the search for reservoirs suitable forenhanced gasrecovery through … · · 2016-01-21• the...
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• THE SEARCH FOR RESERVOIRS SUITABLE FOR ENHANCED GAS RECOVERYTHROUGH CO-PRODUCTION IN SOUTH LOUISIANA
By W. Clay Kimbrell,Brenda D. David,
Richard P. McCulloh,and Fred M. Wrighton
•
•
Abstract
The co-production enhanced gas recovery technique is a meansof enhancing the ultimate recovery of gas in water-driven reservoirs.The technique prescribes production of ~'ater from \\'atered-outwells downdip simultaneou;ly with the production of gas updip, inorder to lower the abandonment pressure, retard water influx, andincrease production during the primary life of the reservoir. Lowerpressure results in increased production due to the expansion in theupdip areas as well as remobiUzation of the dispersed gas fromwatered-out areas downdip. By treating the reservoir as a systeminstead of regarding single wells as individual profit centerS, theoperator can manage some reservoirs more efficiendy and profitably.The Gas Research Institute is funding the Louisiana GeologicalSurveylLouisiana State University to evaluate south Louisiana reser-voirs based on site geology and operator interest for suitability forco-production. To date, the Louisiana GeologicalSurvey has identifiedfive reservoirs which appear, after preliminary screens, to be excellentcandidates for the co-production technique. Computer simulationsshow approximate, but representative, predictions of substantialincreases in production through utili;:ation of co-production.
Introduction
Water-driven gas reservoirs generally have much lower recoveriesthan depletion-drive reservoirs. The water (the drive mechanism)encroaching from the aquifer invades the productive area of thereservoir before much of the gas can be recovered. A water-drivenreservoi r's pressure is maintained by this \\'ater. The stronger thewater dri\'e. the higher the pressure remains and the faster thewater in\'3des the productive area of the reservoir, Larger amountsof ~esidual gas are trapped at higher pressures than for lowerstabili:atiun pre;;sures. For example, a water-Jriven gas reservoirwith an initial water saturation of 30% and a residual gas saturationof 35% has a recovery, under primary techniques. of only 50%whete the resenoir pressure stabili:es near the initial pressure, Ifthe resen"oir permeability is uniform, this recovery factor is repre-sentative. excluding corrections for the efficiency of the drainagepattern and water coning. Also. where there are continuous bedsof higher and lower permeability. the water will ad\'ance morerapidly thrnugh the more p.?rmeable beds so that when a gas wellis abanJ"n"d r-,'cause nf excessi\"e water production. there are stilllarge am,'unrs l,i unrecovereJ gas in the less permeable :ones1
Because of these low reco\cry rates for \\'ater-Jriven gas reset\'oirs.and problems that occur with traditional or other enhancementtechniques such as the accelerated blowdo\\TI method, anothermethod of gas production management is being researched. Fundedby the Gas Research Institute of Chicago. Louisiana State University
lB. C. CrJit and M. F Ha"".kins. A.pplld P•.'tTolt.'\.I.m R&.'h.'"!'\OfT En;;lna"unR (Er:&lcwood Chffs:rr~nti.:e.H311,lnc .. 10:-9) p. 36.
(LSU), through the Center for Energy Studies, the Louisiana Geo-logical Survey and LSU's Department of Petroleum Engineering;is presently researching and promoting this method, which is referredto as the co-production technique,
The co-production process is defined as the simultaneous pro-duction of gas and water. If the water production rate is greaterthan the influx of aquifer water, then the reservoir pressure willdecline and the gas-water interface will lower or stabilize. Thetechnique prescribes production of water from downdip wellssimultaneously with production of gas from updip wells in orderto lower the abandonment pressure, retard water influx, andincrease recovery during the life of the reservoir. Lower pressureresults in increased production due to the expansion in updipareas as well as the remobilization of the dispersed gas fromwatered-out areas downdip. By treating the reservoir as a systeminstead of regarding single wells as indiddual profit centers, theoperator can manage some reservoirs more efficientlyand profitably.
Louisiana Geological Sur ••..ey Study
Co-production may be applied to totally watered-out reservoirsif the abandonment pressure is high enough, In fact, the initialattempts of enhanced gas recovery by co-production focused onthe depressurization of a totally watered out reservoir by with-drawing large volumes of water.l.J.4 This is technically feasibleand economical in some cases, but in case of unfavorable gasrelative permeability, extremely large volumes of water must beremoved to remobilize the gas. Also, the cost invol ved to reworka shut-in gas field and handle large amounts of two-phase gasand water production at high water-gas ratios is prohibitive,
The LSU study directs the application of the process to watcr-driven gas reservoirs not yet totally watered out. The implemen-tation of co-production during the primary life of a gas reservoirby utilizing existing wells and infrastructure represents the greatestpotential for its technical and economical feasibility, The processrequires converting downdip wells, as they watet out, to waterproducets. while gas production is maintained updip, The pro-duction of downdip water enhances recovery by:
• slowing down the advance of the \l'ater front. thus delayingthe watering-out of wells;
• reducing reservoir pressure so more gas can expand and beproduced;
~E. C. Gr~on ... Z. S. ll~m.R. S. R~J, R. A. :\tort00. and. L. A. R~n. "WatcrC'd.()utRes<r'\'oirs Pr~)(uar.le \'Ia EnhancrJ Re\:'ovt:rv'" OJ! l.lnJ G1J jou'ITLIJl. March 1983. pp. 35-60.'E. C. Gttr anJ H. L. C~"ll)k,"Enhancc'"J Gas R~O\'cr" irvm G('Orr("Ssurc-d Aquifc:rs," Paper:Society of PC'O'oleum Ent:ine.:rs 7541. pre~nteJ at the lQ78 Annual re<:hnlcai Confc'f("r'lCt'.
Houston, Oct. 1.3.4M. G. Doherty and P. L. Randolph, "S«king Prospects r'or Enhanc~ Gas R",-covrfY," Paper:Society of ~trolC'um ~nC'C'rs 11103. rre'<fltN at the 19~~ SPE AMual Technkal G.mferencc.New Orleans. Sert. 26.~9.
.,....33-
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• reducing pressure in the swept zone so that previouslyimmobile gas can expand and might be produced.
The updip gas wells can, if warranted, be produced at a high rate,thus incorporating the benefits of the accelerated blowdown method.
The Louisiana Geological Survey has been involved in screeningactive gas reservoirs in south Louisiana which fit the necessaryrequirements for utilization of co-production in order to identifysites for field tests. Initially, the screening was achieved by computerand manual data base searches of Louisiana fields using publicinformation. For this initial screening,S the following basic criteriaswere used:
• There must be two or more producing or temporarilyabandoned wells in the field.
• The initial bottom hole pressure gradient for one or moreof the wells must be above 0.65 pounds per square inch perfoot (psi/ft), i.e., overpressured.
• The inception-to-date gas production per producing wellmust be greater than 1 billion cubic feet @ standard conditions(BCF).
• The field must be onshore.• The field must not produce oil.
After this screening was finished, the reservoirs within the fieldwere subjected to another screen which consisted of the followingcriteria:
• The reservoir must be water driven .• The reservoir must have at least two active or temporarily
abandoned wells .• The reservoir must have adequate geological conttol and
production history in order to define the reservoir shapeand initial gas-water contact and for accurate technical evalu-ation of the field.
Once the reservoir passed this screen, geological maps wereprepared (top of and. base of sand. net sand, and net gas). Originalgas in-place and all pertinent engineering data were calculatedwhen possible or estimated otherwise. Once this had been doneanother screen was applied.
Estimates of the initial gas in-place were made using volumetricand material balance calculations. which were based on availablegeologic information and production data. Computer simulations,pr,wided by the Department of Petroleum Engineering (LSU),pn:dicted. under different production schemes. the future per-formance of the reservoirs. This included use of a material balance(MBE) simulation of water-driven gas reservoirs developed toarrive at an approximate. but representative picture of the reservoir.Assuming that existing updip wells have some primary productionremaining. existing watered-out wells can be converted to waterproducers. and that the produced •.•.<ltercan be disposed of properly,the MBE simulation predicted future production trends for thereservoir with and without implementation of co-production.This simulation required adequate pressure information. and insome cases, reservoirs which had passed all screens to this pointcould not be simulated because of this. Assuming this simulationprovides positive results. a more complex simulation will beconducted to refine the estimate of future rese.rvoir performanceunder different co-production schemes. This will include:
'J. E.Johrumn,lII. \'t', C. Kimbrell. M. A. Surman, and B. D. David. "Exploration (or Solutionand Free Gas from Gropres.suTN Watered-Out Gas Fields. South Louisiana:' Final Report forG•• R.~orch Institute ContTOe< No. 5081.212.05'18. F.bruary 1982-October 1984. pp.12.13.
• Use of company-ownedsimulation models of water-drivegas reservoirs .
• Use of a commercial three-dimensional simulation to fine-tuneand improve the effectiveness of the prediction. Use of sucha model will be provided for by the Gas Research Institute.
Obviously, operator interest must be obtained to continueresearch and to carryon field tests at this point. If the operator ofthe reservoir has no interest in the enhancement. then researchon the reservoir is discontinued.
For the purposes of this study. major companies and independentsare being investigated separately by the Department of PetroleumEngineering (LSU) and the Louisiana Geological Survey (LGS).respectively. This paper focuses on reservoirs operated by inde-pendents. At present the LGS has identified, after the initial MBEsimulation, five reservoirs which appear to have excellent potentialfor the utilization of the co-production technique: Marginulinaascensionensis 7. 10, and 13, which are within the Lower Formationof the Fleming Group of the Miocene Series, of Garden Cityfield; Bolivina mexicana 2A of Maurice field; and Bolivina mexicana3 of North Maurice field. Both Bolit~namexicana 2A and Bolivinamexicana 3 are within the Frio Formation within the CatahoulaGroup of the Oligocene Series. What follows are the descriptionsand results for the five reservoirs. Top of sand and base.of sandmaps for these five reservoirs are preliminary only. Detailed des-criptions have been included for the two best candidates, Marginulinaascensionensis 10 and Bolivina mexicana 2A. The following resultsare based only on the initial simulation and not the more complexsimulations as described above .
Garden City Field
Garden City field is located in central St. Mary Parish, Louisiana.approximately 5 mi. southeast of the town of Franklin (Figure 1).Of the 18 presently active reservoirs in the field. only the threementioned above passed the screening. All reservoirs are stackedabove one another and are located in the northern portion of thefield.As a result. each reservoirconforms to the same generalstructure,which is domal and traversed by a major down-to-the-basin growthfault. The fault cuts each reservoir just to the south of the crest of
--the dome, and each reservoir is in the upthro •.•.n fault block.
LOUISIANA
/a"'IDI. CITY rilL, , .
_ .Figure 1. Location Map of StudIed Fields
I
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:,. .'.): '~1 "".' I " ; •I •: •~.t: .. ; t '.' I ' .' : I. ~ •_ • \ I • I"'" , ' , , '. I • ';' I. I '\. , "'. • " • ',: : ' t I' • : : . :. : .' .', ',l ':', ~
eM . r" . . 7aTglnu Ina ascenslOnensu
MaTginulina ascensionensis 7 (MA-7) lies approximately 14.855feet below sea level (ft-bsl; Figure 2). The original gas-watercontact was estimated at 15,050 ft-bsl. yielding a productivesurface of 2.783 acres, a bulk reservoir volume of 117.979acre-ft. and an original gas in-place estimate of 423.8 BCF (Figure3). Since production began in 1959. 254.5 BCF of gas and gasequi valents. or 60% of gas in-place have been recovered. QuintanaPetroleum Corporation is currently producing this reservoirwith two active wells (state serial numbers 140662 and 178552)
and maintains four shut-in produCtive future-use wells (092534,110438.114742.128887; Table 1). The data shown in Table 2were run on the MBE simulator. Assuming co-production wouldbegin in January 1986 with an abandonment pressure of 1.000psi and a water production rate of 6.000 barrels a day (bblld)the ultimate recovery is estimated to be 398.5 BCF (94% recovery)extending to the year 2024. This contrasts with an ultimaterecovery without enhancement of approximately 322.5 BCF(76%) with abandonment in the year 2003. Therefore. use ofco-production would increase the production by 76 BCF. i.e.,an additional 18%.
44
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0••• _..- GARDEN CITY FIELD011 ~ ••.•••• o
••••••. 5T MARY PARISH LA0-- MARGINUlINA, ASCENSIOI'ENSIS7J. ..- •._ TOP OF SAND "~ __ JULY, 1965' -:" - ---cr.-o,o.... "PREPARED'eY': w.e. KJ.1BRELr-!!.... l LOUISIANA GEOLOGICAL SURVEY
_::..' GRI CONTRACT '#: 50842120997;;:0':;;;- C.'L= 100 FT..... . W",,( ,.. 'reT
*fAULT A30
••
+ 42
27
15
• Figure 2. Top of Sand - MA-7 Preliminary
-35-
+ 42
II
10 II
N
IS \.14
+4ft
4ft Ii27
261/ olJ4-25• -+
Figure 3. Net Gas - MA-7 Preliminary
*FEL - F«,t from Easternmost Lin~ of Section• -FSL - F«t from Southernmost line of Section
"'.FWL - F«t from ~'estn'nmMt line of Section
178952 Active
092534 Shut-in Prod.Future Use (F.U.)
110438 Shut-inProd. F.U.
114742 Shut-inProd. F.U.
128887 Shut-inProd. F.U.
SerialNumber
140662 Active
Status
TABLE IMA-7 WELL LISTING
TotalOperator Well Name Location Depth
Quintana Maryland 19-15S-IOE 15584'Petroleum Corp. Co., Inc. #6 2390 FEL*, 2800 FSL**
Quintana Maryland 19-15S-IOE 15200'Petroleum Corp. Co., Inc. # II 1400 FWL***, 330 FSL
Quintana \Villiams 13-15S-9E 15200'Petroleum Corp. Inc. #8 1000 FSL, 1000 FEL
Quintana Williams 13-15S-9E 15612'Petroleum Corp. Inc. #11 1000 FSL, 2190 FEL
Quintana A.c. Planta- 61-1.-5S-IOE. 15150'Petroleum Corp. tion #9 300 FEL, 850 FSL
Quintana Williams 13-15S-9E 15200'Petroleum Corp. Inc. #14 1500 FWL, 1300 FSL
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• TABLE 2AQUIFER AND RESERVOIR DATA USED FOR MA-7 SIMULATOR RUN
Apparent Reservoir Radius, in Feet (Ft.): •... 4000.0Ratio of Aquifer/Reservoir Radii,Dimensionless (D'Less): 7.0
Net Thickness of System (Ft.): 60.0Angle Open to Flow (Degrees): 127.0Water Compressibility (Microsips): 3.5Rock Compressibility (Microsips): 4.5Aquifer Porosity (D'Less): 0.25
Marginulina ascensionensis 10
Marginulina ascensionensis 10 (MA-lO) lies awroximately 15,283ft-bsl (Figure 4). The original gas-water contact was estimated tobe 15,884 ft-bsl, yielding a productive surface coverage of 4,783acres, a bulk reservoir volume of 395 ,170 acre-ft, and an originalgas in-place estimate of 1355.7 BCF (Figure 5). Since production.began in 1961,584.2 BCF of gas and gas equivalents, or 43.1 %of the gas in-place, have been produced. Graphs of log of pro-duction versus time and log of cumulative production versustime are illustrated in Figures 6 and 7. Quintana Petroleum
Aquifer Permeability, in Millidarcies (MD): 200.0Gas Gravity (D'Less): 0.61Water Viscosity, in Centipoises (CP): .........• 0.61Connate Water Saturation (D'Less): 0.18Residual Gas Saturation (D'Less): 0.20Original Gas In Place (BCF): ....•........... 380.608Reservoir/Aquifer Temperature, .Degrees Fahrenheit (F): 242.0
Corporation operates this reservoir with seven active wells(078435, 081495, 086873, 161198, 162837, 176513, and184468) and maintains four shut-in productive future-use wells(087336, 123801, 149664, and 181097; Table 3). The datashown in Table 4 were run on the MBE simulator in two simula-tions varying the start-up times. The results are shown in Table5. Graphs of the first simulation are shown in Figures 8 and 9.Graphs of the second simulation are shown in Figure. 10 and 11.The utilization of co-production would increase the productionapproximately 252 BCF, or an additional 19%.
•
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II
39
•
Figure 4. Top of Sand - MA.10 Preliminary
-37-
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+ 42
I
IC9
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• Figure 5. Net Gas - MA-10 Preliminary
GARDEN CITY FIELD RESERVOIR MA-l0GAS + GAS EQUIVALENT PRODUCTION
•
7.00
6.80
6.60
0" 6.40::ll
6.20f;:u 6.00ez 5.800
~5.60
::> 5.40A0 5.20ll:p.,
5.00
'"0 4.80~0 4.60...:l
4.40
4.20
4.00196~2 6364 6566 8788697071 72 73 74 75767778798081828364 85
YEAR
Figure 6. Log of Production vs. Time (Mo/Yr) - MA-10
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~'~.~~----~------------c-------------------
-1.0
:
i
:I
85
-10
Totalcation Depth
15628'60 FNL*
15662',1700 FNL
15830',1000 FNL
15569'850 FSL
15539'100 FSL
19650'1050 FNL
!
16000'400 FNL
15800',700 FSL
17350'1400 FSL
15700'2000 FNL
15727'2200 FNL
",;:'g.' .•. ~"', - .""'
"
20-15S-10E400 FWL,
26-15S-9E1200 FEL,
20-15S-lOE900 FWL,
1.0
25-15S-9E600 FEL, 6
25-15S-9E1700 FWL
24-15S-9E1650 FWL
19-15S-10E2000 FEL,
19-15S-10E1500 FWL
25-15S-9E2000 FEL,
30-15S-10E500 F\X!L,
18-15S-10E1400 FWL
Well Name
MacphersonWessland #7
A.C Planta-tion #4
Shinn #8
lvlarylandCo" Inc. #5
MarylandCo., Inc. #9
Shinn #10
WilliamsInc. 4
MarylandCo., Inc. #8
Shinn #7
MacPhersonWessland #2
WilliamsInc. #2A
TABLE 3MA.IO WELL LISTING
GARDEN CITY FIELD RESERVOIR ,MA
-1.0019813283 M 85 68 87 68 89 70 7172 7374757877787980 81 82 83M
YEAR
Figure 7. Log of Cumulative Production vs. Time (Mo/Yr) - MA
Serial• Number Status Operator
078435 Active QuintanaPetroleum Corp.
081495 Active QuintanaPetroleum Corp.
086873 Active QuintanaPet~oleum Corp.
161198 Active QuintanaPetroleum Corp.
162837 Active QuintanaPetroleum Corp.
176513 Active QuintanaPetroleum Corp,
184468 Active QuintanaPetroleum Corp.
087336 Shut-in QuintanaProJ F.L:. Petroleum Corp.
12 38() I Shut-in QuintanaProJ F.C. Petroleum Corp.
149664 - - Shut-in QuintanaProd F.U. Petroleum Corp.• 181097 Shut-in QuintanaProd F.U. Petroleum Corp.
*FNL •••F«t from Nt)rthc:rnmost Line: o( ~ction
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3.00GAS + GAS EQUIVALENT PRODUCTION• •...• 2.50••0
III...,:z: 2.000-t 1.50~~00::lI. 1.00
~~ 0.50
~:liI~ 0.000CI0w -0.50
• TABLE 4AQUIFER AND RESERVOIR DATA USED FOR MA-IO SIMULATOR RUN
Apparent Reservoir Radius (Ft.): 8000.0Ratio of Aquifer/Reservoir Radii, (D'Less): 7.0Net Thickness of System (Ft.): 30.0Angle Open to Flow (Degrees): 137.5Water Compressibility (Microsips): 3.0Rock Compressibility (Microsips): 4.5Aquifer Porosity (D'Less): 0.25
Aquifer Permeability (MD): 150.0Gas Gravity (D'Less): 0.61Water Viscosity (CP): 0.75Connate Water Saturation (D'Less): 0.20Residual Gas Saturation (D'Less): 0.40Original Gas In Place (BCF): , 1355.74Reservoir/ Aquifer Temperature (F): 256.0
TABLE 5MA-IO MBE SIMULATOR RESULTS
Water UltimateStart-Up Prod. Recovery Year %
Simulation Time BBLID BCF Abandoned Recovery
1 1/86 10,000 1,274 2016 94.02 1/99 20,000 1,276 2021 94.1
Without 1,023.5 2008 75.0
ZCstl2O~C15SO z::cc 2!: LaTiME IN TEAfl~
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Figure 9. MBE Simulation Graph. Pressure vs. Time for Various Water.Production Rates Beginning In Jan. 1986 - MA-10
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I I I I I I I I I j I I I iI I I I I I I I I 1 I I I I I IT I I I I I I I I I' I I i 11~-,c:: no, I I I I I I I 1 I !. " 'I I' I I , Iill I 1.111 11/, 1.'11 I' rlJ\3EiII1I IIII y,lJ...- IIII IIII IIII
T ,. I I I. ' ....•..1 t I. I I1I I I 'I I" I I I ,r '70 1=1I I y. I' I 1 ..!...l! 1 ,
I I I I I I ! .' I I I I IT II I~I I I I 1 I.1 I I VI I I -rl I I I'1111 III I IITI 111'11I I 1.11 I I I I I I I J I I I I! 1 I I I., I~ I i I I ill I I I I I I I I I I I I I II A' I! 'I I I I I ! I I I I I I I I I I I I I
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I I I I I I i I
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11111 IX •• WH j~f 11;"<1-11 l"ll~I ! i ! I ! l : : I ~ I '.J I I I ! I ! I ! I
i I I I I i I I I iii iii I 4 I i
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i •
2!lCIl 2D111 = 2!I3llTIME IN TERIi~
Figure 10. MBE Simulation Graph. Cumulative Produ<:t1on vs. Time for Various Water.Produ<:tion Rates Beginning In Jan. 1999 - MA-10
u..uc
C\.LJU
E<>COa:••a..
•-41-
•oB ----~
:iI11!i} ~I:(~I~1"1:-
..- _.-I- -
~ ------ --------------:8 :~::-:-.= =~~h== --a::~::J _.- - _._-.~ :::_:::_::~ -~ -_: =--a::8 - _.- - - - - - - - - ~ - - -0...0•• ::-.:__:::_:__ : :k~_:8::-::-:::::----::-~,:~----------- _ .. ----~~ ----- -- - -------
_::::_-_:::_::_---:_-~:-:_: :- -I:' .- - ... - -1'5.
Figure 11. MBE Simulation Graph. Pressure ils. Time for Various Water.Production Rates Beginning in Jan. 1999 - MA-10
't eo 1 10 J eo I 00 2 00TI HE I N YEARS
2 10 2 20 2 so'.1
-42-
Marginulina ascensionensis 13
Marginulina ascensionensis 13 (MA-13), the oldest producerin this field, is located approximately 16,883 ft-bsl (Figure 12).The original gas-water contact was estimated to be at 17,126ft-bsl, yielding a productive surface of 778 acres, a bulk reservoirvolume of 54,617 acre-ft, and an original gas in-place estimateof 186.3 BCF (Figure 13). Since production began in 1966,71.3 BCF of gas and gas equivalents, or 38% of the gas in-place,have been recovered. Quintana Petroleum Corporation operatesthi.i reservoir with one actiw well (163774) and maintains ashut-in productive future use well (115044; Table 6).
The dara shown in Table 7 were run on the MBE simulator.According to the resulrs, 88% of the gas has been water produced.Assuming a sta rtup time of]anuary, 1986 with an abandonmentpressure of 1,000 psi and a water production rate of 20,000bbl/d, ultimate recovery is estimated at 159.9 BCF (85.8%recovery) extending to the year 2005. Under current conditions,the reservoir is expected to water-out in the year 1993 with anultimate recovery of approximately 106 BCF (57.1 % recovery)and an abandonment pressure of 11,200 psi. Therefore, utili:ingco-production would increase the recovery by more than 53BCF, or 28.7%.
/i
k.1ll
35
• I
14 • ilH3 Itl 45
N + TI5S-R9E
I., .,
-l622 23
If
Figure 12. Top of Sand - MA-13 Preliminary
14 lIE• N +
I.22 23
* ~,
++
* *7 21:;If
+----------
.34 .35
;It-1.3 It:
TI5S - R~E TI:-2 - :>'If
il * *-1
*24 20
1f.,
*" *'I
0-_1:-j("-e-.# .••.tb•• _.----
45
46
52 /53 ~/
.~/
27
BY: Vi. C. ~MlRELLG(OLC(,ICAL S~ <
#" 4 ~
Figure 13. Net Gas - MA-13 Preliminary
TABLE 6MA-13 WELL LISTING
SerialNumber Status• 163774 Active
115044 Shut-inProd F.U.
Operator
QuintanaPetroleum Corp.
QuintanaPetroleum Corp.
Well Name
MarylandCo., Inc. #10
MarylandCo., Inc. #2A
Location
29-15S.10E1000 FWL, 2180 FNL
29.15S-IOE950 FNL, 50 FWL
TotalDepth
17300'
17488'
-43-
---------------,.-;;\j~n~.>-----
TABLE 7AQUIFER AND RESERVOIR DATA USED FOR MA.13 SIMULATOR RUN•
I
Apparent Reservoir Radius (Ft.) 4000.0Ratio of Aquifer/Reservoir Radii, (D'Less) 6.0Net Thickness of System (Ft.) 40.0Angle Open to Flow (Degrees) 120.0Wilter Compressibility (Microsips) 3.5Rock Compressibility (Microsips) 4.5Aquifer Porosity (D'Less) 0.25
Aquifer Permeability (MD) 200.0Gas Gravity (D'Less) . " . " •.......... " •.•.. 0.61Water Viscosity (CP) " '" ......•.. 0.61Connate Water Saturatio~ (D'Less). " 0.26Residual Gas Saturation (D'Less) ........•..... 0.30Odginal Gas In Place (BCF) 186.261Reservoir/Aquifer Temperature (F) 290.0
Figure 14. Top of Sand - Bol Mex 2A Preliminary
BCF of gas and gas equivalents, or 14.4% of gas in-place, havebeen recovered. A graph of the log of production versus time isillustrated in Figure 16. Lea is presently producing the reservoirwith two active wells (179363 and 196062; Table 8). The datashown in Table 9 were run on the MBE simulator, and the resultsare depicted in Figures 17 and 18. The two producing wells arealso conveniently located near'three saltwater disposal wells thatcould be utilized to dispose of the brine produced ..
III
63
MAURICE FIELD BOL .MEX 2A ReGAS + GAS EQUIV.u.ENT PRODUCl'ION.
Figure 16. Log of Production vs. Time (MolYr) 801 Mex 2A
Figure 15.
-45-
6.005.905.605.705.605.505.405.305.2015.1015.004.904.604.704.604.504.404.304.204.104.00
'U~62•
•
•
TABLESBOLIVINA MEXICANA 2A, RESERVOIR C WELL LISTING
TABLE 9AQUIFER AND RESERVOIR DATA USED FOR BOL MEX 2A SIMULATOR RUN
Serial Total.Number Status Operator Well Name Location Depth
179363 Active Lea Exploration E.B. Racca #1 83-1OS-4E 16493'1500 FSL, 2750 FWL
196062 Shut-in Lea Exploration M. Parrish #1 83-1OS-4E 16500'Waiting 4650 FWL, 550 FSLon Pipeline
Aquifer Permeability (MO) 275.0Gas ravity (O'Less) 0.61Water Viscosity (CP) 0.61Connate Water Saturation (O'Less) 0.48Residual Gas Saturation (O'Less) 0.30Original Gas In Place (BCF) 15.26Reservoir/ Aquifer Temperature (F) 267.0
Apparent Reset\~oirRadius (Ft.) 3500.0Ratio of Aquifer/Reservoir Radii, (O'Less) 4.0Net Thickness of System (Ft.) 10.0Angle Open to How (Degrees) 98.7Water Compressibility (Microsips) 20.0Rock Compressibility (Microsips) 5.0Aquifer Porosity (O'Less) 0.25
-46-
Figure 17. MBE Simulation Graph. Cumulative Production vs. Time for Various WaterProduction Rates Beginning in Jan. 1986 - Bol Mex 2A
2000IU'199&199~Ie!! 1'90 1.92TIME .Iff TERRs"
le!5
i . ..
15!2
I.
.
1---
~990
, Ii : i I /' 1.'-3.,l~-' !
_____ -,-__.__ L / !, : I I / I iI I I' I / I I; I I ;I ; I T J :! /! ; Ii! i j ~ ~ Iii t !
i I . Ii; V. Ii; J I I J ! I I I ! i I
I ; -,: ''/1 .. : I "l' ; ;~ I ! I ./' I I ! ! I I i I .!-l
b-'------f----- : -------i- ._-.j ---:--/-:-:-':-;~--I--:'-h'I-'~;--:+:_~" io ~-~~---i i I / :! I I : I I
Z =' I .; ~:~; ~ I :::!! I !C) i I ; Y I I I ! i I ! Ii: ! ! I ;
~! I I I ill! I : : ; I i j I j • I :1u I ! I I' IJ ; j I:! • I I: j I ~ I
g=1 ---J-- -- - - -i - --:-J."~~ItL:ri--~-!-:RRr~"':""lT;ci-J-:-:-~--_.-:0- = 1_,_._;_:-:-' __ '- - -- H,,;.,--.--:--i .' 1.6 . ~ . .~; I ;, ill-,-;-:--;L"l J ! I I! :1-" !=1'-5B.~;B-B-i::-S ': 0811 I ! I ! I I:3 I / / J_-~~~.~..,...;-I' I, I I I 'I
': I , ,-/"; .4- w'R = ( . ..•.....•...I<.; : / ll-l ; ,: I: ;, -I"'I : i I / ii' I: ; I: ;: I : I: i; Ii
; J ./ J , I IIi! / I I ! I Ii: i=1---+ ...----:--/-! : :'! ,: ! I i I
N_L~ -:~-i~:! ! : I I : I., : : ~I: i; I : I II__ :.~__ j..: _-~.!t_.__' i_ --.:....-.l I I,: I : I : : I '; I : iI I /--+ ; i I I I I; : Ii; I I: I i
IHUij
: ;, ;
i 1j fi i ! ;
18~2
I "
iIU8D
r r.r,:j I ! !
Iua 188dTIME IN YEARS
i I, I
I !
1U8ij
; .Ii!ix:,k'I : ;'1; ! ; :r-r;;
-,-!-r~, !
1882
; i
g I I i~
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ao....
......'" I ! ~,' -II" 'j!,"I,' l-r:--Ii; I ; ,j'
I I ! I II r i I • "~ II I' , -T i jjj r~ : Ii' ! ~-!
i ; I I'x xl,''':g 1 l j i : l.~I .1 .~...._+--+-+- _~_l _' _, __ ~- .. ; I • j i !
i I 'I I r'.1, "
g ;! !' I'"..
. ", : 'I' :, ": : ;
, : ,i :.1;'... ,
a:g" -'~7' ~-H-.~-"--t-.t._ .. ;UlD.
o~~.=.>tfllJ'
~ ; I I
Cl.~ -;-~--' -:-~.; .. '---'----T7ii I! :j,
•
•
Figure 18. MBE Simulation Graph. Pressure VS. Time for Various WaterProduction Rates Beginning In Jan. 1986 - Bol Mex 2A
•
Norm Maurice Field
North ~'laurice field is located in Lafayette Parish, Louisiana.Six reser-'oirs are currently active in this field, of which one wasidentified as a candidate for co-production, Bo/it'ina mexicana 3(Figure 1).
The Bolil"ina mexicana 3 (801 Mex 3) reservoir is a south-plunging anticline located at approximately 15,000 ft-bs\. Thereservoir is limited to the north by an east-trending, up-to-the-basin fault that cuts the axis of the anticline. It is further limitedto the north west by a po;sible permeability barrier (Figure 19).The original gas-water contact was estimated at 15,330 ft-bs\,yielding an original productive surface of 1,405 acres, an originalbulk reservoir volume of 70,196 acre-ft, and an original gas
in-place estimate of 189.3 BCF (Figure 20). This reservoir beganproduction in 1983 and to date has produced 6.3 BCF of gasand gas equivalents. or 3.3% of the gas in-place. It is operatedby Exchange Oil and Gas Corporation with two active wells,(184785 and 179630; Table 10. The data shown in Table 11were run on the MBE simulator. According to the results. 85%of the gas has been water produced. Assuming a startup date ofJanuary 1986, an abandonment pressure of 1,000 psi, and awater production rate of 10,000 bbl/d, the ultimate recovery ispredicted to be in excess of 161 BCF, or 85% recovery withabandonment in the year 2034 using the coprOduction technique.Without co-production the ultimate recovery is estimated tobe 93.1 BCF, or a recovery of 49.2%. The~efore, co-productionwould increase the recovery by over 68.6 BCF, or an additional35.8%.
-47-
--------'---------------- ...•_---.
Figure 19. Top of Sand - 801 Mex 3 Preliminary
• II 12 7 8
+R-3E R-4E
+E 17
•
•
\0 II 12 7 B .+
fR-3E R-4E
14+
\5
23-t~
Figure 20. Net Gas - 801 Mex 3 Preliminary
-A8-
• TABLE 10BOLIVINA MEXICAN A 3 WELL LISTING
Serial TotalNumber Status Operator Well Name Location Depth
179630 Active Exchange H. Mouton 19-10S-4E 15438'Oil & Gas # 1 2000 FWL, 1750 FNL
184785 Active Exchange Declouet 24-10S-3E 15500'Oil & Gas # 1 1500 FEL, 580 FNL
TABLE 11AQUIFER AND RESERVOIR DATA FOR BOL MEX 3 SIMULATOR RUN
Apparent Reservoir Radius (Ft.) 5000.0Ratio of Aquifer/Reservoir Radii, (D'Less) 7.0Net Thickness of System (Ft.) 40.0Angle Open to Row (Degrees) 120.0Water Compressibility (Microsips) 3.5Rock Compressibility (Microsips) 4.5Aquifer Porosity (D'Less) 0.25Aquifer Permeability (MD) 75.0Gas Gravity (D'Less) .. '.' 0.61Water Viscosity (CP) 0.61Connate Water Saturation (D'Less) 0.372Residual Gas Saturation (D'Less) 0.30Original Gas In Place (BCF) 189.319Reservoir/Aquifer Temperature (F) 270.0
iI
'1III:j
Summary
• Table 12 is a summation of these five reservoirs and theirsuitability for co-production as indicated by the Department ofPetroleum Engineering (LSU) computer simulations. The pre-dicted additional recovery recorded in Table 12 is based on the
assumption that co-production would begin in January 1986and continued until an abandonment pressure of 1,000 psi hadbeen reached. To further simplify the results, Table 13 ranksthe five candidate reservoirs, and Table 14 summarizes engineeringdata for these reservoirs.
TABLE 12SUMMATION OF CANDIDATE RESERVOIR PERFORMANCE UTILIZING CO-PRODUCTION
PredictedPredicted Abandonment
Reservoir Additional Recovery Date Water.Rate._Name BCF % (Year) BBLID
rvl.l.,-7 76.0 18.0 2024 6.000MA-lO 2'51.0 19.0 2016 10,000MA-13 53.0 28.7 2005 20.000BOL MEX 2A 8.8 57.1 1995 6.000BOL MEX 3 68.6 35.8 2038 10,000
TABLE 13RANKING OF FIVE RESERVOIRS
•Ranked hyAdditional
BCF
MA-I0MA-7Bol Mex 3MA-13Bol Mex 2A
Ranked hyAdditional
%
Bol Mex 2ABol Mex 3MA-13MA-I0MA-7
Ranked byEarliest
Abandonment
Bol Mex 2AMA-13MA-lOMA-7Bol Mex 3
-49-
Ranked by\Vater
Production
MA-7Bol Mex 2AMA-I0Sol Mex 3MA-13
AverageRank
Sol Mex 2AMA-lOMA-7Bol Mex 3MA-13
TABLE 14SUMMATION OF ENGINEERING DATA FOR FIVE RESERVOIRS
Reservoir Name MA-7 MA-IO MA-13 Bol Mex2A Bol Mex 3.original Reservoir Pressure (psig) 12939 13300 16092 13600 13600
Original Gas Saturation (%) 82.0 84.0 74.3 52.0 62.8Original Z-Factor 1.62 1.61 1.81 1.69 1.67
Original Formation Temperature242 285 290 266 270
(Degrees F)
Porosity* (%) 25 25 25 25 25Original Gas in Place (BCF) 423.8 1355.7 186.3 15.3 189.3Present Average Reservoir
8572 7000 12946 12326 13240Pressure (psig)
Reservoir Average Depth (ft-bsl) 15000 15500 17000 15150 15050.Assumc:J \A:hcne\'cr there \Io"3S no core analysis available.
ACKNOWLEDGEMENTS
The authors of this report would like to acknowledge theassistance of the following people: Dr. Zaki A. Bassiouni, of theLouisiana State Universiry Deplrtment ofPerroleum Engineering.who is a co-principal investigator of the university's co-productionresearch; Keith Halford, a master's degree candidate in the
Department of Petroleum Engineering (LSU), whose researchprovided the material balance computer simulation; the GasResearch Institute of Chicago, Illinois, which provided fundingfor the Louisiana State University's research of co-production;and Dr. Leo Rogers, of the Gas Research Institute, who gaveapproval for the publication of this paper.
PHASE BEHAVIOR OF LIGHT HYDROCARBON-HEAVY OIL OR--TAR SYSTEMS, AND ITS APPLICATION TO RECOVERY PROCESSES
By Robert H. JacobyProfessor, Petroleum Engineering Department
Colorado School of MinesGolden, Colorado
AbstractIn trod uction
•The effl,(t of Jisso"'ed light hydrocarbons as ethane, propane
and butane on the viscosity and solids precipitation behavior ofheavy oils and Athabasca tar is shown from experimental data.These data_ac<:,compared with commonly held notions of suchbehavior and explained in more general terms.
This information may be used to advantage in recovery pro-cesses for heavy oils or tars, and the results of one field test areshown as an example.
Although this is not an original presentation of the materialcovered, it is felt that it needs more widespread recognition.Previous publications' of parts of it are scattered in less wellknown places. Furthermore, it deserves field testing in competitionwith the carbon dioxide and steam injection processes that areso popular today .
In 1950, Blair; stated that propane could not be used toextract Athabasca tar from its sand matrix because the tar was
-50-
c" . " "!' .","-
'-------------------------------<-
The apparatus shown in Figure 1 was used to equilibrateknown mixtures of raw tar sand and light hydrocarbons such asliquid ethane, propane, butane and pentane. It was enclosed ina constant temperature bath and pressure was controlled by thehydraulic system driving the piston. Fine screens in the pistonhead and the cell head kept the sand and hydrocarbon solidmaterial in the cell, during circulation of the solvent rich phasethrough the cell from bottom to top, by means of a hand pump.
concentrations they do not, but near 60 wt.% tar, they do indeedapproach 100% solubility! It was not possible to explore mixrureshigher than 65% tar because the sand volume prevented theattainment of smaller cell volumes; Le., the 35 wt.% propanesolution apparently filled the interstices or porosity of the sand.
• essentially insoluble in propane. That notion more or less agreeswith what is known about the propane deasphalting process ina refinery. In that process, a vacuum resid is contacted with 5 to10 volumes of propane per volume of resid. Usually about 50to 70 volume per cent of the resid feed dissolves in the propaneand the remainder settles out as a separate heavy oil phase; Le.,the resid is partially soluble in propane.
Similarly, the ASTM test for asphaltenes is to mix a crude oilsample with 50-100 volumes of pentane per volume of oil, andthe undissolved solid left is defined as "asphaltenes".
The fact which is common to these situations is that themixrures formed are all in the range of 80-100 wt.% light hydro-carbon solvent. Few, if anyone, have investigated the other endof the composition range, at low solvent concentrations. Thiswas done by the author in 1952 at Amoco.
Experimental Data with Athabasca Tar
70
Figure 2.
o 9O"F, !l00 PSIAo 9O"F, 1000 PSlA• 90 OF, 200 'PSlA• 45 OF, 200 PSIAo 45 OF, 800 PSlAa VARIOUS,!lOOPSIA EXCEPT
2OO"F 200 Of, 800 PSIA
I 4
WEIGHT PERCENT ATHABASKATAR IN OVERAU..I.tIXTURE
Propane-Tar System Equilibrium Extraction Data
Figure 1. Schematic Diagram of Apparatus
After an elapsed time and enoq:h circulation considered necessaryt,;[ el.juilihri urn. a sample ot the extract phase was removed fromthe rap ot the cell under constant pressure displacement. Thesesal1lrles wac: analy:ed by weighing the sample cylinders beforeand after the solvent was driven off by evaporation in a warmW3ta bath.
The extract sample anal~~s were then compared with the kno\l.71mixture composition in the cell, in diagrams such as Figure 2. If
•1 ot the tar present in the mixrure dissolved in the propane, then
e extract analysis should be the same as the rotal mixture com-position (on a sand and water free basis); i.e., the data pointsshould lie on the 45° line from the origin. At high propane
Figures 3 and 4 show similar data for ethane and n-butane. Inthe case of ethane, both ethane liquid at 60:' F. and ethane vapornear its critical point were tested. Solubility in ethane liquid ismuch lower than in propane liquid, and in supercriticial ethane itis less than 1% the solubility in liquid ethane.
As one might expect, tar is more soluble in butane than propane,and more soluble in pentane than butane, as compared in Figure5. Note that temperature and pressure have much less effect onsolubility than mixture composition. Mixtures of these solventswere also tested, and it was found that solubility was non-linearwith solvent composition.
If one assumes that all of the original tar not dissolved in thesolvent rich extract phase exists as a separate solid phase. and notas a separate heavy oil phase containing some propane. a materialbalance may be made to obtain the fraction ot original tar dissolvedin the solvent. Based on this assumption, lines ot constant percentof tar dissolved or "recovered" are shown in Figure 5. Thoughnot evident in this figure, "recovery" calculated this way wasfound to exhibit a minimum as wt.% tar in the mixture increasedfrom zero, approaching 100% near 60-70 wt% tar as mentionedpreviously. Regardless of whether one accepts the assumption ofthe material balance rhat all of the propane is in the extract phase,it is clear that when the extraer phase composition equals thetotal mixture composition, the whole tar is completely dissolved.
Perhaps a better way to express the results of these phasebehavior studies is ro state that propane (for example) may beadded ro Athabasca tar up to about 30 wt.% before any solidswill precipitare.
Properties of the Extract Phasesand the Recovered Tar Oils
For any potential recovery process using propane, it wouldalso be important to know the viscosity of the solutions formed.
I
!,i
rI
-51-
70
o 9O'F, llOO PSIAo 9O'F, 1000 PSIA• 9O'F, 100 PSIA• 4O'F, 200 PSIAo 4O'F, 800 PSIAa VlUllOUSllOO PSlA
60
~ m ~40 ~ 60 ro 00 90WEIGHT PERCENT ATllABASKA TAR IN OVERALL MIXTURE .
FIgure 4. Butane-Tar System EquilibrIum ExtractIon DataFigure 3. Ethane-Tar System EquilibrIum Extraction Data
70
,/• ,60 "I- ,,/"
0 ,,"G!110 ,I- ,,"~ ,
:!: ,,/".J 40(5 ,,'" /'i! 30 ,I- ,,"~. //~ 20
,,/"!i:<:l
,,/~ 10,,"
,,"0
900
Even if the tar is mined from the surface as it presently is,these phase behavior and viscosity data have implications. for asurface separation process which might be better than the presenthot water process. The raw tar could be mixed with just enoughpropane in an enclosed vessel at relatively low pressure (less
•
than propane vapor pressure), to obtain a suitable viscosity forrapid settling out of the sand.
Figure 6. Extract Solution Viscosity vs. Composition at1500 PSIA @ 90°F
d
FIgure 7. Extract Solution Vlscosltyvs. Composition at1500 PSIA
90ro ro ~ ~ 00 ~ ro 00WEIGHT PERCENT ATHABASXA TAR IN OVERAll. MIXTURE
Figure 5. Comparison of Various Solvents
60
70
Therefore, experimental equilibrium runs were made to obtainen.)ugh solution for viscosity tests ina rolling ball viscometer.The results are shown in Figure 6 where the extract solutionviscosity is plotted versus the composition of that solution.Note the point near 65 wt.% tar oil; it is close to a solution ofthe whole tar and it has a viscosiry near one centipoise. Althoughthe viscosity curve above 65 wt.% must be inferred, it is clearthat small amounts of propane added to Athabasca tar drasticallyreduce its viscosity, beginning from the semi-solid original material.Figure 7 shows similar data at 90'F and 145"F, showing that thetemperature dependence of the viscosity of these solutions isnot severe.
•
-52-
-53-
.J180
lI.JC - FIELD A::> 16a:
6 ZONE A-I0
::E oZONE A-20 14a:IL.
c 12wl;t~a:uwfwzw.!3 6
lCI) 4~I-Z 2lI.J0
~
~~
One problem with solids precipitation, which is a perpetualnuisance in oil production operations, is the plugging of tubingby precipitated "wax". As an extension of that probl~m, therewas also concern that solids might even be precipitated in thereservoir under some conditions and thereby r~duce th~ pro-ductivity of the formation.
Figure 10. Asphaltene Precipitation Test
the results of some direct measurements of the weight 6f S9lidsprecipitated from a 13.50 API crude oil from Four Bear Field,Wyoming, upon addition of propane to the stock tank oil. Thedata are 1300F and 500 psia. Up to 40 wt. % propane may beadded to the oil before any precipitation occurs, somewhatmore than for Athabasca tar. Thus, the threshold for precipitationwill vary for each crude, being higher for high degree API crudesand lower for heavier crudes, but in general for low API oils, itis in the neighborhood of 35-40 wt.% for propane .
To assess that problem for a particular reservoir oil, someexperiments were run on a bottom hole sample of the originaloil from Rainbow Field, Alberta, in a rolling ball viscometer.The viscometer was us~d to detect the first minute particles ofsolid precipitated because it was known to be very sensitive todirt or emulsified water particles. It would be very difficult todetect the beginning of precipi~ation using filt~rs und~r pressur~,as was done for the measurement in Figure 10. The viscomet~rwas connected to a storage vessel with a circulating pump, all ina thermostatted air bath. At the initial reservoir pressure, theviscometer was operated at successively lower temperatures,beginning with the reservoir temperature. The roll time datawere plotted versus reciprocal absolute temperature as shownin Figure 11.2 Such a plot is expected to be essentially linear fora homogeneous oil phase of constant composition (maintainedby isolating the initial oil in the viscometer).
o ~ ~ ~ ~ ~ ~ ~ ~ ~ ~nIGHT PtRCEHTRa::O'tO't
Figure 8. Viscosity of Tar Oils vs. Recovery
.. WE/GHT PDlCEHT IlEtOI!In'
rd'o
Figure 9. Specific Gravity vs. Recovery
Other Data with Heavy Crude Oils
LOO
Still farther downstream, propane extraction might be used
•a refining process to separate product streams having specified
operties. To this end, the viscosity, specific gravity, and colorof various tar oil extracts were measured and observed. Figure8 shows the viscosity of the extracted oil versus the recoverylevel, at three temperatures. By sequential extraction operations,one could effectively fractionate these tar oils as well.
Figure 9 shows the specific gravity of the extracted tar oil
~
rsus recovery level. It was observed that the first 20 wt.% oftar had a bright, clear yellow color and the first 37 wt.%s still very transparent and yellow-orange in color. At the
50-55% level of extraction, the tar oil was reddish-brown andtransparent in thin sections only, and at the 69% level the oilwas bro'W"l1ish-blackand completely opaque even in thin sections.
•order to show the phase behavior observed with the
abasca tar, light hydrocarbon systems applies equally wellto crude oils, a few additional data are shown. Figure 10 shows
&
TEMPERATURE I of
Figure 11. Determination of the Wax Point of a Reservoir011
- ATHABASCA TARAT 90 OF
o FJELD A550 PSIA, 130 "F
6 FIELD B1500 PSJA. 120 OF
A Generalized Description of Light Hydrocarbon-CrudeOil SoL Phase Behavior
Figure 12. Viscosity vs. Composition
The viscosity behavior of crude oil-propane solutions parallelsthat observed for Athabasca tar as shown in Figure 12. Thehigher the initial oil viscosity, the more dramatic is the viscosityreduction per mol of propane added.
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Since no oil viscosity correlation is capable of accuratelypredicting oil viscosity as a function of the composition of thedissolved gas, a few data showing these effects are given inFigure 13. In Figure 13, oil viscosity is shown vs. the amount ofpropane in the methane-propane gas phase in equilibrium withsaturated oil. Ten mol percent propane in the gas reduces oilviscosity to one-half its value with only pure methane dissolved.The proportion of propane in the dissolved gas would, of course,be higher. This illustrates the effect on reservoir oil of injectinggas of the composition shown on the abcissa.
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10~o 20 40 60 80 100WEIGHT PERCENT PROPANE
10'250
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After the lowest temperature was tested, the system was re-heated to reservoir temperature and recirculated for long periods(minimum overnight, sometimes for a week) to be sure anyprecipitated solids were dissolved. At that point, a differentialgas liberation was made from the storage vessel to reach a lowerpressure, and again after considerable circulation, saturated oilwas isolated in the viscometer and a temperature traverse repeated.This cycle was repeated at the four pressures shown. At thethree lower pressures, a discontinuity is evident, where theviscosity suddenly increased at a higher rate beginning at somelower temperature. Although this is indirect evidence, it isinfertedthat some solid began to precipitate at the discontinuity tem-perature, causing the rolling ball to slow down. Note that as gasis removed from solution (pressure decreases), precipitationbegins ata higher temperature. In other words, natural gas(preponderately methane) in solution helps to keep solids dis-solved. This is precisely the phenomenon observed in somesimple systems using methane3• Thus, even methane acts as agood solvent for solids in an oil solution!
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•This aspect of the so-called "paraffin precipitation problem"
had scarcely ever been considered. It was always looked uponas a temperature problem; i.e., due to cooling of oil as it flowsup the tubing. But now it is clear that "wax" also precipitatesbecause gas comes out of the solution as pressure decreases upthe tubing!
For the oil tested in Figure 11, the temperature for onset ofprecipitation never reached the reservoir temperature as pressuredecreased, so fortunately no solids precipitated in the reservoir.But this oil did produce extensive deposits of solids in thetubing, as these data infer.
It is believed that the data shown are sufficient to draw somegeneral conclusions as to the phase behavior to be expectedfrom solutions of light hydrocarbons such as methane, ethane,propane, butane and mixtures thereof in crude oils, especiallyheavy crude oils and tars.
In no case were specific experiements made with oil, in whichexcess solid was present initially. However, the data in Figure11 show that at the discontinuity temperature for 514 psiawhich is about ll00F, that oil with more gas dissolved up to1514 psia will not precipitate solid until a temperature of about97°F is reached. This means that the 1514 psia oil at llOOFcould hold more solids dissolved than it does!
-54-
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Flao a. I- 0 BOTTOM HOLE OIL AT 200 PSIA laPP)"- 0 1000 PSIA SATURATION PRESSURE •
6 1500 PSIA SATURATION PRESSURE
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above the maximum. One way to avoid this is to injece propanein a carrier gas of methane4• The propane concentration in theinjected gas may be controlled such that in contact with reservoiroil, the resulting propane concentration in the oil is below themaximum where precipitation of solid begins. The parametersof any such operation would have to be determined experimentallyin the laboratory for a given oil because none of these S.Lequilibria may be predicted. It is a technical area that begs formuch research .
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0-7HHf-+++-lf-+f-HH-&-++++-t-H~--J.-++-lllI.J'
~ 6 H-++HH-++H-+-H-+-I-+-1-+-+-I-I--+--1-HD::
~5Hf4f.t-1--1-+-!I-+-H-++-H-+-H--J.+-I-+-t-I-I-+-4lIV\/~~ 4 H-+-I-t-+-II-t-+-t--+-l-H-+-l--t--I-+4-I-!-+-l-+-4l
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024 6 8 ~ ~ ~MOL "10 PROPANE IN EQUILIBRIUM GAS CAP
Figure 13. 011 Viscosity vs. % Proprane In Equilibrium.Gascap
Thus, the general case can be best illustrated by defining anexperiment as follows. Suppose that we start with a mixutre ofoil and excess hydrocarbon solids and gradually dissolve moreand more of a light hydrocarbon in the oil. As the light hydro-carbon concentration builds up in the oil, solids material willalso gradually dissolve in the oil until a point of maximumsolids concentration in the oil will be reached at some lightsokent concentration. When solvent concentration in the oil isincreased beyond the maximum point, dissolved solids will!'It'~in to ptecipitate back out again and do so monotonically assokent concentration increases.
In the practical case, the oil as well as the solids is a complexmixture of components of varying molecular weight and structure.Thus, in any solution or precipitation process we shall expectlow molecular weight solids to be more soluble than highermolecular weight components, other things being equal. Weshould also expect solubility preferences to follow the principlethat structural! y similar molecules are more compatible in solutionthat dissimilar molecules. This means that methane dissolved inoil may tend to dissoke more paraffinic solids than aromatics'llids (asphaltenes?) although it will enhance the solubility ofboth. Thus, the so-called "paraffin deposits" in tubing are reallya mixture lJf various molecular structures depending on theirdistrihution in the original oil.
The problem which these phase behavior data pose for appli-cation to a reservoir recovery process is as follows: 'How may
•e create the less than maximum concentration of the light
lvent in the reservoir?' For example, if one injects propaneInto a heavy oil reservoir, he will almost certainly plug up thewell by heavy precipitation because the mixtures formed in theinjection well area will all be high concentrations of solvent
Figure 14. Post-simulation oil rate Increase farWell A
Field Test of Suggested Process.
The above ideas were embodied in a field test conducted byAmoco in the East Velma Field, Oklahoma, about 19654.5. Atthat time, reservoir pressure was 400 psia, oil viscosity was 18cpo and test weI! No. 1 was producing seven barrels per day of20-25° API oil. After an initial injection of 50 barrels (bbl.) ofgas-condensate liquid to wash out the perforations (well had"parafin" problems), 2 MMSCF of gas containing 198 bbl. ofpropane were injected over a period of a few days. A.fter a oneday shut-in period, the well was opened for proJuctinn and itflowed initially at 71 barrels per day. It sUbSelju,'nti, t,)c)k about70 days to decline to its pre-test rate of seven b'lrr<:l" per day.During the production period, GOR varied between 2000 and3000, up from its pre-test value of 700 SCF/bbI.S[d. During thisperiod, 436 barrels of extra oil had been rroduceJ. A.t 51 days'time the ratio of extra oil to as yet unreco'.ered rr"rane was 6: I.A second and third such cycle were carried out nn this well withroughly similar results. Figure 14 shows the' tV1'ical producingrate versus time history.
In a second test well about 900 ft. hi>!her in [he ("rmation(producing 50 barrels per day pre-test), 4l~ M~ISCF "f gas con-taining 50llO bbL of propane were injected over a reriod of 19days. After three shut-in days, the weI! was orened to productionat 120 barrels per day. However, the true potential rate wasunknown because pumping equipment could not keep pace withthe inflow from the formation. 1n any case, 10 months later thewell was still producing 100 barrels per day. After 313 days, atotal of 12,500 extra barrels of oil had been produced. Figure 15shows the prooucing rate history.
-55-
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Acknowledgement
The emphasis in this discussion has been on propane as the"solvent," but many other mixture compositions could be used.Design of the operation must begin with lab test data Showingviscosity reduction and solids precipitation limits. For moresolid economic projections, a mathematical model of the processcould be used for simulation studies.
APR JUlY»ON APR JUlY OCT .1IINOCT
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) MY SOI\XlHC .P£IlIOD~S IN"(CTIOH CYClE
~~- . - - . - -H PREST MUlATlOH RATE • 51 80PD
Figure 15. Post-simulation performance of Well B.
These are the onl y documented test data available. An attemptwas later made to test the process in Venezuela, but it failedbecause too high a concentration of propane was injected andthe well plugged up as predicted.
An advantage of single well huff-and-puff type operation isthat most of the propane remains near the well and recovery ofit will be inherently high. If all the wells in the field wereoperated this way, efficiency would probably be higher becauseproduced gas may be adjusted for propane concentration ande:reinjectedinto wells on the injection part of the cycle. Furth'er-
ore, energy available for production will also average higherecause adjacent wells are being injected at the same time.
Other producing patterns such as well to well may be consi-dered, and carrier gases other than methane may be used; i.e.,nitrogen, flue gas or carbon dioxide. Depth is also no limitation,working equally well shallow or deep. However. proper consid-eration must be given to the lifting system. If too much gas andsolvent are allowed to come out of the solution while movingup the tubing, oil viscosity will rise substantially and reduceflow rate. Perhaps gas-lit is an appropriate lifting method .
The author wishes to thank the Amoco Production ResearchDept. for the 1982 release of the data on Athabasca tar.
References
1. Blair, S.M.; "Report on the Alberta Bituminous Sands,"Province of Alberra Report, p. 46 (1950).
2. Jacoby, R.H. and Yarboroguh, L.; "PVT Measurements onPetroleum Reservoir fluids and Their Uses," Ind. Eng. Chern.,5949 (1967).
3. Kohn, J.P. and Luks, K.D.; "The Effect of Methane UnderPressure on the Liquid Solubility of Hea,'y HydrocarbonComponents," Final Report API Project 135. Aug. 1974.
4. Jacoby, R.H., Morris, E.E., and Robinson. R.L.: "Recoveryof Oil by Means of Enriched gas Injection," U.S. Patent3,456,823 (1969).
5. Shelton, J.L. and Morris, E.E.; "Cyclic Injection of RichGas into Producing Wells to Increase Rates from ViscousOil Reservoirs," Journal of Petroleum Technology. Aug. 1973,p.90.
6. NATO ASI Series E, No. 76, p.l (1984), Ankara, Turkey.
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