Experimental Results of Polymer Flooding of Heavy Oil Reservoirs

Asghari, Koorosh; Nakutnyy, Petro

doi:10.2118/2008-189

Cited by 70 publications

(28 citation statements)

References 0 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Atsenuwa, et al classified heavy oil with viscosities that ranged from 50 to 50,000 cp, they pointed out that the capillary forces between water and heavy oil are higher than those between water and light oil [4]. Asghari and Nakutnyy carried out experimental work on the application of polyacrylamide for extracting heavy oil; they concluded that a polymer concentration in the injected fluid higher than 5000 ppm is required to effectively recover oil for injection rates of less than 29.6 m 3 /day [5]. Nevertheless, by using polymer with viscosities in the range of 2000-5000 cp to sweep the trapped oil by core-flood tests, Bodino et al observed an insignificant increase in the recovery factor when the viscosity of the polymer solution was changed from 3 to 60 cp [6].…”

Section: Introductionmentioning

confidence: 99%

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Van

Chon

2016

Energies

View full text Add to dashboard Cite

Heavy-oil resources represent a large percentage of global oil and gas reserves, however, owing to the high viscosity, enhanced oil recovery (EOR) techniques are critical issues for extracting this type of crude oil from the reservoir. According to the survey data in Oil & Gas Journal, thermal methods are the most widely utilized in EOR projects in heavy oil fields in the US and Canada, and there are not many successful chemical flooding projects for heavy oil reported elsewhere in the world. However, thermal methods such as steam injection might be restricted in cases of thin formations, overlying permafrost, or reservoir depths over 4500 ft, for which chemical flooding becomes a better option for recovering crude oil. Moreover, owing to the considerable fluctuations in the oil price, chemical injection plans should be employed consistently in terms of either technical or economic viewpoints. The numerical studies in this work aim to clarify the predominant chemical injection schemes among the various combinations of chemical agents involving alkali (A), surfactant (S) and polymer (P) for specific heavy-oil reservoir conditions. The feasibilities of all potential injection sequences are evaluated in the pre-evaluation stage in order to select the most efficient injection scheme according to the variation in the oil price which is based on practical market values. Finally, optimization procedures in the post-evaluation stage are carried out for the most economic injection plan by an effective mathematic tool with the purpose of gaining highest Net Present Value (NPV) of the project. In technical terms, the numerical studies confirm the predominant performances of sequences in which alkali-surfactant-polymer (ASP) solution is injected after the first preflushing water whereby the recovery factor can be higher than 47%. In particular, the oil production performances are improved by injecting a buffering viscous fluid right after the first chemical slug rather than using a water slug in between. The results of the pre-evaluation show that two sequences of the ASP group have the highest NPV corresponding to the dissimilar applied oil prices. In the post-evaluation, the successful use of response surface methodology (RSM) in the estimation and optimization procedures with coefficients of determination R 2 greater than 0.97 shows that the project can possibly gain 4.47 $MM at a mean oil price of 46.5 $/bbl with the field scale of a quarter five-spot pattern. Further, with the novel assumption of normal distribution for the oil price variation, the chemical flooding sequence of concurrent alkali-surfactant-polymer injection with a buffering polymer solution is evaluated as the most feasible scheme owing to the achievement of the highest NPV at the highly possible oil price of 40-55 $/bbl compared to the other scheme.

show abstract

Section: Introductionmentioning

confidence: 99%

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Van

Chon

2016

Energies

View full text Add to dashboard Cite

show abstract

“…In the course of water flooding in conventional heavy oil reservoirs, with an increase in water saturation, the water/oil mobility ratio will increase as well, resulting in a much higher increase in the water cut in heavy oil reservoirs than in light oil reservoirs (Kumar et al 2005;Asghari and Nakutnyy 2008;Aktas et al 2008;Mogbo 2011;Morelato et al 2011;Liu et al 2012). Influenced by such factors as reservoir heterogeneity, the polymer flood was initiated when the water cut of the produced fluids reached 60 % for the SZ36-1 oil field, and the oil recovery factor increased by only 5-7 % due to polymer floods (Zhang et al 2007(Zhang et al , 2009Jiang et al 2010;Kang et al 2011), which was lower than that in the onshore light crude reservoirs (Asghari and Nakutnyy 2008).…”

Section: Introductionmentioning

confidence: 99%

“…Influenced by such factors as reservoir heterogeneity, the polymer flood was initiated when the water cut of the produced fluids reached 60 % for the SZ36-1 oil field, and the oil recovery factor increased by only 5-7 % due to polymer floods (Zhang et al 2007(Zhang et al , 2009Jiang et al 2010;Kang et al 2011), which was lower than that in the onshore light crude reservoirs (Asghari and Nakutnyy 2008). Meanwhile, the largest difference between onshore and offshore oil production is that the design service life of an offshore platform is less than 30 years (Rivas and Gathier 2013).…”

Section: Introductionmentioning

confidence: 99%

Research into polymer injection timing for Bohai heavy oil reservoirs

et al. 2015

View full text Add to dashboard Cite

Polymer flooding has been proven to effectively improve oil recovery in the Bohai Oil Field. However, due to high oil viscosity and significant formation heterogeneity, it is necessary to further improve the displacement effectiveness of polymer flooding in heavy oil reservoirs in the service life of offshore platforms. In this paper, the effects of the water/oil mobility ratio in heavy oil reservoirs and the dimensionless oil productivity index on polymer flooding effectiveness were studied utilizing relative permeability curves. The results showed that when the water saturation was less than the value, where the water/oil mobility ratio was equal to 1, polymer flooding could effectively control the increase of fractional water flow, which meant that the upper limit of water/oil ratio suitable for polymer flooding should be the value when the water/oil mobility ratio was equal to 1. Mean while, by injecting a certain volume of water to create water channels in the reservoir, the polymer flooding would be the most effective in improving sweep efficiency, and lower the fractional flow of water to the value corresponding to D J max . Considering the service life of the platform and the polymer mobility control capacity, the best polymer injection timing for heavy oil reservoirs was optimized. It has been tested for reservoirs with crude oil viscosity of 123 and 70 mPa s, the optimum polymer flooding effectiveness could be obtained when the polymer floods were initiated at the time when the fractional flow of water were 10 % and 25 %, respectively. The injection timing range for polymer flooding was also theoretically analyzed for the Bohai Oil Field utilizing relative permeability curves, which provided methods for improving polymer flooding effectiveness.

show abstract

“…These give rise to viscous fingering or, in heterogeneous formations, to channeling through high permeability streaks (Selby et al, 1989). Polymer helps overcoming these effects resulting in substantially high incremental oil recovery factors (Asghari and Nakutnyy, 2008;Gao, 2011).…”

Section: Introductionmentioning

confidence: 99%

Pressure Behavior and Fracture Development During Polymer Injection in a Heavy Oil Saturated Unconsolidated Sand

2015

View full text Add to dashboard Cite

Polymer injection into unconsolidated sand-packs saturated with either brine or model medium-heavy oil was investigated using a bore-hole simulator (BHS). The high-pressure vessel of this apparatus enables fluid injection under radial or spherical flow regimes into porous specimens having diameter 40 cm and height up to 60 cm and at typical reservoir axial and radial stresses, i.e. up to 40 and 60 MPa respectively. We found that injectivity into heavy oil saturated sand-pack drops steeply to a minimum and then increases again rapidly before leveling off to a plateau. This behavior is in stark contrast with water or polymer injection into water saturated sand-packs, where constant injectivity is established after a rather short transient increase. The behavior of polymer injection into the oil saturated sand-pack strongly supports the idea of the stimulation of the near-wellbore area even though post-mortem visual observations of the porous sample it did not reveal open hydraulic fractures.

show abstract

Experimental Results of Polymer Flooding of Heavy Oil Reservoirs

Cited by 70 publications

References 0 publications

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

Research into polymer injection timing for Bohai heavy oil reservoirs

Pressure Behavior and Fracture Development During Polymer Injection in a Heavy Oil Saturated Unconsolidated Sand

Contact Info

Product

Resources

About