8/19/2019 Ch#2 SPE 0600 0065 JPT Gas Steam

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8/19/2019 Ch#2 SPE 0600 0065 JPT Gas Steam

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66

JUNE 2000

H

eavy

Oil

H

eavy

Oil

The formation pressure was measuredat 2.47 MPa in a shut-in well approxi-mately 100 m from the injector.

Fluid Level. Fluid levels in productionwells were measured before and aftergas/steam injection and approximatelyone month after the gas/steam injec-tion was terminated. Of the six wellstested, three were shut-in, providing

static fluid levels. The static fluid lev-els above the formation had more thantripled, an indication that the forma-tion pressure increased because of gas/steam injection. The flowing fluidlevels in producing wells increased sig-nificantly also, which, in turn,increased well productivity.

Scaling Problem and Air-Compres-sor Failures. During the 65 days of operation, approximately 15 days werespent troubleshooting. Two major

problems were experienced: scaling of the nozzle and air-compressor failure.Scaling was caused by use of untreatedunderground water as feed water forthe generator. The problem was solvedby adding a water softener. Animproper design of the compressor ledto the high-pressure cylinder overheat-ing during operation.

Corrosion. It was anticipated thatCO2 in the gas/steam mixture wouldcause corrosion of the tubing string. Inthe gas-/steam-huff ‘n’ puff tests inthree completed pilot tests, corrosionwas not a problem. However, becausethe gas/steam tests ran for only eightdays during the huff ‘n’ puff process, itis too early to conclude that no corro-sion will occur. Also, the tubing stringhas not been pulled for inspection.Because CO2 corrosion is still a seriousconcern, use of a corrosion inhibitor isunder consideration.

Gas Channeling. Gas channeling wasfound in three wells during the later

period of the pilot test. Gas channelingwas not as severe as expected. Gasbreakthrough was observed in three of the wells during the last several days of gas/steam injection. Gas channelingdiminished after water-slug injection.

Severe gas channeling was encoun-tered in the second pilot test. Duringthe fourth day of gas/steam injection,N2 was found in a producer in anoth-er well group, approximately 300 mfrom the central injector. The majorreasons for gas channeling are low for-

mation pres-sure, high injec-tion rate, andheterogeneity of the reservoir.The large, unfa-vorable mobilityratio betweenthe injectedgas/steam and

the reservoir’smedium-heavyoil may beanother factor.High-perme-ability thief zones are expected in the formation.

In an attempt to solve early gas-channeling problems, a three-phase-foam profile modification was appliedin the third-well-group pilot. Foamwas injected before injecting thegas/steam slug. After foam injection,

the well was displaced with N2 and,as a result of the foam, gas channel-ing was not observed during thegas-/steam-slug-flood test for thiswell group.

Results and DiscussionPilot-test data indicate that the forma-tion pressure increased from 1 MPa toapproximately 3 MPa after gas-/steam-slug flooding in Well Group 43-530.Static fluid levels increased nearlythree times, while the producing-wellfluid levels increased by more than100 m. The four wells that had beenclosed because of low productivitybefore the gas/steam injection have allbeen put back on production. Thewater cut dropped from 84% at thebeginning of the test to 62% inSeptember 1999.

Oil production peaked in the firstmonth (March 1999) after terminatinggas/steam injection. Both the fluid andoil production decreased after thethree months of the pilot test. It isassumed that the decrease in fluid and

oil production is natural depletion.Hot-water injection started on 20 April1999, and oil production increasedsteadily after the water-injection step.The production stabilized four monthsafter water injection, which indicatesthe water injection hit its target.

 Water cut declined gradually afterwater injection. The pilot-test resultsindicate that the original design of thegas-/steam-slug process may providean alternative method to improve oilrecovery in the later life of a thermal

process for medium-heavy-oil reser-voirs. This technology can be econom-ically beneficial because of the lowcapital cost of equipment, substantialreduction in fuel cost, and increase inoil production.

Summary On the basis of the pilot tests in WellGroup 43-530 of Block Du66, thegas/steam technology seems feasible.Because of the technical success andeconomic benefit, the flue-gas-/steam-slug process has been applied to threeother well groups. The gas/steaminjection provided both heat andpotential energy for the reservoirs.Both static and flowing fluid levels inthe test wells increased significantly.

Oil production increased from1.8 Mg/d before the tests to a stabilizedrate of 15 Mg/d in December 1999 inthe pilot-test well group. Water cutdropped from 84% to 62%.

Hot-water injection following thegas/steam slug may maximize the ben-efits of the process. After water injec-tion, oil production increased steadily.

Corrosion may be a problem for theflue-gas/steam injection; therefore,protection (mitigation) should be con-sidered. Pilot tests in Liaohe field sitesindicate that the gas/steam generatorcan reduce the capital-equipment and

operating cost.Three-phase foams provided good

mobility control for gas channeling.However, gas channeling is a majorchallenge for the gas/steam oil-recov-ery process.

Please read the full-length paper foradditional detail, illustrations, and ref-erences. The paper from which the synopsis has been taken has not been peer reviewed.

Fig. 1—Simulation results of the gas/steam process for theBlock Du66 pilot. PV=pore volume.

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