Air Injection - Cost Effective IOR Method to Improve Oil Recovery from Depleted and Waterflooded...

Copyright 1998, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE Asia Pacific Improved Oil RecoveryConference (APIORC), 25-26 October 1999.This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, as presented,have not been reviewed by the Society of Petroleum Engineers and are subject to correction by theauthor(s). The material, as presented, does not necessarily reflect any position of the Society ofPetroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject topublication review by Editorial Committees of the Society of Petroleum Engineers. Electronicreproduction, distribution, or storage of any part of this paper for commercial purposes without thewritten consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in printis restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstractmust contain conspicuous acknowledgment of where and by whom the paper was presented. WriteLibrarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractIn the past air injection has found a wide application as arecovery method of heavy oil. Air injection into light oilreservoirs is a different process than heavy oil combustion.Significant increase in light oil production under air injectioncan be achieved with enhancement to the economics. The mainagent of the process is air which can be regarded as aninexpensive and easily available. A total consumption of 5 to10% of the remaining oil in place can be expected to maintain apropagation of the in-situ oxidation process. The flue gas andsteam generated at the combustion front are stripping, swellingand heating contacted oil. The light oil is displaced at near-miscible conditions with complete utilization of injected oxygen.The process can lead to a high recovery within a relativelyshort period of time. The process can potentially result in allremaining oil in place being produced. The propagation of thecombustion and displacement fronts in the reservoir can besometimes uncertain. Monitoring and control of combustionfront movement is important.The potential of air injection process for an offshore field in theNorth Sea was evaluated. A simulation reservoir modelaccounting for chemical reactions, stochiometry and thermalaspects of the combustion process was used. History matchsimulations of the combustion tube experiments calibrated thefluid description in the simulation model. Application of airinjection as primary, secondary and tertiary oil recoveryprocess was evaluated. The simulation results showed a highefficiency of air injection if applied at a late stage of fieldproduction. Secondary air injection potential to improve oilrecovery after depletion was estimated at 10% of STOOIP incomparison with secondary waterflooding, while tertiary air

injection was estimated to improve waterflooding by additional5% of STOOIP. Air injection in the light oil reservoirs at late ormature production stage will increase oil recovery at low extracost and extend the economic life of the fields.

IntroductionAir injection and the resulting in-situ combustion recoverymethod is a technology, which has found a quite wideapplication as Enhanced Oil Recovery (EOR) method in manycountries [1-5]. The main agent of the process is air, which canbe regarded today as inexpensive and easily available. A totalconsumption of 7 to 10% of oil in place can be expected tomaintain a propagating in-situ combustion/oxidation process.The combustion front is moving behind the oil displacementfront. The CO2 and steam generated at the combustion front aremobilizing residual oil as well as stripping, swelling and heatingcontacted oil. The oil with reduced viscosity is more easilymoved towards production wells. The process can lead to ahigh recovery within a relatively short time period by achievingvery high displacement efficiency. In-situ combustionaccelerates oil production and can potentially result in allremaining oil in place being produced from the region swept byair. The propagation of the combustion and displacement frontsin the reservoir can be sometimes uncertain. Monitoring andcontrol of combustion front movement is important. Prematurebreakthrough of flue gas in production wells can causeexploitation problems (communication, corrosion,environmental aspects etc.) [4-5]. Simulations with accuratehandling of the combustion reactions at reservoir conditionsallow evaluating and designing the efficient field application ofthe process [6-7].

In-situ combustion in light oil reservoirs has been testedpreviously on several fields and was proven to have animportant potential to improve oil recovery if applied afterdepletion or after water flooding. The air injection is apromising future EOR method for many North Sea reservoirs.Offshore application of air injection can open new applicabilityscale for this process.

SPE 57296

Air Injection - Cost Effective IOR Method to Improve Oil Recovery fromDepleted and Waterflooded FieldsLeonid M. Surguchev, RF - Rogaland Research, Alexander Koundin, PETEC Software & Services AS andDemetrios Yannimaras, BP-Amoco

2 SURGUCHEV, L., KOUNDIN, A. AND YANNIMARAS D. SPE 57296

Air Injection in Light Oil Reservoirs

Air injection in light oil reservoir can be implemented assecondary after depletion or tertiary after waterfloodingrecovery process. Light oil reservoirs are usually deep enoughand hot enough, that spontaneous ignition and combustion ofthe in-situ hydrocarbons occur following air injection. Theignition delay time for the reservoir with temperatures above150-200oF could be in the range of several hours.

The important processes contributing to the improved oilrecovery by air injection in light oil reservoirs are [4]:

- stripping and vaporizing of oil by generated CO2,

- swelling of the oil by combustion gases and possiblemiscibility effects,

- oil banking and improved sweep,

- pressurization and voidage replacement,

- reduction of oil viscosity due to increasing temperature.

The Air-Oil-Ratio characterizing the incremental oil productionobtained by air injection can vary typically in the range of 4000- 9000 scf /bbl.

Field Piloting

Although high temperatures are anticipated in the formationaround the injector during the ignition, or backflow and in theproducers during the final phase of the project, the tubing nextto the reservoir and the liners, most of the time is standard. Toensure well bore isolation high temperature cement can betailed in for several tens of meters above the reservoir. Thesecements are either those used in hot fluid injection, or calciumaluminate cements.

One of the most important items in completing an air injectionwell is to prevent tubing leaks. In general, injectors areequipped with premium connections and coated in someprojects. In those injectors where a water purge system isbeing used, the tubing is internally coated.

The injection well head is equipped with dual injection lines,one side for the air injection line and the other side for thepurge water (or nitrogen) line. The purpose of the purge watersystem is to load the injection wells with water or nitrogen, ifthere is an interruption in air injection. These serves to cool thenear well bore area, prevent back flow of hydrocarbons into thewell bore, and acts as a cushion between hydrocarbons and airwhen air injection resumes. The injection well head facilitiesalso include flowmeters (air and purge injection systems),scrubber, filter (cartridge type) and control valves for bothinjection systems.

Simulation Model

The potential of air injection process for a light oil chalk field inthe North Sea was evaluated in a simulation study. A modelrepresenting a 5-spot element of the field was used forsimulation of secondary and tertiary air injection processes.

The air injection process-specific parameters (chemicalreactions, stoichiometry coefficients and other) and fluiddescription was a light oil data set that has been usedsuccessfully in the past by Amoco to simulate in-situcombustion of light oils. History match simulations of acombustion tube experiment have been used to calibrate thesimulation model. The reservoir fluids in the model arecharacterized by nine components including water, nitrogen,oxygen, CO2, C5-C6, C7-C11, C12-C17, C18+ and residual coke.

The combustion process is simulated by five chemicalreactions characterized by reaction frequency and activationenergy:

1) Cracking of C12-C17 -> coke + C7-C11

2) Cracking of C18+ -> coke + C7-C11

3) Burning of C12-C17 + O2 -> WATER + CO2 + energy

4) Burning of C18 + O2 -> WATER + CO2 + energy

5) Burning of coke + O2 -> WATER + CO2 + energy

Air Injection Scenarios

Application of air injection as primary, secondary and tertiaryoil recovery processes was simulated. The description of thesimulated injection scenarios is given in Table 1. Productionperformance of these scenarios is shown in Table 2.

The simulation results showed a high efficiency of air injectionif applied after depletion and also after waterflooding. Thesimulation results are presented in Figures 1 - 12. Productionperformance characteristics for simulated injection/productionscenarios are shown in Figures 1-4. Air injection efficiency issignificantly higher than depletion and waterflooding. Underwater injection 77.1 MMBBLS of oil are produced after 35years. For comparison air injection cumulative oil production is95.8 MMBBLS, i.e. 11% of STOOIP higher than waterflooding.During in-situ combustion process only a small amount of oil isburned, while the rest is displaced, banked and produced. Theincreasing reservoir temperature and pressure due tocombustion process result in more efficient displacement ofhydrocarbons at reduced oil viscosity (Figures 5-8).

Tertiary application of air injection after waterflooding allowsto enhance waterflooding oil recovery by 5-7% of STOOIP.After 2 years of air injection, the production oil rate isincreased from 2700 to 6500 BOPD. The additional oilproduction in comparison with waterflooding is 6.6 MMBBLSin scenario 5. The injection of sea water cools the near well

SPE 57296 AIR INJECTION – COST EFFECTIVE IOR METHOD … 3

area from 268 °F down to 62 °F. The cooling of the reservoirnear injection well does not prevent the combustion reactionwhich takes place at a certain distance from injection well(Figures 5-8).

The movement of the oil displacing front is in conformancewith the reservoir properties in the element model of thereservoir (Figures 9-10). The allocation of air injection volumescan be used as a tool controlling the movement of thecombustion front and combustion gas propagation in thereservoir (Figures 11-12).

No attempt to optimize the injection/production strategy wasundertaken in this study. The injection and production wellswere perforated in the whole section of the thick productiveformation. Selective completion and recompletion of the wellscan considerably improve the sweep efficiency of the airinjection process.

Discussion

• Air injection with a total consumption of 7 to 10% of oil inplace accelerates oil production and enables to recover inthe ideal case all remaining oil in place. The combustionfront is moving behind the oil displacement front with fluegas and steam stripping, swelling, heating, reducingviscosity and moving oil towards the production wells. Atair injection the increased oil production can be achievedwithin a relatively short time period.

• The light oil of the deep and hot formation represents agood candidate for air injection. At these conditions aspontaneous combustion of the in-situ hydrocarbonsshould occur following air injection.

• The in situ generated flue gas (normally 85% N2 and 15%CO2) strips and extracts hydrocarbons from the reservoir.After the eventual gas breakthrough to the production wellthe produced gas composition can contain 2 US gallons ofNGL / 1000 scf flue gas produced and 150 scf C1&C2 / 1000scf flue gas produced. Two possible scenarios can beconsidered for the offshore field:

1. Separation of NGL’s and flaring of the resultingproduced gas. This scheme may not require any additionalCAPEX since the existing facilities can be used. Theenvironmental concerns and CO2 tax implications are theissues to be considered under this scheme.

2. Separation of NGL’s and re-injection of remaining gasinto the reservoir. This scheme can be a preferred option ifthe existing facilities can be used for re-injection of gas.

• The Air-Oil-Ratio characterizing the incremental oilproduction can vary typically in the range of 4000 - 9000 scf/bbl. Small (1000 BOPD) onshore light oil air injectionprojects are shown to generate an IRR of 13% to 24% underthe oil price environment that existed in the years 1985-

1995. For projects such as MPHU and W.Hackberry [6], thecapital expense ranged from 2.4 to 3.3 US dollars perincremental barrel of oil. NGL production, use of existingfacilities and other factors can significantly increase the PVof the project. Offshore projects have operating expensesclose to onshore projects, but capital requirements can behigher by 10-20% in average.

Conclusions• A thermal simulator accounting for processes and flow

mechanisms that arise in a reservoir under air injection wassuccessfully used in evaluating the light oil recoverypotential for a chalk offshore field in the North Sea.

• The simulated scenarios included depletion,waterflooding, air injection from the start, after depletionand after waterflooding.

• The oil recovery after 35 years production is in the rangeof 55-57% of STOOIP under air injection scenarios, 9-11%of STOOIP more than under waterflooding.

AcknowledgmentsDiscussions and recommendations from Ken J. Harpole,Phillips Petroleum, David Hicks and Lloyd Buchanan,Computer Modeling Group, are gratefully acknowledged.

References1. D.V. Yannimaras and D.L. Tiffin: “Screening of Oils for In-

Situ Combustion at Reservoir Conditions by Accelerating-Rate Calorimetry,” SPE Reservoir Engineering, February1995.

2. D.V. Yannimaras and J.L. Mustoni: “ImplementationConcepts and Experience with Field Air InjectionProjects,” EPTG, AMOCO, November 1996.

3. D.V. Yannimaras: “Air Injection Economics & the Effect ofProject Size,” EPTG, AMOCO, December 1996.

4. Musin, M.M., Diyashev, et. all: “Analysis of Pilot AreasDevelopment after In-situ Combustion”, Int. Conf.“Development of Hard-Accessible Oils and NaturalBitumens”, Kazan, Russia, 4-8 October 1994.

5. Surguchev, L.M.: "Assessment of the Efficiency ofThermal EOR Methods by the Use of Primary Resources",Proceedings of the Academy of Sciences EORConference, Baku, November 1987, 14 p.

6. Oballa, V., Coombe, D., Buchanan,W.L.: “FactorsAffecting the Thermal Response of Naturally FracturedReservoirs”, Can. J. Pet. Tech., Oct. 1993, p. 31.

7. Rubin, E., Buchanan, W.L.: “A General Purpose ThermalSimulator”, Society of Petroleum Eng. J., April 1985, p. 202.

8. Fasssihi, M.R., Yannimaras, D.V., Westfall, E.E., Gillham,T.H.: “Economics of Light Oil Air Injection Projects”,SPE35393, SPE/DOE IOR Symposium, Tulsa, April 1996.

TABLE 1 - AIR INJECTION SCENARIOS

Scenario Injection sequence Controlling parameters

1. Depletion 35 years min production well bhp=2762 psi, Qmax=20000 bbl/d

2. Waterflooding afterdepletion

30 years waterflooding after 5years depletion

min production well bhp=2762 psi, Qmax=20000 bbl/d

max water injection bhp=8500 psi, Qmax=2500 bbl/d

3. Air injection 35 years from production start min production well bhp=2762 psi, Qmax=20000 bbl/d

air injection well Qmax=8.7e6 scft/d max, bhp=8500 psi

4. Secondary air injection 30 years air injection after 5years depletion


air injection well Qmax=8.7e6 scft/d max, bhp=8500 psi

5. Tertiary air injection 7.5 years air injection after 5years depletion and 22.5 yearsof waterflooding


max water injection bhp=8500 psi, Qmax=2500 bbl/d

air injection well Qmax=8.7e6 scft/d

6. Tertiary air injection 20 years air injection after 5years depletion and 10 yearsof waterflooding


max water injection bhp=8500 psi, Qmax=2500 bbl/dair injection well Qmax=8.7e6 scft/d

TABLE 2 - AIR INJECTION SIMULATION RESULTS

Scenario Cumulative oil production,

MMBBLS

Oil recovery factor,

% of STOOIP*

Cumulative productionGOR,

scft/bbl

1. Depletion 15.43 9.14 -

2. Waterflooding after depletion 77.07 45.68 -

3. Air injection 95.80 56.78 2388

4. Secondary air injection 93.11 55.19 2402

5. Tertiary air injection 83.71 49.61 1509

6. Tertiary air injection 85.73 50.81 1882

* STOOIP - Stock Tank Oil Originally In Place


air.irf

0.000

4.000e+07

8.000e+07

Cumu

lative

Oil SC

(bbl)

0.000 20.00 40.00

Time (yr)

air injection from the beginningdepletionair injection after depletionair injection after waterfloodingwater injectionair injection after waterflooding

Fig. 1 - Comparison of cumulative oil production for various injection/production scenarios.

0.000

1.000e+04

2.000e+04

Oil Ra

te SC

(bbl/

day)

0.000 20.00 40.00

Time (yr)


Fig. 2 - Comparison of oil rates for various injection/production scenarios.


0.0

0.40

0.80

Water

Cut S

C

0.000 20.00 40.00

Time (yr)

air injection from the beginningdepletionair injection after depletionair injection after waterfloodingwater injectionair ijection after waterflooding

Fig. 3 - Comparison of water cut for various injection/production scenarios.

0.000

4000.

8000.

1.200e+04

Gas O

il Ratio

SC (ft

3/bbl)

0.000 20.00 40.00

Time (yr)


Fig. 4 - Comparison of GOR for various injection/production scenarios.


Fig. 5 - Temperature, 5 years of water injection. Depletion followed by water and air injection.

Fig. 6 - Temperature, 17 years of water injection. Depletion followed by water and air injection.


Fig. 7 - Temperature, 3 years of air injection. Depletion followed by water and air injection.

Fig. 8 - Temperature, 8 years of air injection. Depletion followed by water and air injection.


Fig. 9 - Oil saturation after 10 years of air injection. Air injection after depletion.

Fig. 10- Oil saturation after 30 years of air injection. Air injection after depletion.


Fig. 11 - Gas saturation after 10 years of air injection. Air injection after depletion.

Fig. 12 - Gas saturation after 30 years of air injection. Air injection after depletion.

Air Injection - Cost Effective IOR Method to Improve Oil Recovery from Depleted and Waterflooded...

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