2. LITERATURE REVIEW
2.5 Field applications of polymer flooding
36 Mooney field, Canada
Both a polymer flood pilot (using HPAM initially, then associative polymer) and a sizable ASP flood (using associative polymer) were conducted at the Mooney field in Alberta. The oil field's reservoir consists of sandstone that is semi-consolidated and located near the shore. On average, the sandstone has a porosity of 26%, and a permeability of 1.5 darcies. The reservoir is thin with an average thickness of 4 m. The oil is heavy (12-19 API), and at the temperature of the reservoir (29°C), its viscosity ranges from 300 to 1,000 cp. Formation water has a 28.7 g/L TDS and over 300 ppm Ca2+ and Mg2+ concentration. With 200 ppm of Ca2+ and Mg2+, injection water has a slightly lower TDS of 20.3 g/L (Watson et al., 2014). Before the ASP flooding, lab work was conducted to select the polymer to be used, comparing standard HPAM and associative polymers. Except at low velocity, the use of the selected associative polymer led to higher resistance factor values compared to those obtained with the conventional high molecular weight HPAM. This appears to be somewhat troublesome since for better injectivity, it is preferable to have a lower viscosity at high velocity (near the wellbore). The rationale behind selecting an associative polymer for the Mooney ASP flood instead of a conventional HPAM, which would have been more compatible with respect to injectivity and mobility control, remains uncertain. According to the injection and production statistics (public data obtained from Geowebworks), after the ASP flooding with associative polymers, there was a definite increase in the oil rate and a little reduction in water-oil ratio (WOR). Determining with certainty whether the increase was due to the polymer, the alkali and surfactant, or their combination is difficult to ascertain.
Pelican Lake field, Canada
Starting from 2005-2006, the injection of polymer in the Pelican Lake field of Canada has been continuous, with a pilot followed by quick expansion. The polymer solution was injected into 900 wells that were positioned horizontally, and this injection occurred at a rate of 300,000 barrels each day. As a consequence of this injection, the oil production increased to 65,000 barrels per day. The polymer flood in the Pelican Lake field is the largest polymer flood to use horizontal wells and is also the largest polymer flood in heavy oil. The reservoir is characterized by a prograding shoreface with good petrophysical properties, including an average thickness of 5 meters, a porosity of 30%, and permeability up to 5000 millidarcy. In the locations targeted for polymer application, the oil viscosity is in the 1,500–10,000 cp range. Due to its shallowness (450 m), the reservoir's initial pressure and temperature are low (16 °C). The
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placement of the polymer flood wells in the field is designed in a line drive pattern, with the injection well and production well alternating. The field has been developed solely through the use of horizontal wells, likely due to the thin pay of the reservoir. According to Delamaide (2021), oil production grew along with the volume of polymer injection, and the WOR reduced.
By analyzing the average oil rate per well before and after the polymer injection, it is apparent that the oil rate increased by nearly 300% in 2011 after the flood. The injection of the polymer has allowed for a lower water-oil ratio while increasing the recovery factor for the flooded area of 3.0 billion bbl to over 20% of the OOIP. Since there is no information about the type of fluid injected (water or polymer) or when a well switches from water to polymer injection, it is quite challenging to fully illustrate the impact of the polymer injection.
Bockstedt Oil Field, Germany
Schizophyllan was injected into the Bockstedt oil field in Northern Germany, roughly 25 miles south of Bremen, for field testing. The reservoir is well-sorted and fairly homogeneous Dichotomites sandstone. The project area has a porosity of around 25% and the porosity ranges from 24% to 30%. The permeability ranges from 200 to 7,000 md, with an average value of roughly 2,000 md. The project area's reservoir heterogeneity is rated as moderate, with a Dykstra-Parsons Variation Coefficient of 0.52 to 0.58. The reservoir thickness for the project area is 50 ft. The reservoir contains lighter oil (24,7 – 29 API) with viscosity ranges between 11 – 29 mPa*s. Schizophyllan was tested in a lab with both reservoir brine and oil. There were no incompatibilities found. According to the analysis in the pilot project since the Schizophyllan injection, the production well's water cut trend has increased less steeply. After six to seven months of injection decline curve analysis reveals that the extrapolation of the trends already seen suggests that the injection of biopolymer results in a 25% greater recovery than the injection of water. Notwithstanding, my belief is that this discovery is preliminary in nature, and it is imperative to continue monitoring the behavior of all the wells.
Daqing field, China
The majority of the source bed in the Daqing Oilfield consists of Mesozoic Cretaceous sandstone from the continental facies, which is located around 900-1200 meters below the ground. This sandstone has a permeability of 500-1000 md and a porosity of 25-30%. The crude oil found in the oilfield is mainly paraffin-based and is characterized by a high wax content (20-30%), high freezing point (25-30°C), high viscosity (35 cP), API gravity ranging from 33-39°, and low sulfur concentration (around 0.11%). This field is exceptional since it is
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without a doubt the largest polymer flood ever recorded in a light oil reservoir. Since 1996, when polymer flooding made its first commercial field application, it has been successful.
According to a study by Okechukwu et al. (2021), the use of polymer in the Daqing oilfield resulted in an additional recovery of 12% of the OOIP. The knowledge acquired from the utilization of polymer in the Daqing field is that, contrary to conventional belief, polymer flooding not only affects sweep efficiency at a macroscopic level, but also reduces interfacial tension through its viscoelastic properties, resulting in improved oil recovery at a microscopic level, as demonstrated by researchers working in the Daqing oil field (Okechukwu et al., 2021).
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Table 2. Summary of field applications of polymer flooding.
№ Field Location Polymer used Reservoir Conditions Remarks Reference
1 East Bodo field, Canada
Associative polymer ϕ = 27–33%, k = 1,000 md, 14 API, 600–2,000 cp, 27 °C, 11,5 ft net pay,
formation water salinity 25–27 g/L, with 300–400 ppm of Ca2+ and 200–
250 ppm of Mg2+
There was an increase and stabilization of the oil rate after
the associative polymer flood expansion.
(Delamaide, 2020)
2 Mooney field, Canada
Polymer flood (HPAM and associative polymers) and
ASP flood (associative polymers)
ϕ = 26%, k = 1500 md, (300-1000 cp), (12-19 API), 29°C, 13 ft thickness, formation water salinity
28.7 g/L TDS and over 300 ppm Ca2+ and Mg2+
After the ASP flooding with associative polymers, there was a definite increase in oil rate and
a little reduction in WOR
(Delamaide, 2020)
3 Pelican Lake field, Canada
2-17 °C, k = 300-5000 mD, 12-14 API, 800-80000 cP, net pay 29,5 ft
Polymer injection has reduced the water-oil ratio and increased the recovery factor to over 20%
OOIP in the flooded area of 3.0 billion bbl.
(Delamaide, 2021)
4 Bockstedt oil field, Germany
Schizophyllan ϕ = 24-30%, k = 200-7000 md with average 2000 md, 50 ft thickness,
24,7–29 API, 11-29 cp
The analysis of decline curves indicates that biopolymer injection leads to a 25% higher
(Ogezi et al., 2014)
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recovery compared to water injection.
5 Daqing field, China
HPAM ϕ = 25–30%, k = 500–1000 md, wax content (20–30%), 35 cP, 33–39 API,
95-126 °C
It has proven that polymer application in the Daqing field
produces an extra 12% of the OOIP
(Okechukwu et al., 2021)
6 Bohai Bay, China
HPAM with the application of comprehensive adjustment
technology
High permeability, oil viscosity <
150 cP
Polymer flooding strategy is expected to boost oil production by 1.15 million m3 and increase recovery by 7.78% compared to
water flooding.
(Kang et al., 2022)
7 Giant
Kalamkas Oilfield, Kazakhstan
Polyacrylamide ϕ = 28%, k = 958 md, 38-43 °C, 9.18-9.53 MPa, 50-71% So, 23,3 cp,
The recovery factor increased – 1,6% and water cut decreased – 8,2% after the polymer flood
(Sagyndikov et al., 2018)
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