1

No. 1998.206

Crude Oil Characterization and PVT Studies on Prudhoe Bay Heavy Oil/Tar Mat

Raj Srivastava and Arden Strycker, BDM Petroleum Technology, Bartlesville, Oklahoma, USA; and Richard Charles, PENCOR Group of Companies, Broussard, Louisiana, USA

Abstract

The Prudhoe Bay field, located at north coast of Alaska, ischaracterized by a variable thickness heavy oil/tar (HOT)zone lying just above the water-oil contact and below the lightoil column. Oil-in-place for the HOT zone is estimated at over1.5 billion reservoir barrels. A joint industry study has beenundertaken with the goal of developing a suitable recoveryprocess for the HOT zone.

In order to develop an economically viable process, thecharacterization of the oil and simulation of the candidaterecovery process are essential steps. However, the actual dataon rock and fluid properties for HOT are scarce. There is alsopotential to use enriched gas injection for oil recovery fromthe HOT zone. Since the overlain light oil column is undergo-ing tertiary gas injection, a source of enriched hydrocarbongas is available for the purpose. To assess the suitability ofgas injection process, PVT data on oil-injection gas systemsare required. This paper discusses oil characterization andPVT data generated using bottom hole samples of live oil andsurface samples collected from the reservoir. The results ofPVT studies conducted with the live oil and an enriched injec-tion gas are also presented.

The studies conducted on the various oil samples obtainedfrom the Prudhoe Bay HOT zone indicated that the viscosity ofthe live oil at the reservoir temperature and pressure condi-tions was surprisingly low and was comparable to oil found inthe light oil column. The asphaltene content was high asexpected. Since the hydrocarbons in the zone were thought tohave been relatively immobile based on previous logs, theresearch focus is being shifted to the fluid analysis ofextracted core plug samples.

Introduction

The Prudhoe Bay oil field is located about 250 miles (402 km)north of the Arctic circle on the north coast of Alaska. Thefield was discovered in 1968 and is known to be the largest oilfield in North America.

1

Over 95% of the field reserves arefound in the Ivishak Sandstone Formation of the SadlerochitGroup.

2

For this reason it is also referred to as the SadlerochitReservoir or Sadlerochit Sandstone or the Main area. Other

intervals include Sag River Formation and Shublik formationor Eileen area.

1

The Sadlerochit formation is a fluvial-deltaicsequence of sediments consisting of sandstones, conglomer-ates and shales with an average thickness of 550 ft.

3,4,5

At discovery, the reservoir had a large gas cap in contactwith the oil zone covering approximately two thirds of the col-umn. The gas-oil contact in the Main area was found to occurat a subsea depth of about 8,578 ft. The oil-water contact wasfound irregular and slightly titled ranging between 8,990 and9,050 ft. The Main area contained over 22 billion stock tankbarrels of oil and 40 trillion standard cubic foot of gas origi-nally in place.

1

The oil zone is considered to consist of a light-oil column(LOC) overlying a relatively low API gravity crude oil zone.This zone is termed the heavy-oil/tar (HOT) zone. The maxi-mum oil thickness in the Main area was 465 ft versus 205 ft inthe West End. The maximum thickness of LOC in the fieldexceeded 400 ft. The reservoir original pressure was approxi-mately 4,400 psi at 8,800 ft.

HOT interval occurs throughout the Main area immediatelyabove the water contact. The thickness of the zone varies from20–80 ft. HOT zone is pillow shaped with an irregular basevarying from 8,969–9,069 ft subsea. It is lacking in the westend where oil-water contact is generally 50–60 ft shallowerthan the Main area. The accumulation is thickest where the oilcolumn is deepest. The thinner areas are generally found inthe southeastern one-third of the field. The zone is separatedfrom the LOC by shale complexes having limited vertical per-meability. The shale areas exhibit low to moderate continuity.HOT zone is estimated to contain 1.5 billion reservoir barrelsof hydrocarbons. It is considered to be largely immobile withlow oil saturation. It plays an important role in reservoir per-formance by acting as a partial barrier to water influx.

1

There is a very large associated aquifer at the bottom of theoil rim. The rock quality in the aquifer is poorer than in thehydrocarbon column. The formation water has an averagesalinity of about 18,000 ppm NaCl.

2

Fluid Properties

Fluid properties are fairly well established for the light-oil col-umn but are still uncertain in the HOT zone. Oil gravity inLOC of the Main area varies from about 30° API at the gas-oilcontact to about 26°API immediately above the HOT zone. Itdecreases rapidly below this value in the HOT interval to lessthan 15° API.

6

The oil viscosity in LOC ranges from 0.5–1.2cP at the reservoir conditions and the solution gas-oil ratio(GOR) varies from about 900–650 scf/stb (162–117 sm

3

/m

3

).Initial reservoir pressure in the Main area ranges from 4,335psi at the gas-oil contact to about 4,480 psi at the water-oilcontact. The reservoir temperature varies both arealy and lat-erally and ranges from about 185–240°F.

1

Table 1 summarizesthe fluid properties for the Prudhoe Bay reservoir HOT zone.

Objective

Since the discovery of the reservoir, LOC has been the targetof oil recovery. Waterflooding of the reservoir followed byCO

2

miscible flooding is being utilized for the enhanced oilrecovery. As the light oil production and resource declines,alternate targets are being investigated to enhance productionand reserve. A cooperative work between BP Exploration, Inc.(BPX) and BDM-Oklahoma was initiated to develop a recov-ery process for the heavy oil resident above the oil-water con-tact and beneath the LOC at Prudhoe Bay. Primary productionand waterflooding recovery factor for HOT has been estimatedto be quite low, about 2–3.5% of the original heavy oil inplace. Approximately 7.5 Bscfd of gas is currently beingcoproduced, processed, and reinjected at Prudhoe Bay. Hence,gas injection appears to be a suitable alternative. Several gasinjection processes will need to be evaluated for improving theheavy oil recovery. Oil characterization and simulation of can-didate recovery processes will form essential steps in develop-ing a viable economic system to implement the heavy oilrecovery.

Heavy oil viscosity is expected to be the most importantparameter affecting the heavy oil recovery. Viscosity affectsthe heavy oil mobility, injectivity, and well productivity. Thefirst goal of this project is to design and conduct laboratorypressure-volume-temperature (PVT) experiments and todevelop an equation-of-state (EOS) model for predicting andcorrelating the heavy oil phase behavior and PVT properties.The second goal of this work is to validate the phase behaviormodel by conducting laboratory coreflood experiments andperforming compositional simulations. The phase behaviormodel will then be used in compositional simulations to eval-uate various heavy oil recovery processes. An economicallyviable candidate recovery method would be evaluated in afield pilot test. This presentation focuses on the first goal.

Experimental

Phase behavior studies on the surface and bottom hole sam-ples received from Prudhoe Bay reservoir HOT zone wereconducted in a PVT apparatus. Figure 1 depicts the set up. Theunit is equipped with a PVT cell connected to a capillary tubeviscometer and an on-line densitometer for measurements.

The experimental apparatus consists of a mercury-free vari-able volume high pressure cell housed in an oven and con-nected to a dual piston Temco pump. The PVT system iscurrently rated to 10,000 psi maximum working pressure at250°F. The apparatus allows visual observation of the contentand interface location through a glass viewing window locatedat the fluid end with the help of a cathetometer. A linear trans-ducer (LVDT) is attached to the front face of the piston foraccurate volume measurement. There are provisions to mea-sure the cell temperature at two locations deep in the body. Apressure transducer mounted on the cell measures the fluidpressure. The cell can be rocked with the help of a motorassembly for mixing the cell contents. An inlet port located atthe bottom of the cell can be used to sample the aqueousphase. Another port located at the top can be used to samplethe vapor phase. The cell can be tilted to aid in sampling anyphase, if required.

The PVT cell was connected on-line to a Anton Paar modelDMA 512 densitometer and to a capillary tube viscometer formeasuring density and viscosity of the phases. To minimizepressure effects during viscosity measurement, the capillarycoil was inserted in a 3/8” diameter stainless steel tube. Theinterior of this tube was filled with a pressure medium and wasmaintained at the pressure of measurement. These units werelocated in the oven for measurement at the temperature andvarious pressures of interest. Standard procedures were usedto calibrate these units, PVT cell and LVDT.

A unit required for a flash of the pressurized oil sample andthe measurement of gas-oil ratio (GOR) was also constructed.This allowed separation of a pressurized fluid sample intoatmospheric gas and liquid phases for chromatographic analy-sis. The purpose of the unit was to obtain as close as possible aC6

-

gas phase and a C7

+

liquid phase. This unit was modifiedto accommodate the extremely foamy oil we encountered dur-ing the first flash of the fluid from well F–17A which is fromPrudhoe Bay’s heavy oil zone.

3

Results

Stock Tank Samples from Wells DS 9–31B and F–17A and DS9–31B Simulated Reservoir Fluid

We received initially stock tank oil samples from Prudhoe Baywells DS 9–31B and F–17A at a depth interval within theheavy oil zone. The samples contained from 4–48 wt% water.Hence, they were centrifuged at 20,000 RPM to separatewater. Compositional analyses and physical property mea-surements on these samples were completed. The composi-tional analyses included a detailed hydrocarbon analysis(PIANO) up to C9- and a simulated distillation (ASTM-D5307) to a C40+. The two were tied together for a completeanalysis. Results for the original sample were adjusted for thelighter end components lost in the centrifuge process.

The compositional distributions of the two samples arecompared in Figure 2, and the physical property measure-ments are presented in Table 2. Except for the measured vis-cosity at ambient conditions, the two samples were verysimilar.

EOS Model and Viscosity Correlation

The surface samples were evaluated for use in generating areservoir fluid sample by laboratory recombination with a syn-thesized separator gas. The purpose was to obtain preliminaryestimate of the PB heavy oil properties. The compositionalanalysis was used to represent the DS9–31B oil in terms of theEOS pseudocomponents in the Prudhoe Bay fluid character-ization. The fluid characterization was originally developedand extensively validated from the light oil data. British Petro-leum Inc. (BPX) has extended the characterization for model-ing of the heavy oil phase behavior by adding an asphaltenepseudocomponent. The EOS characterization was applied topredict the density and viscosity of the DS9–31B sample inorder to help evaluate surface samples, design laboratory PVTexperiments, and obtain preliminary estimates of the heavy oilfluid properties. The shift parameter and the critical z-factor ofthe asphaltene pseudocomponent were adjusted, respectively,to match the crude oil density and viscosity measurements.EOS predicted density of the oil at 68°F was found to be 0.921g/cm

3

against measured 0.926 g/cm

3

and viscosity to be 101.8cP against measured 98.5 cP. The agreement between the mea-sured and predicted values was considered satisfactory andwas used to determine the composition of separator gas.

Composition of Separator Gas for Recombination

Composition of separator gas to be recombined with the DS9-31B sample was calculated as follows. An estimate of theheavy oil composition at a depth of 8,990 ft subsea was avail-able from a BPX study, which modeled compositional segre-gation with depth in the Prudhoe Bay field. This model oilcomposition was used to simulate the sampling process and

predict the composition of sampled stock tank oil. The pre-dicted stock tank oil composition was used to adjust the mea-sured DS9-31B oil composition for the missing CO

2

, N

2

, CH

4

,and C

2

H

6

components in the surface oil sample. The adjusted,surface oil composition was subjected to a simulation of thereversed sampling procedure to arrive at a reservoir fluid com-position, using an assumed surface GOR value of 500 scf/bbl.Table 3 presents the model calculated stock tank oil, theadjusted surface oil, and the simulated reservoir fluid compo-sitions for the DS9–31B oil. Finally, the separator gas compo-sition to be used for recombination was determined bysubtracting the stock tank oil composition from the reservoirfluid composition and is shown in Table 4.

Viscosity Predictions

The reservoir fluid composition was next subjected to a simu-lated constant composition expansion experiment at a reser-voir temperature of 224.4°F. The predicted viscosity with anincrease in pressure is plotted in Figure 3. The model calcu-lated a viscosity of 12.2 cP for the DS9–31B oil at the calcu-lated bubble point pressure of 3,160 psia. For an increase inoil viscosity from 150–600 cP at surface condition, the pre-dicted reservoir condition viscosity increased from 12.2–37.6cP. This preliminary simulation study suggests that the21°API, Prudhoe Bay heavy oil is 10– 40 times more viscousthan the light oil, which has a viscosity of about 1 cP at reser-voir conditions.

Well F17–A Synthetic Reservoir Fluid

The surface stock tank oil sample from well F–17A was ini-tially evaluated for use in generating a reservoir fluid sampleby laboratory recombination with a synthesized separator gasand to compare the measured viscosity of the reservoir fluidwith that obtained using EOS model. The primary concernwas whether the water-oil emulsion could be broken and thewater successfully removed from the surface sample withoutaltering the hydrocarbon sample. Heat treatment at 150°F and200 psig followed by centrifugation did not completely breakthe water-oil emulsion. An alternate method of passing thesample over anhydrous calcium sulfate desiccant was testedand was found effective in removing water from the stock tankoil sample.

A 600 cm

3

sample of water-free stock tank oil was com-bined with a synthetic gas to a GOR of 500 scf/bbl in the PVTcell for reconstituting the synthetic reservoir fluid. The gascomposition required for this reservoir fluid needed to be sim-ulated by EOS because solution gas from Prudhoe Bay is pro-duced along with lift gas. It was calculated using the methodoutlined for oil from well DS9–31B in the last section.

A small portion of the reservoir fluid was flashed to roomconditions and analyzed. The results are listed in Table 2 andcompared with the surface oil samples obtained earlier fromwell F–17A. The repeatability for the pentane insoluble exper-

4

iment is estimated to be four percent. Considering that thesesamples are uniquely distinct from each other, the match isconsidered reasonable. The variance in viscosity could be theresult of differences in asphaltene content, water content, anddensity of the two oils.

The room temperature bubblepoint of this synthetic samplewas measured at 3,312 psig at 74°F. Approximately 200 cm

3

of the reservoir fluid was then charged to the PVT cell at 5,000psig and the reservoir temperature of 224°F and the physicalproperties were measured and are provided in Table 5. Thesaturation pressure of the fluid was found to be 3,770 psig at224°F. The density and viscosity of the synthetic reservoirfluid was measured in the single phase region. These resultsare depicted in Figures 4–5. The viscosity of this fluid at thereservoir temperature was very low at 1.84 cP. This viscosityis pretty close to the viscosity of reservoir fluid from the Prud-hoe Bay LOC and does not represent it as a heavy oil. Thisvalue is also considerably lower than that obtained for theDS9–31B simulated reservoir fluid using EOS modeling. Thecomposition of the reservoir fluids is listed in Table 3. A com-parison of the reservoir fluid compositions for the two oilsshowed that the DS9–31B simulated reservoir fluid is richer inlighter hydrocarbons than F17–A synthetic reservoir fluid.However, the viscosity of the simulated fluid was higher thanthe synthetic fluid. This may suggest that the EOS model waspossibly not able to predict the viscosity of the reservoir fluidsatisfactorily or composition segregation with depth providedby BPX needed improvement.

Well F17-A Bottom Hole Samples

We also received two bottom hole samples from well F17–A.These samples were available in sample cylinders rated to1,800 psig. An initial quality check was performed on thesesamples by measuring their room temperature bubblepointpressure. One of the samples had a bubble point exceeding1,800 psig and could not be determined. The bubble point ofthe other sample was determined to be 2,005 psig at roomtemperature. This sample was selected for further analysis atthe reservoir temperature.

The saturation pressure of the bottom-hole sample at 224°Fwas found to be approximately 2,600 psig. This value is over30% lower than that of the synthetic reservoir fluid. This sug-gested that this bottom hole sample was possibly undersatu-rated and could be the result of the sampling process.

A flash of the bottomhole sample from well F–17A wasperformed. The measured GOR of the sample was 507 scf perbarrel of residual oil at 60°F. Although this GOR was similarto the GOR of the synthetic reservoir fluid sample, the molepercent of the lighter components, particularly carbon diox-ide, was much less in the bottomhole sample than in the syn-thetic sample (Table 3). This variation in the light ends of thehydrocarbon composition could account for the difference inthe saturation pressure observed. Table 3 compares the com-position of the bottomhole sample with that of the synthetic

reservoir fluid from well F–17A. It appears that the bottomhole sample contained more heavier fractions than the syn-thetic fluid. For this reason, density and viscosity of the bot-tom hole sample (which were not measured) will be expectedto be slightly higher than the synthetic fluid.

Well B–36 Bottom Hole and Surface Samples

We also received a surface sample from Prudhoe Bay’s HOTzone well B–36. The API gravity of the stock tank oil wasapproximately 21.1°, however the water content was over47%. Because of the high water content, viscosity and asphalt-ene content of the surface sample was not determined (Table2).

Two bottom hole samples from well B–36 were alsoreceived for analysis. The room temperature bubblepoint ofboth bottomhole samples was measured at 76°F. Fluid in cyl-inder 1 had a saturation pressure of 2,084 psig and the fluid incylinder 2 had a saturation pressure of 2,138 psig. Bottomholereservoir fluid from cylinder 2 having a higher saturation pres-sure was used in subsequent analyses. A separator flash wasperformed on this bottomhole sample from well B–36. Thestock tank fluid recovered from the separator flash was used todetermine the water content, asphaltene content, viscosity,API gravity, and SARA analysis. Table 6 lists the results ofthe separator flash and Table 7 provides the SARA analysisresults.

The two sample cylinders were maintained in a verticalposition for a period of one week. A check for free water pro-duced 75 cc of water from cylinder 1 and approximately 17 ccof water from cylinder 2. The cylinders were then placedinside an oven and heat treated for an additional week. Noadditional water was found.

Initial test involved the measurement of the bubblepointpressure of the fluids at room temperature of 76°F. This indi-cated that the samples remained essentially unchanged sincesampling as the measured values were in good agreement(2,084 psig from cylinder 1 and 2,138 psig from cylinder 2).Before we attempted to measure the phase behavior propertiesof these bottomhole samples from Prudhoe Bay’s HOT, weneeded to restore the fluids, as much as possible, to nativestate. The cylinders were pressurized to the maximum cylin-der rating of 5,000 psig and agitated for a period of twoweeks. This process disperses the asphaltenes, as much aspossible, back to their original state.

Once the restoration process was complete, several smallportions of hydrocarbon sample from cylinder 2 were dis-placed for compositional analysis, SARA analysis, and for aseparator flash test. The oil had an API gravity of 22.5° and anasphaltene content of 10 wt%. A small portion of the reservoirfluid from cylinder number 2 was then charged to a high pres-sure, PVT cell which was at room temperature. The samplewas then thermally expanded to the reservoir temperature of207°F and the system equilibrated. A pressure-volume rela-

5

tions experiment was performed on this sample and the satura-tion pressure was determined to be 2,748 psig at 207°F. Thedensity, viscosity, and formation volume factor of the fluidwere measured. These measured physical properties of thereservoir fluid are listed in Table 4 and compared with the F–17A reservoir fluid.

Solubil ity-Swelling Tests with F–17A Bottom Hole Samples

Since miscible injectant gas available at the reservoir sitecould be a possible recovery candidate, a solubility-swellingexperiment using this gas was performed on the bottomholesample from well F–17A. Particular attention was paid to theappearance of precipitated asphaltenes. The composition ofthe miscible injectant gas can be found in Table 8. Using themeasured miscible injectant gas composition supplied byBPX, a sufficient quantity of gas was synthesized for thisexperiment. In order to perform phase behavior experimentsusing this miscible injectant gas, the compressibility- or Z–factor of this gas mixture at reservoir temperature needed tobe determined.

The miscible injectant gas was transferred from the originalmanufacturers cylinder into a high pressure storage cylinderand maintained at laboratory temperature and 5,000 psig. It isinteresting to note that at these conditions the injectant gasexists as a liquid. A small portion of the miscible injectant wascharged into the PVT cell and heated to the reservoir tempera-ture of 220°F. The gas-phase compressibility factor of theinjectant was determined over the pressure range of 5,000 and1,000 psig. The results are graphically presented in Figure 5.Due to the small inconsistencies of the LVDT and the sensitiv-ities of the Z–factor calculation, it was decided that anotherapproach was needed to verify our results. Room temperaturedensity and grams per standard cubic centimeter measure-ments were obtained. These measurements were repeatableand verified our Z–factor data from the PVT cell.

The solubility-swelling experiments covered the injectionrange from 10–70 mole percent gas per original oil from6,500–2,000 psig. Variation in the saturation pressure of themixture with an increase in injectant gas concentration is dis-played in Figure 6. Phase volume measurements and satura-tion pressure determinations were conducted at each injectionstage.

The completed solubility-swelling experiment is presentedgraphically in

Figure 7

. The viscosity and density measure-ments for a 70 mol% mixture could not be determined as thismixture was two-phase at 7000 psig. There is a possibility thatasphaltenes might be precipitated at 30 mole percent injectant.This observation might be confirmed by asphaltene floccula-tion onset experiments using near-infrared technology by sep-arate experiments.

Physical Properties of HOT Zone Fluid

The viscosity and density of the bottom hole samples fromwell B–36 and synthetic fluid F–17A at reservoir conditionsare noted to be nearly the same at about 2 cP and 0.77 g/cm

3

.The viscosity of this fluid is close to that observed for LOCfluid which varies from 0.5–1.2 cP.

1

The measured formationvolume factor for B–36 fluid was 1.32 vol/vol and is similar tothat obtained for LOC fluid which varies from 1.3–1.4 with anaverage value of 1.36.

1

These measurements indicate that theoil produced from the HOT zone is similar to the LOC fluidexcept for slightly higher asphaltene content. Asphaltene con-tent of the LOC fluid is < 5 wt% whereas it varied for the HOTzone fluid from 10–15 wt% (Table 2).

It is noted that the viscosity of the produced fluids fromHOT interval is low and does not represent a heavy oil. Itwould be expected that this oil should be easy to produce.However, log data and laboratory tests conducted with HOTcore samples have shown that the oil in the zone is relativelyimmobile and the effective permeability to water through theHOT interval is about 1 mD.

6

This poses serious questions onthe reasons for poor mobility of the HOT zone.

It has been observed that there is considerable difference inthe fluid produced from the HOT interval and the oil found inthe core samples obtained from the HOT zone. If the HOTzone hydrocarbons are immobile as the past studies

6

indicate,the produced fluid from HOT interval most likely either doesnot represent or poorly represents the oil from the zone. Thebottom hole samples collected from the HOT interval, in alllikelihood, represent only the mobile fraction of the hydrocar-bons in the reservoir. Our results indicate at least two possibil-ities:

1. The HOT zone actually consists of three sections (seeTable 1) as has been suggested by some researchers. Thesection at the top of the HOT interval represents a rela-tively lighter mobile oil than the rest of the interval. Thisoil is produced and collected as the bottom hole sample.The characteristics of this produced fluid represent thetransition zone oil from the HOT interval. Our currentstudy has been then with this transition zone oil. In thiscase, it will be believed that the oil sample is only repre-sentative of the upper mobile section of the zone.

2. The sampled fluid essentially comes from the LOC Eventhough the sample is collected from the HOT interval.The fluid flowing from LOC to the wellbore picks upsome asphaltene from the asphaltenic HOT interval andmixes somewhat with the heavy oil of the interval beforebeing produced. It thus becomes slightly heavy comparedto the LOC fluid. In this case the sampled fluid poorlyrepresents the HOT zone oil.

6

To test the validity of these plausible explanations, thebottom hole samples can be collected at increasing depthsin the HOT interval. Below certain depth, the productionwill cease when the immobile zone is encountered. Alter-natively, core plugs can be drilled covering the wholedepth of the HOT zone and the core fluids analyzed forthe purpose. The future studies on the HOT zone areaimed at the latter. Only when the HOT zone oil is char-acterized well from the above studies, a suitable recoveryprocess for the interval can be investigated.

Conclusions

1. Several surface and bottom hole samples were collectedfrom the Prudhoe Bay HOT zone. The analysis on theseoils showed that the fluid samples were similar to the oilfrom the LOC with an increase in asphaltene content anda slight increase in viscosity.

2. The oil characteristics determined for the bottom holesamples could not explain the reason for relative immo-bility of the HOT zone oil. It was believed to be eithertransition oil from upper section of the HOT zone or lightoil slightly mixed with the heavy oil of the zone. In eithercase, the sampled bottom hole fluid did not truly repre-sent the HOT zone oil. More studies are required to prop-erly characterize the HOT zone oil. Only then a suitablerecovery technique for the HOT interval can be investi-gated.

Acknowledgment

The authors wish to thank the Department of Energy and Brit-ish Petroleum Inc. for funding and supporting this CRADAproject. Thanks are also due to Robert Fishback for his contri-bution in the experimental work and to British Petroleum Inc.for providing oil samples.

References

1. Wadman, D.H., Lamprecht, D.E., and Mrosovsky, I.“Joint Geologic/Engineering Analysis of the SadlerochitReservoir, Prudhoe Bay Field,” JPT, 933–940, July 1979.

2. Szabo, D.J., and Meyers, K.O. “Prudhoe Bay: Develop-ment History and Future Potential,” SPE 26053 presentedat the 1983 Western Regional Meeting held in Anchorage,Alaska, May 26–28.

3. Bradley, M.E., Mayson, H.J., and Wilkins, K.L. “An Inte-grated Approach to Refining Reservoir DescriptionThrough Monitoring Fluid Movements in the PrudhoeBay Reservoir,” SPE 15567 presented at the 1986 AnnualTechnical Conference and Exhibition, New Orleans,October 5–8.

4. Erickson, J.W. and Sneider, R.M. “Structural and Hydro-carbon Histories of the Ivishak (Sadlerochit) Reservoir,Prudhoe Bay Field,” SPE 28574 presented at the 69

th

Annual Technical Conference and Exhibition, NewOrleans, September 25–28, 1994.

5. Sneider, R.M. and Erickson, J.W. “Rock Types, Deposi-tional History, and Diagenetic Effects: Sadlerochit Reser-voir, Prudhoe Bay Field,” SPE 28575 presented at the 69

th

Annual Technical Conference and Exhibition, NewOrleans, September 25–28, 1994.

6. Haldorsen, H.H., Mayson, H.J., and Howarth, S.M. “TheHeavy Oil/Tar Mat in the Prudhoe Bay Field, Alaska -Characterization and Impacts on Reservoir Performance,”paper presented at 3

rd

International UNITAR Conference,Long Beach, California, July 22–31, 1985.

7

Table 1: Prudhoe Bay HOT (Heavy Oil/Tar) Zone Characteristics

Table 2: Physical Properties of Stock Tank Oils

Property Value Property Value

Depth, ft 8950 - 9070 Payzone Thickness, ft 10-80

ReservoirTemperature,∞F

185 - 240 Initial Pressure, psi 4,315 at 8,8subsea

API gravity ~10-15∞ Gas-oil ratio, scf/bbl ~350-550

Viscosity, cP 40-140 (estimated) AsphalteneContent,wt.%

10-35

Porosity, % ~21 Air Permeability, mD 1-1000

Oil Saturation, % PV 30-70 Oil-in-place, Billionbbl

1.5 - 1.6

Other Information HOT zone is generally thought of consisting of three parts:immobat bottom, viscous mobile heavy oil in the middle containing h

asphaltene content, and transition zone oil essentially mixture ofand light oil (API gravity near 22)

Well location SampleType

AsphalteneContent(wt.%)

Density at 60° F°

(g/cm 3)

Viscosityat 77° F

(cP)

WaterContent(wt.%)

DS9-31B Surface 1 12.6 0.925 98.5 48.4

Surface 2 13.5 0.948 276.7 31.8

F-17A Surface 1 10.8 0.936 - 13.9

Surface 2 13.1 0.930 146.5 1.2

BHS 11.6 0.919 67.9 <0.001

B-36 BHS

Surface

10.0

-

0.936

0.928

303.5

-

0.20

47.3

G-10A BHS 15.2 0.936 303.5 0.03

G-12 Surface 12.5 0.924 109.3 1.34

8

Table 3: Composition of Stock Tank Oils and Reservoir Fluids

Table 4:Composition of the Simulated Solution Gas for Oil from Well DS9-31B

Table 5: Physical Properties of the Prudhoe Bay Reservoir Fluids

WellLocation

DS9-13B

mol %

DS9-13B

mol %

DS9-13B

mol %

F-17Amol %

F-17Amol %

B-36mol %

Oil Type StockTankOil

ModelStockTank

Simulated Res.

Fl.

Synthetic Res.

Fl.

BHSRes. Fl.

BHSRes. Fl.

ComponentCO2

N2

C1C2C3C4C5C6C7C8C9C10C11-13C14-19C20-26C27-35C36+

0.00.00.00.00.121.153.496.646.955.486.025.7615.0220.0112.498.408.45

0.190.000.250.270.802.052.312.535.326.875.594.8312.2617.4914.3810.9313.93

7.660.3845.114.370.411.062.103.213.142.302.452.315.997.914.943.323.34

7.040.3543.904.060.680.781.222.302.843.023.052.827.4410.247.2011.07

-

2.160.3541.503.082.501.711.091.042.582.452.042.597.5912.857.8813.083.40

6.570.3431.344.182.641.610.950.763.003.663.603.358.7813.328.175.172.53

Component CO2 N2 C1 C2 C3 C4 C5 C6+

mol % 12.66 0.63 74.59 7.22 0.60 1.01 1.18 2.11

Properties F-17A (Synthetic)F-17A (BHS) B-36Reservoir temperature (°F)

Bubblepoint pressure (psi)

Gas-oil ratio (scf/bbl)

Viscosity (cP)

Density (g/cm3)

Formation Volume Factor* (vol/vol)

Thermal expansion at 5000 psig

Compressibility of liquid phase(vol/vol/psi)

5000 - 4528 psi

4528 - 4009 psi

4009 - 3544 psi

3544 - 2980 psi

2980 - 2748 psi

22437705001.840.778

--

9.0E-069.9E-061.4E-06

--

2242600507

20727484891.980.7661.3161.101

8.4E-069.4E-069.6E-069.9E-061.0E-05

9

Table 6: Separator Flash of Reservoir Fluid from Well B-36

Table 7: SARA Analysis on B-36 Flashed Oil

Table 8: Composition of Prudhoe Bay Miscible Injectant Gas

SeparatorPressure

psig

SeparatorTemeperature

∞F

Gas-OilRatio*scf/bbl

Tank OilGravity∞API

FormationVolumeFactor**vol/vol

GasGravity (air=1)

0 62 489 22.5 1.316 0.8522

* Gas-oil ratio is in cubic feet of gas at 14.7 psi and 60∞F per barrel stock tank oil at 60∞F** Formation volume factor is barrels of oil at saturation pressure and reservoir temperature

per barrel ofstock tank oil at 60∞F

Components wt %

SaturatesAromatics

ResinsAsphaltene

25.625.213.735.6

Component CO 2 C2 C3 i-C4 n-C4 i-C5 n-C5

mol % 19.11 0.14 34.91 19.05 21.51 1.99 3.21 0.05 0.03

N 2 C1

10

Figure 1: Schematic of the PVT Measurement Apparatus

Figure 2: Comparison of Compositional Analysis of Samples F17-A and DS-31B

PVT Cell:Temco Inc.918/835-2193Serial No. WC20-500-210,000 psig at 350ûF.500 cc volume

Oven:24 cuft capacityTemperature to 224ûF0.25% temperature control316 SS interior

Transducer:0 - 10000 psig range250ûF working temp.low volume - flush mount316 SS wetted parts

Temco Pump:Dual opposed, independentlyoperated10,000 psig working pressure100 cc volume minimum316 SS wetted parts

Densitometer:Anton Paar model DMA 5126,000 psig working pressure224ûF working temperature

ÆP

Capillary CoilsViscosity:

1/8" SS tubing, 0.03" ID0.048" wall, 10 feet long12" diameter coil10,000 psig at 224ûF

ÆP Transducer:0 -12500 psig line pressure0 - 125 psid differential250ûF working temperature410 SS wetted parts

Piston Cylinder:Stainless steel, 316100 cc volume10,000 psig working pressure224ûF working temperatureTeflon seals

Relief Valve:316 stainless steel30,000 psig working pressureadjustable, set at 5,500 psigLiquid service

PISTON

Tubing:1/8" OD, 0.035 wall316 stainless steel10,000 psi working pressure224ûF working temperature

Valves:Two-way straight valves316 stainless steel10,000 psi working pressureat 224ûFRegulating stem

Mixing Ring:

316 stainless steelGrooved and perforated

11

Figure 3: Predicted Viscosity for DS9-31B Fluid at Reservoir Conditions

Figure 4: Variation in Density of Prudhoe Bay Reservoir Fluids With Pressure

0.76

0.78

0.80

0.82

0.84

0.86

0 1000 2000 3000 4000 5000

PRESSURE, psi

DE

NS

ITY

, g/

cm3

F17-A (Synthetic Fluid)B-36 (Bottom Hole Fluid)

12

Figure 5: Viscosity of Prudhoe Bay Reservoir Fluids With Pressure

Figure 6: Z Factor of Miscible Injectant (MI) Gas at Reservoir Temperature

1.0

2.0

3.0

4.0

5.0

6.0

7.0

0 1000 2000 3000 4000 5000

PRESSURE, psi

VIS

CO

SIT

Y,

cP

F17-A (Synthetic Fluid)B-36 (Bottom Hole Fluid)

0.700

0.750

0.800

0.850

0.900

0.950

1.00

0 1000 2000 3000 4000 5000 6000

PV Z

Measured Z

PRESSURE, psig

Z F

AC

TO

R

13

Figure 7: Variation in Bubblepoint Pressure of F17-A Bottom Hole Sample With MI Gas

Figure 8: Solubility-Swelling Data on F17-A Bottom Hole Sample With MI Gas Mixtures

2000

2500

3000

3500

4000

4500

0 10 20 30 40 50 60 70

MI GAS CONCENTRATION, mol %

BU

BB

LEP

OIN

T P

RE

SS

UR

E,

psig

60

65

70

75

80

85

90

95

100

1500 2000 2500 3000 3500 4000 4500

Original Reservoir Fluid10 Mole Percent Mix20 Mole Percent Mix30 Mole Percent Mix40 Mole Percent Mix50 Mole Percent Mix70 Mole Percent Mix

PRESSURE, psig

LIQ

UID

VO

LUM

E,

%

14