Research Co.
    Enhanced Waterflood for Middle East Carbonate Cores–Impact of Injection Water Composition. Proceedings of the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25–28 September, 2011, SPE 142668.
    [Google Scholar]
  17. T.Babadagli, SPE, University of Alberta
    . Analysis of Oil Recovery by Spontaneous Imbibition of Surfactant Solution. Proceedings of the SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, 20–21 October 2003, SPE 84866.
    [Google Scholar]
  18. T.Babadagli, SPE, Sultan Qaboos University
    . Scaling of Co-Current and Counter-Current Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs. Proceedings of the SPE/AAPG Western Regional Meeting, Long Beach, California, 19–23 June, 2000, SPE 62848.
    [Google Scholar]
  19. Zhang, X., Morrow, N. and Ma.S.
    Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition. SPERE (Nov. 1996), 273.
    [Google Scholar]
http://instance.metastore.ingenta.com/content/papers/10.2118/167742-MS
Loading
/content/papers/10.2118/167742-MS
Loading

Data & Media loading...

This is a required field
Please enter a valid email address
Approval was a Success
Invalid data
An Error Occurred
Approval was partially successful, following selected items could not be processed due to error