High Concentration Polymer Flooding is Successful

Abstract

Recently, new evidences show that the recovery factors of both partially hydrolyzed polyacrylamide (HPAM) and xanthan gum (XA) flooding increase with higher concentration and higher viscosity. However, when the incremental oil recovery of XA flooding in artificial cores reaches about 8.6% OOIP (original oil in place), the displacement efficiency of XA flooding levels of, but an incremental oil recovery of more than 20% OOIP can be obtained from HPAM flooding with a high concentration, the higher the concentration the higher the recovery, the recovery does not level of. The difference in recovery between the two solutions is due to the visco-elastic properties of HPAM. The visco-elastic property of HPAM fluid not only increases the volumetric sweep efficiency but also the displacement efficiency of the pay zone on a micro scale. A novel method has been developed to enhance the oil recovery in highly heterogeneous and high permeable reservoirs. The results on artificial cores with a Dykstra-Parson Coefficient of 0.72 show that an incremental recovery over water flooding of more than 20% OOIP can be obtained by early time injection of the high molecular weight, high concentration polymer solution, the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost. In Daqing Oil Field, a pilot test of high concentration polymer injectivity was conducted on 6 injection wells in August 2002. Three wells are injecting in high permeable pay zones and the other 3 wells in low permeable pay zones. The range of effective permeability (Keff) of the pay zones is 0.354 ~1.06 um2. The results show that high permeable formations (Keff>0.890um2) are suitable for continuous injection of high concentration polymer solutions (concentration 2,000 ppm ~2,500 ppm, molecular weight 17 million Daltons, viscosity 200~250 mPa.S). There were 22 oil wells around the 6 dispersive polymer injection wells. In February 2004, the average fluid production of each well was 90.2 tons per day, the average daily oil production of each well was 21.7 tons and average water cut was 79.5%. Compared to low concentration (1,000 ppm) solution flooding, the fluid production per day of each well remained and the daily oil production of each well increased by 3.4 tons (an increase of 18.6%) and the average water cut decreased by 1.0%.The average water cut decreased by a maximum of 7%.The results show that the injection of high concentration polymer fluid is very effective and the pilot area will be further expanded. Introduction Petroleum, as a kind of non-renewable resource, is the lifeblood of the national economic development. About 60~70% oil is remained in the formation after water flooding. How to produce the remained oil economically and efficiently has become a problem to be resolved by oil reservoir engineers all over the world. According to most literatures,[1–2] when polymer flooding, the capillary numbers, which can only increase about a dozens times, is less than the increment needed to recover the residual oil, therefore, polymer flooding can only improve the swept volume and not the swept efficiency. In recent years, many petroleum engineers[3–4] consider that polymer flooding can also improve microscopic oil displacement efficiency due to the visco-elastic properties of polymer solution. From results on artificial cores, Wang Demin, etc.[5] deemed that an incremental oil recovery over water flooding of more than 20% can be obtained by injecting high concentration polymer solution. The aim in the present research is to find a new technique which can greatly enhance oil recovery efficiencies. The results in labs and fields both show that high concentration polymer flooding can further improve oil recovery. This technique is significant to the increment of recoverable reserves and the sustainable development of oil fields.

Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling

“…(3) Interestingly, injection of more concentrated polymer solutions (2,000 -2,500 mg/L rather than 1,000 mg/L) did not result in substantially increased injection pressures. 140 This result suggests that fractures exist near the wells. If these fractures are extended during injection of the more viscous polymer solutions, increases in injection pressure will be mitigated.…”

“…140 For either a given polymer concentration or viscosity level, HPAM solutions provided significantly greater oil recovery levels under Daqing conditions. This result was believed to occur because HPAM solutions exhibited significantly greater viscoelasticity than xanthan solutions.…”

“…138 Furthermore, they impart greater solution viscoelasticity, which provides higher oil recoveries and lower residual oil saturations under Daqing conditions. 139 From the two pilot tests 140 at Daqing (specifically, at areas called "West of Center" and "4-4# Station of the Northwest in Lamadian"), the following observations were noted: (1) Water intake profile was improved after injecting higher polymer concentrations. (2) During polymer flooding, the period of relatively low water cuts can be prolonged by injecting higher polymer concentrations.…”

Data Analysis and Novel Screening Criteria for Polymer Flooding Based on a Comprehensive Database

“…According to Asghari and Nakutnyy (2008), a high polymer concentration (more than 5000 ppm) is required to increase heavy oil recovery. The increased elasticity of highly concentrated polymer results in an improvement in the displacement efficiency at the microscopic scale, yielding more than 20% incremental oil recovery after water flooding (Demin et al, 2001;Yang et al, 2004). Figure 4g illustrates the polymer slug size distributions, showing that the overall slug size in the HPAM subset ranges from 0.1 to 8 pore volume (PV), and the majority of slug sizes are in the range of 0 ~ 1 PV.…”

The Methods of Improving Polymer Flooding Performance at Northwest Area of Lamadian

“…Consequencely, favourable sweep volume and effectiveness can be obtained by utilization of polymer . [18][19][20][21][22] Based on the pre-flush dynamic behaivoir and the reservoir characteristics before the polymer injection at Northwest, 91 wells have been taken higher polymer concentration polymer injection. In the meanwhile, PI(90) value increased 162.4% from 5.35 MPa to 8.69 MPa .…”