Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2000 SPE Permian Basin Oil and GasRecovery Conference held in Midland, Texas, 21–23 March 2000.

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AbstractCO2 miscible gas flooding is a popular method of improvedoil recovery. It is widely used in the Permian Basin.Asphaltene deposition in many of these systems is a costlyoperational problem associated with the utilization of thismethod of recovery. A CO2 flood in West Texas wasexperiencing major problems with asphaltene depositionrelated ESP failures and tubing plugging.

Operational procedures, field experience and a successfulchemical program have greatly reduced the cost of theseproblems over the last 3 years. A new inhibitor for continuouscapillary injection was recently developed and performed wellon live oil lab tests. To evaluate the field performance of thisnew asphaltene inhibitor, a wellhead side stream filter loopwas constructed to monitor asphalteneprecipitation/deposition. The objective was to measure andcompare the time needed to plug a given size filter withuntreated and chemical treated produced fluids. Pressure dataat the filter loop and wellhead was also recorded to monitorthe effectiveness of the treatments.

The field trial results proved the use of a filter-pluggingside stream was an effective way of assessing asphalteneinhibitor performance. Based on the filter plugging andwellhead pressure data, it was concluded that asphalteneprecipitation/deposition occurred if the produced fluid was notchemically treated. The standard field product usedsuccessfully in the past was able to reduce asphaltenedeposition and doubled the filter plugging time. The newasphaltene inhibitor was shown to be more effective forstabilizing the asphaltenes in the CO2 flooded produced fluids.

The new inhibitor extended the time needed to plug a filter bymore than four times as compared to untreated fluids.

Case history information, laboratory tests results, sidestream configuration, field test procedure and field test resultsare presented.

IntroductionAsphaltenes are heterocyclic unsaturated macromoleculesconsisting primarily of carbon, hydrogen, and a minorproportion of heteroelements such as oxygen, sulfur, nitrogenetc1,2. The amounts of carbon and hydrogen in asphaltenesvary over a very small range so that the H/C ratio is fairlyconstant at about 1.1-1.2, which is characteristic of a strongaromatic composition. Asphaltenes are typically defined bysolubility as benzene soluble and pentane or heptaneinsoluble1,2,3 .

The asphaltenes are believed to exist in the oil as acolloidal suspension, and are stabilized by resins adsorbed ontheir surface1. These higher molecular weight components ofcrude oil are normally in equilibrium at reservoir condition.As crude oil is produced this equilibrium may be disrupted bya number of factors including pressure reductions, crude oilchemical composition changes, introduction of miscible gasesand liquids, mixing with diluents and other oils, and duringacid stimulation, hot oiling and other oilfield operations. Theupset of the colloidal system may result in irreversibleflocculation of asphaltenes. The deposition and precipitationof flocculated asphaltenes can severely reduce thepermeability of the reservoir, cause formation damage and canalso plug-up the wellbore and tubing. The two primarymechanisms for asphaltene flocculation and deposition aredepressurizing of the oil and mixing of solvents with reservoiroil during enhanced oil recovery (EOR).

Miscible and immiscible flooding of crude oil reservoirsby solvents, e.g. CO2, NCL, LPG, and natural gas, is oftenused in enhanced oil recovery. However, the flooding processcauses a number of changes in the flow and phase behavior ofthe reservoir fluids and can significantly alter formationproperties. One such change is the precipitation of asphalteneswhich can adversely affect the productivity of the reservoirduring the course of oil recovery. During gas flooding of amiscible fluid, e.g. CO2, light hydrocarbon gases or other

SPE 59706

Asphaltene Inhibitor Evaluation in CO2 Floods: Laboratory Study and Field TestingY. Ralph Yin*, Andrew T. Yen and Sam Asomaning, Baker Petrolite Corporation

*SPE Member

2 Y. R. Yin, A. T. Yen and S. Asomaning SPE 59706

injection gases, gas is injected into the reservoir to displace theresidual oil left after water flooding and mobilize the oiltoward producing wellbores. Miscibility of the gas with thereservoir oil can also lead to the precipitation of asphaltenes inthe reservoir matrix. Most of the miscible solvents are capableof causing asphaltene flocculation and deposition. In general,as more gas dissolves into the crude oil, the more severe theasphaltene problem is 1,2,3,4,5.

Precipitation of asphaltenes can cause formation pluggingand wettability alterations which can lead to reduced recoveryefficiencies. In many cases, the precipitated asphaltenes canplug up the well tubing or can be carried to the well head,through the flowlines and into the separator and otherdownstream equipment causing expensive problems 1. Theplace where the asphaltene problem is most acute is perhaps inthe well bores and well tubing. Asphaltene deposition insidethe well not only can constrict the wells and result inproduction losses, but also can cause damage to downholeequipment, such as ESP and safety vales.

Presently asphaltenes are removed by mechanical methods,chemical cleaning or reservoir condition manipulation. Theassociated cost can be substantial and the hidden cost fromlost production and equipment damage can significantly affectthe economics of a producing field. Therefore, thedevelopment of a cost-effective method to control thedeposition of asphaltenes is of great importance to increase theoverall efficiency of the EOR fields with asphaltene problems.

Prevention of asphaltene deposition by the application ofchemical inhibitors has been studied extensively. Differentchemistries for asphaltene inhibition have been developed andevaluated. Chemical A was developed as an effectiveasphaltene dispersant to minimize asphaltene dropout evenafter flocculation. A successful program using Chemical Awas initially established and greatly reduced the cost ofasphaltene induced problems for a West Texas field over thelast two years. Since an important fact about asphaltenes isthey are deposited only after flocculation, it is evident thatavoiding asphaltene flocculation is the key to preventingasphaltene-induced problems 5. Therefore, a new asphalteneinhibitor Chemical B was recently developed to preventasphaltene flocculation. During a recent field trial in the sameWest Texas field, continuous capillary injection of ChemicalB was proven successful in asphaltene inhibition.

Lab Test Results

Both Chemical A and Chemical B were evaluated with high-pressure experiments performed in a D.B. Robinson (DBR)PVT cell equipped with a solids detection system (SDS) usingdownhole live oil samples from a West Texas well. Theversatility of the equipment lies in the fact that it simulates thebehavior and performance of asphaltene inhibitors as theyinhibit deposition under high pressure well bore conditions.The equipment can measure the onset pressure of asphalteneprecipitation, the bubble point of the crude oil, and the amountof asphaltenes deposited. The effectiveness of a chemical isdetermined by comparing the amount of asphaltene

precipitated and deposited on the walls of the cell after adepressurization experiment for both treated and untreatedsamples. Table 1 summarizes the results of Chemical A andChemical B at 2000 ppm on West Texas live oil. Theasphaltene deposited in the PVT cell was dissolved in 200 mLof toluene and was quantified by measuring the absorbance ofthe resulting solution at 440 nm. The asphaltene precipitated(but not deposited) was determined by filtration of the live oilafter depressurization . Percent inhibition is calculated base onthe following equation

% Inhibition=( Asp blank – Asp treated)/(Asp blank)x100.

Where Asp blank and Asp treated are amount of asphaltenerecovered after blank and treated runs respectively. Note thatamount of asphaltene deposited is directly proportional to theabsorbance reading. It is apparent that both Chemical A andChemical B reduce the amount of deposit and precipitatecompared to a blank run. The data also indicates that thenewly developed Chemical B is more effective than ChemicalA in preventing asphaltene deposition.

Chemical A Case HistoryA major producer conducts extensive petroleum productionoperations in the Permian Basin and throughout West Texas.As these oil fields have aged, the producer has employed CO2

flood enhanced recovery techniques to extract oil after waterflooding. However, One of the largest CO2 operations in WestTexas had been experiencing asphaltene deposition problemssince 1994 when the producer started the CO2 injectionprogram. Asphaltene deposition had caused the failure ofelectrical submersible pumps (ESP) and well tubing depositionseverely restricted the production flow. One well had to bepulled and asphaltene deposits were found in the lower 1800’of the tubing which had constricted the 2 7/8 inch ID tubing toabout ½ inch. A chemical treating program was established totreat about 20 wells which had showed signs of asphaltenedeposition in late 1997. The wells were batch treated once amonth with 25 gallons of Chemical A down the casing withbrine over flush. In late 1998, a continuous treating programwas established for a couple of the more problematic wells tocontrol the asphaltene problems. 150 ppm of Chemical Abased on the oil production rate, was pumped downholecontinuously though a capillary injection string. The injectionpoint of the capillary was just beneath the ESP. Since theestablishment of this continuous treating program, no moreESP failures or well plug-ups occurred in the treated wellsduring normal operations. The gradually declining productionrates were also stabilized, and in some cases, increased withhigher gas production. The production data of one of thetroublesome wells (Well A) is shown in Figure 1.

It is interesting to note that a severe well failure occurredrecently in one of the asphaltene problem wells because of anunexpected under-treatment. The continuous injectionprogram had to be switched back to batch treating once amonth because of a malfunctioning capillary injection string.Two months later, CO2 was injected constantly for a month

SPE 59706 ASPHALTENE INHIBITOR EVALUATION IN CO2 FLOODS: LABORATORY STUDY AND FIELD TESTING 3

instead of the regular 3-4 day water alternate gas (WAG)program. The well was then completely locked up and had tobe pulled. Asphaltene deposition was found in the ESP.Massive asphaltene deposits with heavy oil were also found inabout 300 yards of flowline which had to be replaced. Thisincident indicated that the continuous application of aninhibitor is much more effective than batch treating forasphaltene control in CO2 floods. When a chemical is appliedby batch, most of it will be produced out relatively quicklyand leave the well under-protected. For cases where CO2 wasinjected constantly, flocculated asphaltenes kept depositingand accumulating at the lowered inhibitor level without thewater flushing from a regular WAG pattern. As an unfortunateresult, the well was severely plugged-up under the combinedunder-treating conditions.

Chemical B Field TrialTo monitor the field performance of the new asphaltene

inhibitor Chemical B, a side stream filter loop was installed atthe wellhead of one of the capillary-ready wells (Well A). Theobjective was to monitor the extent and severity of asphaltenedeposition and evaluate the effectiveness of Chemical B. Thiswas achieved by measuring and comparing the time needed toplug a given size filter by untreated and chemically treatedproduced fluids.

The testing loop was constructed with 3/8” stainless steeltubing. It consisted of two pressure gauges, two chartrecorders, one in-line filter, one flowmeter and the requiredvalves and fittings as shown in Fig. 2. As produced fluidswould flow through the filter, the pressure difference acrossthe filter would increase as the filter would begin to plug. Thedown stream pressure would level off once the filter wastotally plugged. The time required to plug the filter wascalculated from the pressure data measured by the chartrecorders. Fig. 3 displays a picture of the actual field set-up.

Test Procedure:Four different pressure readings (wellhead pressure, filter up-stream pressure, filter down-stream pressure and casingpressure) were monitored by pressure gauges during the tests.The pressures up and down-stream of the filter were alsomonitored by chart recorders. Upon complete plugging of thefilter, the downstream filter pressure should be the same as thecasing pressure. The flowrate through the loop should also beclose to zero and could be checked with the flowmeter and thebleeder.

After the filter was plugged, it was replaced with a newfilter and fresh charts were started. The filter pluggingmaterials were collected for further analyses. Wellhead fluidsamples were also collected daily and checked for changes inappearance and texture.

A summary of the test schedule is shown below:

Day 1 – Day 16 Chemical A (150 ppm) performance testDay 16 – Day 27 Blank test as baseline (no chemical)Day 27 – Day 29 Cleanup wellbore with xylene/Chemical ADay 29 – Day 43 Chemical B (150 ppm) performance test.

Results:Filter Plugging Data: The filter in the side stream loop

had been plugged a number of times by considerable amountsof asphaltic material. Based on the severity of eachoccurrence, the extent of asphaltic pluggings was classified aseither “moderate” or “severe”. A moderate asphalteneplugging is defined as the presence of asphaltenes on the filterand in the filter housing. A severe asphaltene plugging meansasphaltenes not only plugged the filter and filter body but alsothe side stream tubing. The observations of asphaltic pluggingduring the 43-day field test are summarized as follows:

• Moderate asphaltene plugging was observed twice duringthe two weeks when Chemical A was injected.

• Severe asphaltene plugging was observed twice in oneweek after cutting off Chemical A.

• Moderate asphaltene plugging was observed once in twoand half weeks when Chemical B was injected

The average time it took asphaltenes to moderately orseverely plug the filter and/or loop is illustrated in Fig.4. Thedata clearly illustrates the effectiveness of Chemical A and thesuperiority of Chemical B for treating asphaltene problems.

H/C Ratio Analysis: The deposits collected from thetubing and the filter were analyzed for percent carbon andhydrogen. The H/C ratios (between 1.20-1.37) indicate thesolids were asphaltenes with some entrapped oil. The resultsare listed in Tables 2 and 3.

Wellhead Pressure Data: The change in wellhead pressurefrom the three testing periods was analyzed and compared.Downhole restrictions in the tubing associated with asphaltenedeposition would cause a rise in wellhead pressure. While thewellhead pressure was also affected by various natural andoperational factors which could cause it to fluctuate, the trendin wellhead pressure as a function of time, as displayed in Fig.5, gives some indication of when down hole depositionoccurred during the tests. The figure shows that the pressureincreased gradually when Chemical A was cut off on Day 16and no chemical was applied in well A through Day 27. Thiscould be an indication of deposition building up in the tubing.After the well was cleaned up on Day 29, the pressuredecreased, indicating removal of the deposits. When ChemicalB was applied the pressure remained relatively stable at avalue about 40 psi lower than when no chemical was applied.

Discussions:The H/C ratio analysis indicates that the deposits were indeedheavily asphaltic when a severe or moderate pluggingoccurred. The frequency of moderate and severe asphaltenepluggings was likely related to the WAG (water alternate gas)pattern that the producer applied to operate the well. BecauseCO2 is a costly fluid, the WAG program has been applied toinject an optimum volume or slug rather than continuous

4 Y. R. Yin, A. T. Yen and S. Asomaning SPE 59706

injection. In this method, the CO2 slug (2-3 days of injection)is followed by continuous water injection (3-4 days) to drivethe slug through the reservoir. The water immiscibly displacesCO2, leaving a residual CO2 saturation in the reservoir insteadof water flood residual oil6. Phase behavior considerationsimply that organic deposition is most intense duringmiscibility development7. Thus, in CO2 miscible flooding,organic deposition characterizes the flood front rather than theswept zone8. Therefore, when the well was just switched fromwater to CO2 flood, the impact of CO2 on the colloidalstability of asphaltenes in oil was much more severe than afterseveral days of CO2 flooding. The result was that periodicallymore asphaltenes were flocculated and precipitated in theproduced fluid to moderately/severely plug the side streamfilter loop. However, moderate and severe pluggings were notobserved each and every time the CO2 was switched on. It issuspected that the colloidal system of asphaltenes in oil canwithstand the disturbance from CO2 flooding to somethreshold extent before the asphaltenes starts to flocculate andprecipitate. The application of a chemical inhibitor enhancesthe colloidal stability and increased the resistance threshold ofoil against CO2 impact. However, if the threshold is exceededby a much stronger CO2 front, asphaltene flocculation anddeposition will still occur even when an inhibitor chemical isused. According to the field test results (Fig. 3), it was clearthat without the injection of chemicals in the subject well,moderate to severe asphaltene plugging of the filter was likelyto occur frequently. Chemical A was shown to work atreducing deposition and effectively doubled the time to plugthe filter loop. The new inhibitor, Chemical B, more thandoubled this time again. Since Chemical A was designed todisperse asphaltenes into smaller aggregates, and Chemical Bwas designed to prevent or hold up asphaltenes fromflocculation, Chemical B was a better performer in CO2

floods. In addition to the filter plugging frequency data, therewas a noticeable change in the texture and appearance of theproduced oil when treated by Chemical B: the oil appeared tobe softer, smoother and free of small black aggregates asnoticed in untreated oil.

Conclusions

• The newly develop asphaltene inhibitor (Chemical B)performs better than Chemical A on the high pressure liveoil depressurization experiment. The lab test results areconsistent with field trial data.

• As evidenced by the 15 month treating history in the WestTexas field, continuous injection of an asphaltenedispersant chemical was proven to be effective incontrolling asphaltene deposition problems.

• According to the 43-day field trial results, the recentlydeveloped asphaltene inhibitor, which preventsasphaltenes from flocculating,, was shown to be moreeffective in controlling asphaltene deposition whenapplied continuously.

• Batch treatment using dispersant chemicals on wells withsevere asphaltene problems periodically may not give thewells enough protection under rigorous CO2 flooding.

• The use of a filter-plugging side stream proved to be aneffective way of assessing asphaltene inhibitorperformance in field trials.

AcknowledgementsThe authors appreciate Baker Petrolite for permission topresent this paper. We would also like to thank Jim Ripley andDavid Mayes with Baker Petrolite for their assistance in thefield trial and Mike Newberry, Pat Breen and Chris Gallagherwith Baker Petrolite for their help in this project.

References1. Kokal, S.L. and Sayegh, S.G.: “Asphaltenes: The Cholesterol of

Petroleum,” SPE paper 29787, presented at the SPE Middle EastOil Showin Bahrain, March 11-14, 1995.

2. Newberry, M.E. and Barker, K.M.: “Organic Formation Damageand Remediation,” SPE 58723, paper prepared for the 2000 SPEInternational Symposium on Formation Damage, Lafayette,Louisiana, February 23-24, 2000.

3. Newberry, M.E. and Barker, K.M.: “Formation DamagePrevention Through the Control of Paraffin and AsphalteneDeposition,” SPE 13796, paper presented at the 1985 SPEOperations Symposium, Oklahoma City, Oklahoma, March 10-12, 1985, pp. 53-61.

4. Barker, K.M., Germer, J.W., Leslie, M.P.: “Removal andInhibition of Asphaltene Deposition on Formation Minerals,”paper SPE 35342 presented at the SPE International PetroleumConference and Exhibition of Mexico in Villahermosa, Tabasco,Mexico, March 5-7, 1996.

5. Leontaritis, K.J., Amaefule, J.O., and Charles, R.E.: “ASystematic Approach for the Prevention and Treatment ofFormation Damage Caused by Asphaltene Deposition,” paperSPE 23810 presented at the Symposium on Formation DamageControl, Lafayette, Louisiana, February 26-27, 1992.

6. Stalkup, F.I.: “Carbon Dioxide Miscible Flooding: Past, Present,and Outlook for the Future,” JPT (August 1978) 1105.

7. Monger, T.G. and Trujillo, D.E.: “Organic Deposition DuringCO2 and Rich-Gas Flooding,” paper SPE 18063, presented at the63rd Annual Technical Conference and Exhibition of SPE,Houston, TX, October 2-5, 1988.

8. Monger, T.G. and Fu, J.C..: “The Nature of CO2 Induced OrganicDeposition,” paper SPE 16713, presented at the 62nd AnnualTechnical Conference and Exhibition of SPE, Dallas, TX,September 27-30, 1987.

SPE 59706 ASPHALTENE INHIBITOR EVALUATION IN CO2 FLOODS: LABORATORY STUDY AND FIELD TESTING 5

Amount ofdeposit

(absorbancereading at

440 nm

Precipitatedasphaltenes

(mass ingrams)

% Inhibitionof depositsasphaltenes

% Inhibitionof

precipitatedasphaltenes

Blank 1.99 0.128 0 0Chemical A 1.36 0.095 32 26Chemical B 0.64 0.067 68 47

Table 1 Chemical screening results from high pressure experiment withWell A live oil

H (wt %) C (wt %) H/C RatioTubing Deposits 9.13 79.01 1.37Filter Deposits 7.41 71.84 1.23

Table 2. H/C ratio test results on deposits collected when nochemical was applied.

H (wt %) C (wt %) H/C RatioHousing Deposits 9.13 79.01 1.37Filter Deposits 7.41 71.84 1.23

Table 3. H/C ratio test results on deposits collected whenchemical A was applied.

Well A Production Data

10

100

1000

Production Time

Oil

& W

ater

Pro

du

ctio

n, B

OP

D &

BW

PD

1

10

100

1000

10000

Gas

Pro

du

ctio

n, M

CF

D

OilWater

Gas

1 1 / 9 7 S t a r t e d

C h e m c i a l A

B a t c h P r o g r a m

1 2 / 9 8 S t a r t e d

C h e m i c a l A

C o n t i n o u s

P r o g r a m

1 / 9 6 S t a r t e d

C O 2 F l o o d

o n W e l l A

Fig. 1---Well A Production History

6 Y. R. Yin, A. T. Yen and S. Asomaning SPE 59706

F

P

P

P C R

P C R

AdjustableChoke

Flowline from Wellhead

Ball Valve

Fil ter

Flow Meter

Check Valve Ball Valve

Ball Valve

PressureReliefB leeder

SamplingBleeder Needle Valve

UpstreamPressureGauge

DownstreamPressureGauge

UpstreamPressureChart Recorder

DownstreamPressure Chart Recorder

Downstream Flowline

SCHEMETIC OF ASPHALTENE DEPOSITION SIDE STREAM FILTER TEST LOOP

Fig. 2---Diagram of the Filter Plugging Side Stream Loop.

Side Stream Loop Filter Plugging Results

0 2 4 6 8 10 12 14 16 18 20

Chemical B

Chemical A

No Chemical

Average Days to Plug Filter by Asphaltene Deposits

Fig. 3---Side Stream Loop Field Setup. Fig. 4---Side Stream Filter Loop Plugging results

SPE 59706 ASPHALTENE INHIBITOR EVALUATION IN CO2 FLOODS: LABORATORY STUDY AND FIELD TESTING 7

Wellhead Pressure Data for Well A During Side Stream Tests

0

5 0

1 0 0

1 5 0

2 0 0

2 5 0

3 0 0

3 5 0

4 0 0

4 5 0

5 0 0

1 3 5 7 9 1 1 1 3 1 5 1 7 1 9 2 1 2 3 2 5 2 7 2 9 3 1 3 3 3 5 3 7 3 9 4 1 4 3

Field Trial Duration in Days

Wel

lhea

d P

ress

ure,

psi

S u r g e H i g h

A v g H i g h

A v g l o w

S u r g e l o w

W e l l h e a d

p r e s s u r e w a s

s e t a t a l o w e r

l e v e l a t c h o k e

C h e m i c a l A

T e s tN o C h e m i c a l C h e m i c a l B T e s t

Fig. 5---Wellhead Pressure Data for Well A During Field Trial.