Improved Water Flooding through Injection Brine Modification

Robertson, Eric P.; Thomas, C.P.; Morrow, Norman R.

doi:10.2172/910973

Cited by 15 publications

(11 citation statements)

References 12 publications

(21 reference statements)

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“…Numerous laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. [1][2][3][4][5][6] Many of these academic studies were conducted using core material and crude oil from a BP North Sea reservoir. The increase in oil recovery for low salinity water injection from this North Sea reservoir ranged from 10 to 40%.…”

Section: Introductionmentioning

confidence: 99%

Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

McGuire¹,

Chatham²,

Paskvan³

et al. 2005

SPE Western Regional Meeting

522

214

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractLaboratory studies conducted over a period of many years have indicated that oil recovery could be improved by injecting lower salinity water (less than about 5,000 ppm). Although the recovery mechanisms are still uncertain, they appear to be similar to those found in alkaline flooding. Recent successful field trials have led to serious evaluation of field-scale implementation of low salinity EOR.

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Section: Introductionmentioning

confidence: 99%

Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

McGuire¹,

Chatham²,

Paskvan³

et al. 2005

SPE Western Regional Meeting

522

214

View full text Add to dashboard Cite

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“…Although Robertson et. al 7 ( Fig. 2) did not use Minnelusa reservoir core in their experimentation set, they did show that a potential increase in oil recovery could be achieved by using diluted (lower salinity) injection water with Minnelusa oil and water and Berea sandstone.…”

Section: Selection Of Fields For Waterflood Comparisonmentioning

confidence: 99%

“…7 Average recovery curves from seven corefloods are plotted in Fig. 2 and show a clear increase in recovery from low-salinity waterfloods under simulated reservoir conditions.…”

Section: Introductionmentioning

confidence: 99%

Low-Salinity Waterflooding to Improve Oil Recovery-Historical Field Evidence

Robertson¹

2007

Proceedings of SPE Annual Technical Conference and Exhibition

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Waterflooding is by far the most widely applied method of improved oil recovery. Crude oil/water/rock interactions can lead to large variations in the displacement efficiency of waterfloods. Laboratory waterflood tests and single-well tracer tests in the field have shown that injection of low-salinity water can increase oil recovery, but work designed to test the method on a multi-well field scale has not yet been undertaken. Historical waterflood records could unintentionally provide some evidence of improved recovery from waterflooding with lower salinity water. Numerous fields in the Powder River basin of Wyoming have been waterflooded using low salinity water (about 1000 ppm) obtained from the Madison limestone or Fox Hills sandstone. Three Minnelusa formation fields in the basin were identified as candidates for waterflood comparisons based on the salinity of the formation and injection water and reservoir characteristics. Historical production and injection data for these fields were obtained from public records. Field waterflood data were manipulated to display oil recovery in the same format as laboratory coreflood results. Recovery from fields using lower salinity injection water was greater than that using higher salinity injection water-matching recovery trends for laboratory and singlewell tests. IntroductionAlmost without exception, at the start of a waterflood, water from the cheapest source (usually different in composition than the initial formation water) is used as the injection water, provided injectivity is not adversely affected by formation damage. Historically, little consideration has been given in reservoir engineering practice to the effect of the composition of the salt in the injection water on waterflood displacement efficiency or to the possibility of increased oil recovery through manipulation of the injection water composition. Most laboratory relative permeability tests and displacement tests are done using synthetic formation water as both the for-

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“…Guo and Morrow, 1999; Robertson et al, 2003;Lager et al, 2006;Zhang and Morrow, 2006). It is carried out here in reference to the low salinity CO 2 -WAG in this investigation.…”

Section: Effects Of Brine Salinitymentioning

confidence: 99%

Laboratory Investigation of Factors Affecting CO2 Enhanced Oil and Gas Recovery

et al. 2013

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A series of laboratory investigation on factors affecting Enhanced Oil and Gas Recovery and CO 2 geo-sequestration were conducted. The coreflooding experiments were done using a relatively heavy crude oil (18° API), a number of brines of 0.18%-2.5% NaCl and varieties of cores with a range porosity and permeability from 15% and 17 mD to 19% and 330 mD under some typical reservoir pressure-temperature condition of 1164-3300 psi and 50-83 °C. Factors affecting CO 2 enhanced oil and gas recovery including the effects of the petrophysical properties of the reservoir rocks, formation water salinity, reservoir pressure, the Minimum Miscibility Pressure (MMP), total volume (PV) injected and injection rate and gravity segregation.Excellent recovery factors in the range of 27%-34% Original Oil In Place (OOIP) and almost 100% gas recovery were achieved through immiscible and miscible CO 2 flooding. Some of the coreflooding experiments were monitored with a medical CT in real time. The coreflooding experiments have shown that (1) reservoir petrophysical properties with permeability difference of up to an order of magnitude do not affect the CO 2 EOR factor; (2) variable EOR can be achieved both at reservoir pressures below or above the CO 2 -oil MMP; (3) Incremental oil recovery is proportional to the pore volume (PV) of CO 2 injected up to 3PV; (4) No significant additional recovery was observed beyond the MMP; (5) CO 2 -Water alternating gas (WAG) flooding can be quite effective in EOR in terms of the less amount of CO 2 injected as compared to that for the single CO 2 -water flooding to achieve the same EOR; (6) there is no benefit to use low-salinity CO 2 WAG flooding; (7) the optimum injection rate in the laboratory is around 1 cc/minute. These finding may provide some useful insight and guide for the field application of CO 2 enhanced oil and gas recovery; (8) During enhanced gas recovery using supercritical CO 2 , gravity segregation may occur in some porous-permeable reservoir with denser supercritical CO 2 preferentially enter through the bottom of the reservoir.

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Improved Water Flooding through Injection Brine Modification

Cited by 15 publications

References 12 publications

Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

Low-Salinity Waterflooding to Improve Oil Recovery-Historical Field Evidence

Laboratory Investigation of Factors Affecting CO2 Enhanced Oil and Gas Recovery

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