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Difference between revisions of "Wilmington field"

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[[Category:California]] [[Category:Heavy Oil]]
[[Category:California]][[Category:Heavy Oil]][[Category:5.4.1 Waterflooding]][[Category:Fields]]
[[Category:5.4.1 Waterflooding]]

Revision as of 11:07, 8 June 2015

The Long Beach Unit (LBU) area of the Wilmington oil field (southern California, US) is mainly under the Long Beach harbor and contains more than 3 billion bbl of original oil in place (OOIP).[1][2][3] This oil field is a large anticline that is crosscut by several faults with displacements of 50 to 450 ft. It consists of seven zones between 2,500 and 7,000 ft true vertical depth subsea (TVDSS), the upper six of which are turbidite deposits of unconsolidated to poorly consolidated sandstone (1 to 1,000 md and 20 to 30% BV porosity) interbedded with shales. The gross thickness of 3,300 ft contains 900 ft of sandstone.


From its discovery in 1936 to the 1950s, most of the onshore portion of this oil field (the non-LBU area of the Wilmington oil field) was produced using the pressure-depletion oil-recovery mechanism. Because of this, there was significant surface subsidence—up to 29 ft, with some areas dropping from several feet above sea level to below sea level (but protected by dikes). Development of the LBU area was delayed until an agreement with the government was reached that required voidage-replacement waterflooding to be implemented from its beginning to prevent further subsidence. LBU was developed in the mid-1960s, with the directional drilling of more than 1,000 wells from four artificial islands and from the nearby pier area. The early completions consisted of gravel-packed slotted liners that were up to 1,000 ft long in the injectors and the producers.


In the largest zone, the Ranger (> 2 billion bbl of OOIP), the oils range from 14 to 21°API gravity and from 20- to 70-cp viscosity; hence, any waterflood would operate under a very unfavorable mobility ratio, and early water breakthrough would be expected. The LBU Ranger-zone waterflood was a 3:1 staggered line drive on a 10-acre well spacing (see Fig. 1); peripheral waterflooding has been used in the other zones. Oil production peaked in 1969 at 150,000 barrels of oil per day (BOPD). The oil production has declined slowly since then, and the water production rate has increased steadily over the years. Water has been injected at rates of up to 1 million barrels of water per day (BWPD). In 2002, production was approximately 32,000 BOPD at an average water cut of approximately 96%. To date, total production is > 940 million bbl of oil.

Optimizing the waterflood

As years of oil-production and water-production and -injection data were acquired, the field engineers determined that some of the initial well-completion practices needed to be changed. The early completion techniques caused thief zones to develop in the higher-permeability sands, so that the deeper sands could not be pumped off. Between 1979 and 1986, by the drilling of 450 new wells into the lower portions of the Ranger and Terminal zones, this massive interval was redeveloped as two or three separate intervals.[2] This subzoning added 160 million bbl of oil reserves and increased the field rate by 30,000 BOPD.

In 1991, an optimized waterflood program was undertaken to reduce the volume of produced water, recomplete wells in sands that were not being well swept by the waterflood, and drill new wells in selected locations to improve the performance of the waterflood.[3] Pattern surveillance was used to quantify areas with low water throughputs and to guide the selection of new well locations. To aid the optimization studies, detailed studies of the geology of the field were undertaken and some 3D-seismic data were acquired and interpreted. The 3D-seismic data significantly changed the understanding of orientation of some of the faulting patterns within the field area; the previous fault patterns had been developed from the data gathered during drilling of 1,200 directional wells and from interpretation of early 2D-seismic data. Also in thicker sands, more than 50 horizontal wells have been drilled to capture bypassed "attic" oil and banked oil along faults. This optimized waterflood program has added 125 million bbl of oil reserves and has the potential to add another 90 million bbl of reserves.

Over the past 30 years, the field engineers have monitored and modified the original waterflood design using the full variety of waterflood-analysis techniques, including bubble maps, log water/oil ratio (WOR) vs. cumulative-oil–production plots, X -plots, streamtube models, and numerical reservoir simulation for selected intervals within the Ranger zone over most of the LBU area.

Because of its very unfavorable mobility ratio, the LBU waterflood has undergone several decades of water injection and production with 80 to 97% water cuts (5 to 25 bbl water produced per bbl oil). The injected water has stripped considerable amounts of the dissolved solution gas from the oil in the reservoir sands. This is observed in the producing gas/oil ratios (GORs), which—if all the gas were assumed to be from the oil—would indicate that free gas is being produced along with the oil and water. Instead, what is happening is that each barrel of "dead" injected water that cycles through the reservoir sands is extracting 5 to 10 scf of gas per STB of reservoir oil. This causes the reservoir oil to contain less solution gas and to increase in viscosity as the waterflood progresses.

Ultimate recovery

Estimated ultimate-recovery factors for the LBU as of 2005 are shown in Table 1.

Overall, the LBU area of the Wilmington oil field has been a very successful waterflood of a lower-API-gravity, more-viscous oil. For much of the waterflood period, the water cuts have been high, 80 to 97%. The LBU waterflood has successfully prevented further surface subsidence.


  1. 1.0 1.1 Woodling, G.S., Taylor, P.J., Sun, H.H. et al. 1993. Layered Waterflood Surveillance in a Mature Field: The Long Beach Unit. Presented at the SPE Western Regional Meeting, Anchorage, 26–28 May. SPE-26082-MS.
  2. 2.0 2.1 ames, D.M., Mayer, E.H., and Scranton, J.M. 1967. Use of Economic and Reservoir Models in Planning the Ranger Zone Flood, Long Beach Unit, Wilmington Field. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, New Orleans, Louisiana, 1-4 October. SPE-1855-MS. Cite error: Invalid <ref> tag; name "r2" defined multiple times with different content
  3. 3.0 3.1 Robertson, J.A., Blesener, J.A., and Soo Hoo, S. 1987. Subzone Redevelopment of the Long Beach Unit, Wilmington Oil Field: A Case Study. J Pet Technol 39 (10): 1229-1236. SPE-15101-PA.

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