Gas injection enhances recovery from polymer flood pilot

May 21, 2007
A field pilot showed that gas polymer, two-phase flooding could increase oil recovery from a low and intermediate permeable reservoir.

A field pilot showed that gas polymer, two-phase flooding could increase oil recovery from a low and intermediate permeable reservoir.

The combination of natural gas and polymer injection recovered about 10% more oil than with polymer injection alone after optimizing such parameters as the preflushing slug volume, polymer molecular weight, and injection rate. Because it has high mobility, natural gas can enter low permeability zones into which polymer cannot.

Other benefits seen from the test was a decrease in water cut in some oil-producing wells and the need to inject less polymer because natural gas replaced some polymer.

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Fig. 1 shows the injection scheme in the pilot.

Polymer flooding

Polymer flooding began in 1996 at Lamadian oil field. The field is a part of the Daqing complex of oil fields in Heilongjiang province of northern China.1-5

Polymer injection at Lamadian has had good results, increasing oil recovery and helping to maintain production rates. But because of reservoir heterogeneity, however, the field still has some oil-bearing layers with low oil recovery.

To improve the effect of polymer injection in low and intermediate permeability layers, a pilot test injected natural gas, more than 95% methane, along with polymer in the west area of northern Lamadian oil field.

Feasibility studies

Prior to the field pilot, laboratory tests verified the feasibility of injecting both natural gas and polymer. The tests included two plans: the first with polymer and the second with gas and polymer.

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Plan 1 (Fig. 2) had the following injection steps:

  • Water until reaching a 98% water cut.
  • A 0.3 pore volume (PV) of 1,000 mg/l. high molecular weight (MW) polymer solution.
  • A 0.34 PV of 1,000 mg/l. ultrahigh MW polymer solution.
  • Water until reaching again a 98% water cut.
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Injection steps in Plan 2 (Fig. 3) included:

  • Water until a 98% water cut.
  • A 0.3 PV of 1,000 mg/l. high-MW polymer solution.
  • Five slugs of 0.03 PV of 3,000 mg/l. ultrahigh MW polymer solution.
  • A 0.1 PV of natural gas.
  • A 0.05 PV of 1,000 mg/l. ultrahigh MW polymer solution.
  • 10 slugs of 0.03 PV of 5,000 mg/l. ultrahigh MW polymer solution.
  • A 0.1 PV of natural gas.
  • A 0.1 PV of 500 mg/l. ultrahigh MW polymer solution.
  • Water until reaching again a 98% water cut.

Plan 1 had a 56.88% recovery efficiency compared with 68.15% for Plan 2.

This result shows that with the same amount of polymer, gas polymer two-phase flooding improves recovery efficiency by 11.27% compared to polymer flooding.

Optimizing injection

Three experiments optimized the injection. All the tests used the same 640 PV and mg/l. of polymer.

One test showed that a higher gas-liquid ratio improves displacement. The test noted a 12.88% enhanced recovery for polymer flooding compared with waterflooding. Gas polymer two-phase flooding with a 0.4:1 gas-liquid ratio enhances oil recovery a further 18.54%. But with a 1:1 gas-liquid, gas polymer two-phase flooding ratio improves oil recovery by 22.21%.

Another test showed that increasing injection rate improves oil recovery for gas polymer two-phase flooding. With the same polymer amount and gas-liquid ratio, gas-polymer flooding with a normal injection rate increased recovery 12.1%. Gas-polymer flooding at a higher injection rate and constant pressure increased recovery by 13.59% compared with polymer flooding.

A third test showed that adding a slug of high-concentration polymer solution just before gas-polymer alternating injection and using intermediate-MW polymer for gas-polymer flooding further improves recovery.

The conclusion for the tests was that the best injection strategy was:

  • Water to a 98% water cut.
  • A 0.3 PV of 1,000 mg/l. high-MW polymer solution.
  • Five slugs of 0.03 PV of 3,000 mg/l. ultrahigh MW polymer solution.
  • A 0.1 PV natural gas.
  • A 0.05 PV of 1,000 mg/l. intermediate-MW polymer solution.
  • 10 slugs of 0.03 PV of 5,000 mg/l ultrahigh MW polymer solution.
  • A 0.1 PV of natural gas.
  • A 0.1 PV of 500 mg/l. intermediate-MW polymer solution.
  • Water to again reach a 98% water cut.

This plan can enhance oil recovery by 13.36% compared with polymer flooding.

These laboratory studies show that gas polymer two-phase flooding with parameters optimized enhanced oil recovery by more than 10% compared with polymer flooding.

Field application

The 90-acre pilot is near the No. 4-2 polymer injection station at Lamadian oil field. The injection targets the PI1-2 oil-bearing zone that has an average 50-ft gross and 47-ft effective thickness. The sand has an 8.22 million bbl pore volume and originally contained 5.66 million bbl of oil in place.

The pilot has a line-drive well pattern and an injector-producer spacing of 780 ft. It includes 13 wells of which 4 are injectors and 9 are producers.

The central well is on 22-acre spacing and the sand in the well is 39-ft thick. The sand in this area has a 1.81 million bbl pore volume and originally held 1.25 million bbl of oil.

The injection strategy included low salinity (less than 500 ppm) water and salt-resistant polymer with a MW of 25 million. Injection rate was 0.12 PV/year and gas-liquid ratio was 1:1.

The injection sequence consisted of 10 days of gas followed by 10 days of polymer solution in each of two stages.

Injected first was a 0.01 PV high-concentration preflushing slug of polymer solution. Then a slug of gas-polymer was injected, alternating gas injection and 1,000 mg/l. polymer solution.

From February 2001, 1,000 mg/l. polymer flooding was initiated in the pilot area.

Gas polymer two-phase flooding started on May 19, 2005. By the end of September 2005, well 7-P1900 and well 7-A1925 had completed four turns of gas-polymer injection, well 7-P1905 and well 7-P1920 had completed five turns of gas-polymer injection.

Total gas injected in these four wells was 106.4 MMscf of natural gas (0.81 MMcf at reservoir conditions), which is 0.018 of the pore volume at formation conditions.

Total polymer solution injected in these four wells was 223,000 bbl, which is 0.027 of pore volume at formation conditions.

Gas-liquid ratio for the completed injection was 0.67:1.

Evaluation results

The current liquid production from the nine producers is 6,409 b/d of which 739 b/d is oil production. The water cut is 89.9% and the polymer concentration in the produced liquid is 438 mg/l. Bottomhole pressure is 980 psi.

Compared with production when the wells had the highest water cut, liquid production has increased by 75 b/d, oil production has increased by 66 b/d, and water cut has decreased by 0.8%.

Well 7-P191 had seen the best results with Wells 7-P1928 and 7-P1988 also having good results.

Liquid production from Well 7-P191 is now 1,150 b/d, oil production is 219 b/d, and the water cut is 83.0%. Compared with the production before, liquid production has stayed the same, oil production has increased by 117 b/d, and the water cut has decreased by 9.1%.

Field tests show that injection pressure in all injectors is higher when gas injection first started. After tubing pressure and annular pressure equalized, the gas injection became stable and injection pressure decreased by 290-435 psi.

Tracers added to the injected gas in Well 7-1900 were noted in the produced fluids 8 days after being added. This throughput time is much faster than for polymer solution and indicates that gas has a faster displacing speed and greater transport ability then polymer in the low permeability reservoirs.

One economic benefit of using gas has been to reduce the amount of polymer needed. To date, the flood has uses about 20.4 tonnes less polymer.

Acknowledgment

This work described in this article was supported by the National Natural Science Foundation of China under Grant No. 50634020.

References

  1. Song Kao-Ping, Porous Flow Mechanism for Polymer Flooding, Beijing: Petroleum Industry Publishing House, April 1999.
  2. Xu Yun-Ting, Xu Qi, Guo Yong-Gui, and Yang Zheng-Ming, Study and Application of Mechanism of Porous Flow in Low Permeability Reservoir, Beijing: Petroleum Industry Publishing House, April 2006.
  3. Zhang Ji-Cheng, Liang Wen-Fu, Zhao Ling, Song Kao-Ping, and Gan Xiao-Fei, “Analysis of the Situation of Lamadian Oilfield at the High Water Cut Stage,” Journal of Daqing Petroleum Institute, Vol. 29, No. 3, June 2005, pp. 23-25.
  4. Wang De-Min, “Discussion on the 4 kinds of technologies influencing the sustainable development of Daqing Oilfield,” Petroleum Geology & Oilfield Development in Daqing, Vol. 21, No. 1, 2002, pp. 10-19.
  5. Wang Demin, et al. “A Pilot Polymer Flooding of Saertu Formation SII 10-16 in the North of Daqing Oil Field,” Paper No. SPE 37009, SPE Asia Pacific Oil and Gas Conference, Adelaide, Australia, Oct. 28-31, 1996.

The authors

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Zhang Ji-Cheng (zhangjc2006 @tom.com)is associate professor in the petroleum engineering department, Daqing Petroleum Institute, Daqing, China. His main focus is in research for oil and gas field developments.

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Shu Fang-Chun is an engineer with the 6th Oil Production Co., Daqing Oilfield Corp. Ltd. He is in charge of research and pilot tests of enhanced oil recovery techniques.