verma & bird( role of res eng in npra resouce assessment)
TRANSCRIPT
AUTHORS
Mahendra K. Verma � U.S. GeologicalSurvey, P.O. Box 25046, MS 939, DenverFederal Center, Denver, Colorado 80225;[email protected]
Mahendra Verma specializes in reservoir en-gineering and has more than 26 years of world-wide oil industry experience. Currently, he is aresearch petroleum engineer with the U.S.Geological Survey, providing engineering sup-port to various geological assessments of fieldsand provinces in the United States, Canada,North Sea, Russia, and the Middle East. He holdspetroleum engineering degrees from the In-dian School of Mines, India (B.S. degree), theImperial College of Science and Technology,London (Diploma of Imperial College), and Bir-mingham University, United Kingdom (Ph.D.).
Kenneth J. Bird � U.S. Geological Survey,Menlo Park, California 94025; [email protected]
Kenneth Bird specializes in the petroleumgeology of northern Alaska, where his experi-ence spans more than 40 years. Currently, heis the coleader of the U.S. Geological SurveyAlaska Petroleum Studies Project. With inter-ests primarily in stratigraphy and sedimentolo-gy, he has been extensively involved in petro-leum resource assessments. He holds geologydegrees from Oregon State University (B.S.degree) and the University of Wisconsin (M.S.degree and Ph.D.).
ACKNOWLEDGEMENTS
We thank U.S. Geological Survey reviewersThomas S. Ahlbrandt and Michael D. Lewanand AAPG reviewers Kent A. Bowker, NareshKumar, and Jerry Lucia for their in-depth re-views and valuable comments. We also thankU.S. Geological Survey staff for assistance inpreparing this article and Richard Nehring forhis permission to use the NRG Associates’ da-tabase in this study.
Role of reservoir engineering inthe assessment of undiscoveredoil and gas resources inthe National PetroleumReserve, AlaskaMahendra K. Verma and Kenneth J. Bird
ABSTRACT
The geology and reservoir-engineering data were integrated in the
2002 U.S. Geological Survey assessment of the National Petroleum
Reserve in Alaska (NPRA). Whereas geology defined the analog pools
and fields and provided the basic information on sizes and numbers
of hypothesized petroleum accumulations, reservoir engineering
helped develop necessary equations and correlations, which allowed
the determination of reservoir parameters for better quantification
of in-place petroleum volumes and recoverable reserves.
Seismic- and sequence-stratigraphic study of the NPRA resulted
in identification of 24 plays. Depth ranges in these 24 plays, how-
ever, were typically greater than depth ranges of analog plays for
which there were available data, necessitating the need for establish-
ing correlations. The basic parameters required were pressure, tem-
perature, oil and gas formation volume factors, liquid/gas ratios for
the associated and nonassociated gas, and recovery factors.
Finally, the results of U.S. Geological Survey deposit simulation
were used in carrying out an economic evaluation, which has been
separately published.
INTRODUCTION
Reservoir engineering has taken on greater importance in recent
U.S. Geological Survey assessments of undiscovered oil and gas re-
sources, particularly as economic analysis has become an integral
part of the assessment process. Some of the earlier assessments of
undiscovered oil and gas resources have been based on geologic
information (i.e., geology, geophysics, geochemistry, and petrophys-
ics), and assessment results are typically reported in terms of gross
AAPG Bulletin, v. 89, no. 8 (August 2005), pp. 1091– 1111 1091
Copyright #2005. The American Association of Petroleum Geologists. All rights reserved.
Manuscript received May 24, 2004; provisional acceptance November 17, 2004; revised manuscriptreceived February 24, 2005; final acceptance April 4, 2005.
DOI:10.1306/04040504055
in-place or technically recoverable resources (e.g.,
Masters, 1984; Rice, 1986). However, experience has
shown that assessment results are much more quanti-
fiable when (1) they are reported in terms of sizes and
numbers of petroleum accumulations and (2) they in-
corporate engineering and economic analysis. Reservoir-
engineering studies, when integrated with geologic
analyses, strengthen and broaden the outcome. The di-
minishing numbers of new discoveries around the world
and the importance of economics in the exploration for
and exploitation of hydrocarbons also necessitate an
engineering approach. Such evaluations are particularly
important in remote frontier areas where infrastructure
is limited or nonexistent and where there may be com-
peting land-use issues. This study describes an integrated
reservoir engineering and geosciences approach to the
evaluation of the undiscovered hydrocarbon-resource
potential of the National Petroleum Reserve, Alaska
(NPRA), a large, remote, and little-explored region on
the North Slope of Alaska (Figure 1).
The function of reservoir engineering in the as-
sessment of undiscovered oil and gas resources of the
NPRA is to provide basic information that allows the
estimation of hydrocarbon-in-place volumes using fluid
and reservoir parameters, converting them from sub-
surface to surface volumes using formation volume
factors (FVFs) and then calculating technically recov-
erable volumes by multiplying the surface hydrocar-
bon volumes by a recovery factor. Therefore, the main
objectives of this article are to (1) provide a procedure
for data analysis to establish equations for the calcu-
lation of oil and gas FVFs and gas-liquid ratios; and
(2) define recovery factors required for estimation of
undiscovered oil, gas (associated and nonassociated),
and natural gas liquid resources. This study is the first
attempt to compile and analyze all available reservoir-
engineering data for North Slope hydrocarbon accu-
mulations and to characterize undiscovered oil and
gas accumulations in the little-explored NPRA area.
Twenty-four individual petroleum plays have been
identified for resource assessment in the NPRA, based
on the general definition of a petroleum play as being a
set of known or postulated oil and (or) gas accumula-
tions sharing similar geologic, geographic, and temporal
properties, such as source rock, migration, timing, trap-
ping mechanism, and hydrocarbon type. In practice, each
play has a geographic outline and includes a specific
interval of strata. Many of the plays have no discoveries
in NPRA; it is a largely unexplored area, and so analogs
are required. Therefore, the greatest challenge in pro-
viding reservoir-engineering support to an assessment
of undiscovered resources is to incorporate appropriate
analog data in reservoir-engineering equations, which
can be applied to the entire range of reservoir condi-
tions postulated to exist in the plays being assessed.
As input for resource calculations, the assessor
provides a probabilistic range of estimates of reservoir
thickness, porosity, and the number, depth, and areal
dimensions of prospective hydrocarbon accumulations.
Engineering details, such as solution gas/oil ratio (GOR),
oil FVF, gas volume factor or gas FVF, and recovery
factor (subjects of this article), are then incorporated
into the calculations prior to running the U.S. Geolog-
ical Survey deposit simulation, which results in prob-
abilistic estimates of sizes and numbers of hydrocarbon
accumulations for individual petroleum plays (Schue-
nemeyer, 2003). Hydrocarbon accumulations are mod-
eled either as oil fields or nonassociated gas fields.
Subsequently, economically recoverable estimates are
produced (e.g., Attanasi, 2003) that are based on es-
timated cost of finding, development, production, and
transportation to market.
BACKGROUND
The NPRA is a large, 23-million-ac (9.3-million-ha),
little-explored tract of land owned by the federal gov-
ernment. It includes nearly the entire western half of
the North Slope (Figure 1) and lies beyond the west-
ernmost extent of northern Alaska’s existing petroleum
infrastructure. Government exploration programs in
1944–1953 and 1974–1982 resulted in the collection
and analysis of large amounts of geological and geo-
physical data, the drilling of 45 shallow core tests and
64 deeper exploratory test wells, and the discovery of
about 10 noncommercial oil and gas fields. These explo-
ration programs were summarized by Reed (1958) and
Gryc (1988) and the oil and gas discoveries by Kumar
et al. (2002). Near the end of the second government
exploration program, in 1980, the U.S. Geological Survey
completed an assessment of undiscovered oil and gas re-
sources of the NPRA using an early version of the deposit-
simulation method. Because the North Slope reservoir-
engineering data at that time were limited to just one
producing oil field (Prudhoe Bay), that assessment in-
corporated no engineering or petroleum fluid details;
it reported only in-place resources and, for economic
analysis, it applied the same single-value recovery fac-
tors (35% for oil, 75% for gas) to all plays (Gryc, 1988).
Since 1982, the NPRA has been open to explora-
tion by private industry. In the mid-1980s, several lease
1092 Reservoir Engineering
sales were held, and two industry wells were drilled
with no announced discoveries. The 1996 announce-
ment of ARCO’s Alpine discovery just beyond the
eastern edge of NPRA, with an estimate of 429 million
bbl of recoverable oil (Hannon et al., 2000), sparked
renewed industry interest in exploring the NPRA. In
recent years, additional lease sales were held in north-
ern NPRA; exploratory wells were drilled; and oil dis-
coveries, such as Lookout and Spark, were announced
(Figure 1). These recent developments and a 20-yr-old
perspective on the geology, engineering, and economics
of the NPRA (Gryc, 1988) prompted a new assessment
in 2002; a summary of that assessment was published as
a U.S. Geological Survey Fact Sheet (Bird and House-
knecht, 2002a). The 2002 U.S. Geological Survey as-
sessment relied heavily on reservoir-engineering data
collected over the last 20 yr (since the 1980 assess-
ment) from 33 reservoirs in 15 North Slope oil and
gas fields, most of which are located near the NPRA
(Figure 1), as well as several recently published reports
or otherwise publicly released information.
GEOLOGIC SETTING
The NPRA occupies a central position in the north Alas-
ka region and shares a common stratigraphy and many
regional tectonic features. Within the NPRA, major tec-
tonic features include a remnant of a late Paleozoic–
early Mesozoic south-facing continental margin and a
Cretaceous–Tertiary foreland basin and fold and thrust
belt. Late Mesozoic rift margin and rift shoulder fea-
tures (Barrow Arch), the site of most commercial oil
accumulations east of NPRA, are located mostly north
of and offshore from NPRA, except at Barrow Peninsu-
la where they are present onshore. Sratigraphically, the
NPRA includes a basement composed of Devonian and
older metasedimentary and some igneous rocks that
are generally referred to as the Franklinian sequence.
Above the basement, in upward succession, are tecto-
nostratigraphic sequences representing a Mississippian
to Triassic south-facing passive continental margin se-
quence (Ellesmerian), a Jurassic to Early Cretaceous syn-
rift sequence (Beaufortian), and a Cretaceous to early
Tertiary foreland basin sequence (Brookian). Most North
Slope oil and gas reservoir rocks and source rocks are
represented in the NPRA; at least five petroleum sys-
tems (four oil and one gas) are present (Figure 2a).
The 2002 U.S. Geological Survey assessment of
NPRA identified 24 petroleum plays based primarily
on reservoir characteristics, trapping mechanism, ther-
mal maturity, and source and migration considerations.
Most of the plays (20) are stratigraphically defined and
located in the northern, relatively undeformed part
of the NPRA; by sequence, these 20 plays include
five Brookian, eight Beaufortian, and seven Ellesme-
rian. Four structural plays were evaluated in the fold
and thrust belt region of southern NPRA. Of these,
two are Brookian, one Ellesmerian, and one composite
Ellesmerian, Beaufortian, and Brookian play. The strati-
graphic interval encompassed by each play is shown
in Figure 2a. A schematic cross section (Figure 2b)
shows the relative locations of plays in each tectono-
stratigraphic sequence. Maps and resource estimates
for each play are presented in Bird and Houseknecht
(2002b), and descriptions of most plays can be found in
the report by Houseknecht (2003), Moore and Potter
(2003), and Potter and Moore (2003).
DERIVATION OF RESERVOIR-ENGINEERINGPARAMETERS
In the 2002 NPRA assessment, existing North Slope
oil and gas fields provided useful analogs, but for less
than half of the identified plays. In addition, for any
individual play with analogs, the number of fields is
too small to derive meaningful reservoir-engineering
data that might be specific to that play. Our approach
was to use reservoir-engineering data from all North
Slope fields to derive correlations and engineering pa-
rameters that could be applied to all plays.
We relied on data from 27 reservoirs in 10 oil fields
(Table 1) and 6 reservoirs in 5 gas fields (Table 2), in
conjunction with corrected bottom-hole temperature
data from NPRA exploratory wells (Blanchard and
Tailleur, 1982), to establish correlations and equa-
tions as described in the following sections. Data
were extracted from the proprietary NRG Associates
(1998) and publicly available documents from the
Alaska Oil and Gas Conservation Commission, Petro-
leum News Alaska, and Society of Petroleum Engineers
(SPE) publications.
Equations for Pressure and Temperature
Two basic equations, one for pressure (Figure 3) and
one for temperature (Figure 4) are presented below
along with discussions on data regression.
Pressure ¼ depth � 0:5 ð1Þ
Verma and Bird 1093
1094 Reservoir Engineering
where pressure is in pounds per square inch and depth
is in feet below surface.
For developing correlations, the original reservoir
pressure at depth below surface from all fields, except
Badami and Point Thomson fields (Figure 1B) with high-
pressure gradients (0.70–0.85 psi/ft; 15.8–19.3 kPa/m),
were regressed, giving 0.99 as the value of R2 (correla-
tion coefficient), which is a measure of the high level of
correlation and, hence, provides validity to equation 1.
Pressures based on the above equation show an error
range of �1.0 to +15.5% when compared with ob-
served pressures on the North Slope reservoirs, except
for pressures in Badami and Point Thomson fields with
known high pressures (Gautier et al., 1987). The Umiat
pressure was excluded because of inadequate data.
Although data for temperature-depth correlations
were available from two sources (individual North Slope
fields from the NRG Associates [1998] and bottom-
hole temperatures from individual wells in the NPRA
from Blanchard and Tailleur [1982]), we used the lat-
ter source as being more appropriate for the NPRA
area. The data consist of 68 corrected bottom-hole tem-
peratures (range: 90–420jF [32–215jC]) from 28 ex-
ploratory wells, and these temperatures are plotted
against depths in Figure 4, resulting in the following
equation:
Temperature ¼ 1:9 � depth
100þ 30 ð2Þ
where temperature is in degrees Fahrenheit and depth
is in feet below surface.
Because of the presence of permafrost, the in-
tersection of the regression line with the X-axis at
30jF (�1.1jC) does not necessarily reflect the sur-
face temperature.
Sixty of the sixty-eight bottom-hole temperatures,
excluding too high or too low temperatures (data points
that fall either too far below the 1.5jF/100 ft (�55.6jC/
100 m) line or too far above the 2.2jF/100 ft [�54.3jC/
100 m] line) shown in Figure 4, were regressed, giving
0.92 as the value of R2. These excluded temperatures
were from the Lisburne and South Meade wells: tem-
peratures in the Lisburne well were found to be higher
than the normal trend at depths above 1200 ft (365 m)
and lower than the normal at depths ranging from 7975
to 16,955 ft (2430 to 5167 m); temperatures in the
South Meade well were higher than the normal trend
for depths greater than 8000 ft (2438 ft).
The temperatures based on equation 2 were found
to be accurate within 18% of the observed tempera-
tures for reservoirs on the North Slope with depths
greater than 3600 ft (1097 m) and calculated temper-
ature ranges of 70–250jF (21–121jC), except in the
Badami, Milne Point (Schrader Bluff), and Point Thom-
son fields. In fact, it is difficult to predict temperatures
for shallow reservoirs with any accuracy because of
the variable thickness of permafrost (Lachenbruch et al.,
1988).
In addition to basic equations 1 and 2, separate cor-
relations or equations were established for oil and gas
reservoirs.
Equations for Oil Reservoirs
Estimation of undiscovered oil resources requires a de-
termination of the FVF as a function of depth. Because
FVF is a function of the solution GOR, it is necessary
to first establish an equation for solution GOR, which
is a function of pressure, temperature, and the compo-
sition of oil and gas. Because solution-gas gravity data
for all the North Slope reservoirs are not available, we
developed a correlation for gas gravity based on pres-
sure, temperature, and oil-gravity data, as shown in
Table 1 and plotted in Figure 5. We found the loga-
rithmic function to be most appropriate for regres-
sing the data. Equations for the three correlations are
shown on the individual plots. The empirical equa-
tion we formulated to calculate the gas gravity is
g ¼ 0:1582 ln P � 0:5840 þ 0:1732 ln T � 0:1709 þ 0:2105 ln�
API þ 0:0194
3
ð3Þ
where g is the symbol for gas gravity; P is for pressure
in pounds per square inch absolute; T is for tem-
perature in degrees Fahrenheit, and jAPI is for oil
gravity.
Figure 1. Maps showing the locations of North Slope oil and gas pools and fields. (A) Index map showing areas of major federal landholdings (shaded), the Trans-Alaska Pipeline System (TAPS) with feeder pipelines, and the location of Prudhoe Bay. (B) Map of that partof the North Slope where oil and gas fields have been discovered. Pool names, if different from field names, are shown in parentheses.Dotted line, NPRA boundary. (C) Detailed map of the Prudhoe Bay–Kuparuk area where most oil accumulations have been found. Fieldsare shown in black. Pool names, if different from field names, are shown in parentheses. KR = Kuparuk River; PB = Prudhoe Bay.
Verma and Bird 1095
1096 Reservoir Engineering
The values of R2 for solution-gas gravity vs. pres-
sure and temperature correlations are in the range of
0.80–0.87. The value of R2 for the gas-gravity-vs.-oil-
gravity correlation is about 0.70. The above composite
equation yields gas-gravity values that are within 7% of
the observed gravity values.
If values for pressure, temperature, oil gravity, and
gas gravity are available, solution GOR can be calcu-
lated either by an equation from Standing (1947) or
one from Lasater (1958). Gas/oil ratios calculated from
both of these equations are plotted against the observed
or reported GORs in Figure 6 to determine which was
most suitable for our use. The plot shows that the
Standing (1947) equation gave relatively better results
based on the fact that calculated GORs lie closer to the
unit-slope line on a plot of observed vs. calculated
GORs in Figure 6. Therefore, the Standing equation,
which has been derived from the bubble-point pres-
sure equation, was chosen for the calculation of solu-
tion GOR. Although based on an assumption that the
oil is saturated with respect to gas, which may not
apply to all oil reservoirs, this equation simplifies the
procedure and provides reasonable values for the res-
ervoir parameters, particularly with respect to undis-
covered oil reservoirs. The Standing equation for cal-
culating solution GOR is
Solution GOR ¼ ggas �P � ð10Þ0:0125� goil
18 � ð10Þ0:00091�T
! 10:83
ð4Þ
where ggas is the gas gravity; goil is the oil gravity in
jAPI, P is the pressure in pounds per square inch ab-
solute, and T the temperature in degrees Fahrenheit.
However, the calculated GORs required correc-
tion for a better match with the observed GORs from
reservoirs on the North Slope of Alaska. This was
achieved by regressing a best fit line through the cal-
culated data, which resulted in a correction factor (CF)
of 0.86, for all the GORs below 1200 scf/STB. The
precision of regression (R2) for this correlation was
0.74. To determine a CF for higher than 1200 scf/STB,
we used data from Northstar field (Figure 6) with its
high API-gravity oil and high GOR, which required a
CF of greater than 1.1 for a better match. We used a
sine function to gradually increase the value of CF
from 0.86 at a calculated GOR of 1200 scf/STB (the
value just below the calculated GOR of 1250 scf/STB
for the Sag River reservoir in Milne Point field, where
the observed GOR was 974 scf/STB) to 1.1 at about a
GOR of 2250 scf/STB (corresponding to the North-
star GOR of 2150 scf/STB), based on the empirical
equation
CF ¼ 0:86 þ 0:24 � sinGOR � 1200
2250 � 1200
� �� p=2
� �2
ð5Þ
where GOR is based on equation 4.
Application of equation 5 for correcting calculated
GORs resulted in accuracies of ±16%, except for the
Alapah, Milne Point (Kuparuk reservoir), Northstar,
and Tarn fields (Table 1), where GOR values deviated
by 19–37%. The GOR for the Badami field was not
considered because of its abnormally high pressure.
This difference in calculated and observed GORs could
be caused by errors in any of the reservoir parameters.
After calculating the solution GORs using equation 4
(Standing equation) and modifying them using the
proposed correction factor from equation 5 (modifi-
cation to the Standing method), we used a two-step
procedure based on the Standing (1947) correlation to
calculate FVFs as follows:
1. The correlation factor (F) is calculated as per the
equation
F ¼ GOR �ggas
goil
� �0:5
þ 1:25 � T ð6Þ
where ggas is the gas gravity; goil is the oil specific gravity;
and T is the temperature in degrees Fahrenheit.
Figure 2. (a) Generalized stratigraphic column for the NPRA region north of Brooks Range showing tectonostratigraphic sequencesubdivisions, petroleum system source rocks, and petroleum play (reservoir) intervals. Play numbers are keyed to play names in Table 6.GRZ = gamma-ray zone of Hue Shale; LCU = Lower Cretaceous unconformity; *Blankenship, Otuk, and Kuna are distal facies of Kingak,Shublik, and Lisburne, respectively, that are known only from the Brooks Range and thus are not shown on this stratigraphiccolumn. (b) Schematic section illustrating the distribution of assessed petroleum plays in relation to major tectonic and stratigraphicfeatures. Half arrows = schematic representation of thrust faults.
Verma and Bird 1097
Tab
le1
.Su
mm
ary
ofSe
lect
edRe
serv
oir
Dat
afo
rN
orth
Ala
skan
Oil
Fiel
dsU
sed
inth
eD
eriv
atio
nof
Rese
rvoi
rEn
gine
erin
gPa
ram
eter
sfo
rth
e20
02A
sses
smen
tof
the
NPR
A*
Fiel
dPo
olRe
serv
oir
Dep
th
(ft
SS)*
*
Dep
th
(ft
S)**
Pres
sure
(psi
)
Tem
pera
ture
(jF)
Poro
sity
(%)
Perm
eabi
lity
(md)
Oil
Gra
vity
(jA
PI)
Oil
visc
osity
(cP)
Solu
tion
Gas
/Oil
Ratio
(scf
/STB
)yFV
F
(bbl
/STB
)y
Gas
Spec
ific
Gra
vity
Reco
very
Fact
or
(%)yy
Bada
mi
Bada
mi
Can
ning
9900
9911
6285
180
1820
026
.04.
4050
21.
237.
6
Col
ville
Alp
ine
Alp
ine
7000
7021
3238
160
1915
39.0
0.46
850
1.44
0.72
042
.9
Endi
cott
Ala
pah
Lisb
urne
10,0
0010
,000
4885
216
17.5
5–
200
28.5
600
5.4
Endi
cott
Eide
rIv
isha
k97
0097
0046
2020
621
134
23.0
1.00
769
1.36
0.77
838
.0
Endi
cott
Endi
cott
Kek
iktu
k10
,000
10,0
0048
4021
821
550
22.0
750
1.35
50.0
Endi
cott
Sag
Del
taN
orth
Ivis
hak
10,0
0010
,000
4825
212
2038
825
.062
435
–44
Kup
aruk
Rive
rK
upar
ukRi
ver
Kup
aruk
6200
6250
3120
160
2015
024
.02.
2051
61.
260.
700
43.0
Kup
aruk
Rive
rM
eltw
ater
Berm
uda
5400
5625
2400
140
2012
37.0
0.76
620
1.33
29.0
Kup
aruk
Rive
rTa
rnBe
rmud
a52
3053
7523
5014
221
1037
.00.
5571
01.
3931
.0
Kup
aruk
Rive
rTa
basc
oSc
hrad
erBl
uff
3000
3021
1512
7120
3000
16.0
253.
0016
91.
060.
580
21–
30
Kup
aruk
Rive
rW
est
Sak
Schr
ader
Bluf
f35
0035
6115
5078
3060
018
.054
.00
200
1.07
0.60
0na
Miln
ePo
int
Kup
aruk
Rive
rK
upar
uk70
0070
1734
8516
523
605
22.0
3.80
320
1.16
0.65
043
.3
Miln
ePo
int
Sag
Rive
rSa
gRi
ver
8750
8767
4425
235
184
39.2
0.28
974
1.56
0.80
038
.0
Miln
ePo
int
Schr
ader
Bluf
fSc
hrad
erBl
uff
4000
4017
1790
8027
.717
117
.552
.00
202
1.07
0.57
022
.0
Miln
ePo
int
Ugn
uU
gnu
3500
3517
1485
6530
350
na
Nor
thst
arN
orth
star
Ivis
hak
11,1
0011
,100
5305
254
1553
44.0
0.14
2150
2.20
0.80
052
.0
Poin
tM
cInt
yre
Poin
tM
cInt
yre
Kup
aruk
8800
8800
4362
180
2220
027
.00.
9080
61.
390.
700
42–
45
Poin
tTh
omso
nFl
axm
anIs
land
Can
ning
12,5
0012
,500
9835
195
23.1
899
na
Poin
tTh
omso
nPo
int
Thom
son
Thom
son
12,9
0012
,900
10,1
4520
518
.4na
Prud
hoe
Bay
Aur
ora
Kup
aruk
6700
6727
3433
150
2112
–15
827
.20.
7271
71.
350.
720
34.0
Prud
hoe
Bay
Lisb
urne
Lisb
urne
8900
8920
4490
183
100.
1–
2.0
27.0
0.90
830
1.39
0.72
07.
0
Prud
hoe
Bay
Mid
nigh
tSu
nK
upar
uk80
5080
9940
4316
023
.520
0–
760
25.5
1.68
717
1.33
0.72
514
–39
Prud
hoe
Bay
Nia
kuk
Kup
aruk
9200
9200
4596
181
2050
024
.91.
4066
01.
350.
720
40.0
Prud
hoe
Bay
Prud
hoe
Bay
Ivis
hak
8800
8820
4320
200
2226
528
.00.
8173
01.
400.
770
52.0
Prud
hoe
Bay
Prud
hoe
Bay
Nor
thIv
isha
k92
4592
6946
0020
620
590
29.0
0.43
923
1.48
0.72
0na
Prud
hoe
Bay
Wes
tBe
ach
Kup
aruk
8800
8800
4347
175
1910
725
.71.
0075
21.
3610
–44
Um
iat
Um
iat
Nan
ushu
k68
596
025
012
3037
.07.
0
*Dat
aso
urce
:N
RGA
ssoc
iate
s’da
taba
se,
repo
rts
from
the
Ala
ska
Oil
and
Gas
Con
serv
atio
nC
omm
issi
on,
Petr
oleu
mN
ews
Ala
ska,
and
Soci
ety
ofPe
trol
eum
Engi
neer
spu
blic
atio
ns.
**ft
SS=
feet
subs
ea(d
epth
infe
etbe
low
sea
leve
l);
ftS
=de
pth
infe
etbe
low
surf
ace.
y scf/
STB
=st
anda
rdcu
bic
feet
per
stoc
kta
nkba
rrel
;bb
l/ST
B=
barr
elpe
rst
ock
tank
barr
el.
yyRe
cove
ryfa
ctor
repr
esen
tspr
imar
ypl
usse
cond
ary
reco
very
;na
=no
tav
aila
ble.
1098 Reservoir Engineering
2. The FVF is calculated as per the Standing (1947)
equation:
FVF ¼ 0:972 þ 0:000147 � ðFÞ1:175 ð7Þ
where F is the correlation factor, as in step 1.
To cross-check the accuracy of the calculated FVFs
from the proposed modified Standing method (equa-
tions 4–7), the FVF vs. solution-GOR correlation
(Figure 7) and apparent gas density (Standing, 1977)
method was used to calculate FVFs. Based on the avail-
able data, the following equation was established to
calculate FVF from solution GOR (in scf/STB):
FVF ¼ ð0:00058 � GORÞ þ 0:9544 ð8Þ
The precision of regression for data in Figure 7 is
0.99.
The calculated FVFs from the proposed modified
Standing method (equations 4–7) are compared with
the FVFs from the apparent gas density method and the
FVF vs. solution-GOR correlation (Table 3). The FVFs
Table 2. Summary of Selected Reservoir Data for North Alaskan Gas Fields Used in the Derivation of Reservoir Engineering
Parameters for the 2002 Assessment of the NPRA*
Field Pool Reservoir Depth (ft SS)** Depth (ft S)** Pressure (psi) Temperature (jF)
Barrow East Barrow Barrow 2000 2024 985 58
Barrow South Barrow Barrow 2250 2280 1088 63
East Umiat East Umiat Nanushuk 1929 2466 735 50
Kavik Kavik Sadlerochit 3500 4852 2385 121
Kemik Kemik Shublik 7433 8653 4495 215
Walakpa Walakpa Walakpa 2073 2103 1012 64
*Data source: NRG Associates’ database, reports from the Alaska Oil and Gas Conservation Commission, Petroleum News Alaska, and Society of Petroleum Engineerspublications.
**ft SS = feet sub sea (depth in feet below sea level); ft S = depth in feet below surface.
Figure 3. Plot showing pres-sure vs. depth below surfacefor oil and gas reservoirs in fieldson the North Slope of Alaska(data in Tables 1 and 2). Datafrom all fields, except Badamiand Point Thomson (both Flax-man Island and Point Thomsonpools) with high-pressure gra-dients, were regressed using lin-ear function, giving the best fitline with 0.5 psi/ft (11.3 kPa/m)gradient. R 2 = 0.99. The pres-sure gradient in Badami field is0.7 psi/ft (15.8 kPa/m), whereasit ranges from 0.79 to 0.85 psi/ft(17.9 to 19.2 kPa/m) in PointThomson field, depending onthe reservoir.
Verma and Bird 1099
based on the proposed modified Standing equation com-
pare well with those from the other two methods and
are within 8.5% of the observed values.
Equations for Gas Reservoirs
For gas reservoirs, the procedure for estimating undis-
covered resources is straightforward because the gas
volume factor, or gas FVF, is calculated using a general-
ized gas equation, which includes a compressibility fac-
tor to account for the deviation in the behavior of natu-
ral hydrocarbon-gas mixtures from that of ideal gases.
The theorem of corresponding states (Kay, 1936)
is widely used to calculate the compressibility of a
mixture of gases, which requires calculating pseudo-
reduced pressure (the ratio of reservoir pressure to
pseudocritical pressure) and pseudoreduced tempera-
ture (the ratio of reservoir temperature to pseudo-
critical temperature). If the composition of the hydro-
carbon gas mixture is not available, charts or plots are
used to determine pseudocritical pressure and pseudo-
critical temperature (Standing and Katz, 1942; Standing,
1977). From these parameters, pseudoreduced pressure
and temperature are calculated for a specific reser-
voir pressure and temperature. These pseudoreduced
pressure and pseudoreduced temperature values are
then used to determine the compressibility factor (z)from a correlation chart (Standing, 1977) that is based
on data ranging as high as 8200 psia and 250jF (121jC),
respectively (Standing and Katz, 1942). For other pres-
sure and temperature conditions, several charts are
available for use, such as a chart by Katz et al. (1959)
for high pressures (10,000–20,000 psia) and charts
by Brown et al. (1948) for lower pressures (Beggs,
1992).
Once the value of compressibility factor (z) is
known, gas FVF is calculated using the following gas
equation:
FVF ¼ 35:37415 � P
z � Tð9Þ
where P and T are the reservoir pressure in pounds
per square inch absolute; temperature is in degrees
Rankine (jR), respectively, and z is the compressibil-
ity factor. Absolute pressure (in psia) is obtained by
adding 14.7 to the gauge pressure (psig or just psi),
and the temperature in Rankine (jR) is obtained by
adding 460 to the temperature in Fahrenheit (jF).
Pressure and temperature are calculated using equa-
tions 1 and 2.
The results are fairly accurate for pure hydrocar-
bon systems. However, natural gases contain nonhy-
drocarbon gases, such as nitrogen (N2), carbon dioxide
(CO2), and, in some cases, hydrogen sulfide (H2S),
which introduce errors in the compressibility factor.
For natural hydrocarbon gases, the use of the chart
developed by Standing and Katz (1942), which relates
pseudoreduced pressure and pseudoreduced tempera-
ture with gas gravity, results in gravities that are ex-
pected to be accurate within 3%. For higher percentages
Figure 4. Plot showing cor-rected bottom-hole tempera-ture data vs. depth below sur-face for wells in the NPRA. Most(82%) data lie between gradi-ents 1.5 and 2.2jF/100 ft (�55.6and �54.3jC/100 m). Datawere regressed using linearfunction, giving the best fit linewith a slope of 1.9jF/100 ft(�4.9jC/100 m). The precisionof regression, R 2, is 0.92. Datasource: Blanchard and Tailleur(1982).
1100 Reservoir Engineering
Figure 5. Plot showing gasgravity as a function of pressure,temperature, and oil gravity foroil reservoirs in the North Slopefields (data listed in Table 1).Not knowing the relative impactof these three major reservoirparameters on the gas gravity,the gas gravity values wereobtained by combining in equalproportion the values of theseparameters from their individualcorrelations to gas gravity. Datahave been regressed using logfunction. The first two correla-tions gave R2 values as 0.80 and0.87 and the third one as 0.70.
Verma and Bird 1101
of nonhydrocarbon gases, various methods are avail-
able, depending on the degree of accuracy required.
When the concentration of nonhydrocarbon gases is
greater than 5 mol%, Carr et al. (1954) suggested the
use of a correction factor for each individual nonhy-
drocarbon gas to correct the pseudocritical pressure and
temperature, followed by the use of a chart presented
by Standing and Katz (1942) to determine the com-
pressibility factor. Corrections for nonhydrocarbon
gases, as proposed by Carr et al. (1954) are as follows:
(1) for each mole percent of carbon dioxide, subtract
0.8jR; for each mole percent of hydrogen sulfide,
add 1.3jR; and for each mole percent of nitrogen, sub-
tract 2.5jR from the pseudocritical temperature; and
(2) for each mole percent of carbon dioxide, add
4.4 psi; for each mole percent of hydrogen sulfide,
add 6.0 psi; and for each mole percent of nitrogen, sub-
tract 1.7 psi from the pseudocritical pressure.
Figure 6. Plot showing observedor corrected GOR against thecalculated GOR using Standing(solid diamonds) and Lasater(open triangles) equations forNorth Slope reservoirs (see textfor explanation). The Standingequation was chosen for calcu-lating GORs with a correctionfactor of 0.86 (dotted line) re-quired for a good match with theobserved GORs for a range of160–1200 scf/STB, and highercorrection factors for GOR rangeof 1200–2250 scf/STB to accom-modate higher GOR in fields likeNorthstar. A unit-slope line, whichrepresents an ideal correlationbetween the two GORs, is alsoshown.
Figure 7. Plot showing oilFVF vs. solution GOR for oil res-ervoirs on the North Slope ofAlaska (Table 1). Data (shownas solid diamonds) were re-gressed using a linear function.The value of R2 for the corre-lation is 0.99.
1102 Reservoir Engineering
Equations for Natural Gas Liquid Estimates
Two kinds of natural hydrocarbon-gas accumulations
exist: nonassociated gas (gas reservoirs) and associated
gas (gas cap or solution), both of which contain varying
amounts of liquid hydrocarbons, which are in the va-
por phase under reservoir conditions but drop out as
liquid at atmospheric conditions. These hydrocarbons
have been given various names, such as condensate and
natural gas liquid, and are reported in terms of liquid/
gas ratios in barrels of liquid per million standard
cubic feet of gas (bbl/MMSCF) at standard temper-
ature and pressure (STP); the standard temperature
is 60jF (15.5jC), and the pressure is 14.7 psia.
Because some undiscovered oil accumulations in
the NPRA are postulated to lie at much greater depths
than the known North Slope fields, it was necessary
to establish some correlation between liquid/gas ra-
tios and reservoir depths. This was achieved through
the regression of data using appropriate mathematical
functions. Liquid/gas ratio data from the North Slope
reservoirs have been collected (Table 4) and plotted
against reservoir depth separately for both the associ-
ated and nonassociated gas reservoirs.
Table 3. Formation Volume Factors Calculated from Three Different Methods*
Formation Volume Factor (bbl/STB)**
Field Pool Reservoir
Observed
Data
Modified
Standing Method
Apparent
Density Method
Gas/Oil Ratio
Correlation Method
Badami Badami Canning Abnormal high pressure
Colville Alpine Alpine 1.44 1.46 1.42 1.45
Endicott Alapah Lisburne No data available
Endicott Eider Ivishak 1.36 1.38 1.35 1.40
Endicott Endicott Kekiktuk 1.35 1.40 1.35 1.39
Endicott Sag Delta North Ivishak No data available
Kuparuk River Kuparuk River Kuparuk 1.26 1.25 1.23 1.25
Kuparuk River Meltwater Bermuda 1.33 1.28 1.30 1.31
Kuparuk River Tarn Bermuda 1.39 1.28 1.34 1.37
Kuparuk River Tabasco Schrader Bluff 1.06 1.06 1.06 1.05
Kuparuk River West Sak Schrader Bluff 1.07 1.06 1.07 1.07
Milne Point Kuparuk River Kuparuk 1.16 1.27 1.15 1.14
Milne Point Sag River Sag River 1.56 1.67 1.55 1.52
Milne Point Schrader Bluff Schrader Bluff 1.07 1.08 1.07 1.07
Milne Point Ugnu Ugnu No data available
Northstar Northstar Ivishak 2.20 2.17 2.26 2.20
Point Mcintyre Point Mcintyre Kuparuk 1.39 1.42 1.36 1.42
Point Thomson Flaxman Island Canning No data available
Point Thomson Point Thomson Thomson No data available
Prudhoe Bay Aurora Kuparuk 1.35 1.32 1.32 1.37
Prudhoe Bay Lisburne Lisburne 1.39 1.43 1.38 1.44
Prudhoe Bay Midnight Sun Kuparuk 1.33 1.38 1.31 1.37
Prudhoe Bay Niakuk Kuparuk 1.35 1.39 1.30 1.34
Prudhoe Bay Prudhoe Bay Ivishak 1.40 1.42 1.35 1.38
Prudhoe Bay Prudhoe Bay North Ivishak 1.48 1.60 1.44 1.49
Prudhoe Bay West Beach Kuparuk 1.36 1.39 1.33 1.39
Umiat Umiat Grandstand No data available
*The three methods for calculation are (1) modification of the Standing (1947) method, (2) the apparent gas density method, and (3) the GOR – FVF correlationmethod. Data source: NRG Associates’ database, reports from the Alaska Oil and Gas Conservation Commission, Petroleum News Alaska, and Society of PetroleumEngineers publications.
**FVFs are compared to observed FVFs in selected north Alaskan oil reservoirs based on data provided in Tables 1 and 2. bbl/STB = barrels per stock tank barrel, a unitof oil formation volume factor.
Verma and Bird 1103
Tab
le4
.Li
quid
/Gas
Ratio
Dat
afo
rth
eA
ssoc
iate
dan
dN
onas
soci
ated
Gas
Acc
umul
atio
nsfr
omVa
riou
sW
ells
onth
eN
orth
Slop
eof
Ala
ska
Dat
afo
rIn
divi
dual
Fiel
ds
Dep
th**
Liqu
id/G
asRa
tio
(bbl
/MM
SCF)
Fiel
dPo
olRe
serv
oir
Info
rmat
ion
Sour
ce*
Test
deta
ils
(ft
belo
w
surf
ace)
Ass
ocia
ted
Gas
Non
asso
ciat
ed
Gas
Endi
cott
field
Kek
iktu
kK
ekik
tuk
Test
deta
ilsfr
omA
OG
CC
16pr
oduc
tion
resu
lts
betw
een
Dec
embe
r19
88
and
Nov
embe
r20
02
10,0
0012
.21
Endi
cott
field
Sag
Del
taN
orth
Ivis
hak
Test
deta
ilsfr
omA
OG
CC
14pr
oduc
tion
resu
lts
betw
een
Dec
embe
r19
89
and
Nov
embe
r20
02
10,0
0012
.98
Prud
hoe
Bay
field
Lisb
urne
Wah
ooTe
stde
tails
from
AO
GC
C16
prod
uctio
nre
sults
betw
een
Dec
embe
r19
87
and
Nov
embe
r20
02
8900
9.93
Prud
hoe
Bay
field
Prud
hoe
Ivis
hak/
Sag/
Shub
likTe
stde
tails
from
AO
GC
C16
prod
uctio
nre
sults
betw
een
Dec
embe
r19
87
and
Nov
embe
r20
02
8800
11.0
9
Prud
hoe
Bay
field
Prud
hoe
Ivis
hak
Lette
rad
dres
sed
toA
OG
CC
Prud
hoe
Bay
Stat
e1
wel
l88
0016
.31
Prud
hoe
Bay
field
Nia
kuk
Nia
kuk/
Kup
aruk
Test
deta
ilsfr
omA
OG
CC
9pr
oduc
tion
resu
lts
betw
een
Dec
embe
r19
94
and
Nov
embe
r20
02
8800
14.3
5
Poin
tM
cInt
yre
field
Poin
tM
cInt
yre
Kup
aruk
Test
deta
ilsfr
omA
OG
CC
10pr
oduc
tion
resu
lts
betw
een
Dec
embe
r19
93
and
Nov
embe
r20
02
8800
13.2
7
Dat
afr
omIn
divi
dual
Wel
ls
Wel
lN
ame
and
Num
ber
Pool
Rese
rvoi
rIn
form
atio
nSo
urce
Test
deta
ilsy
Exxo
nA
lask
aSt
ate
F-1
Poin
tTh
omso
nba
sem
ent
DST
1(8
hr,
36m
in)
1092
mcf
gan
d61
bc
(35.
3jA
PI)
reco
very
12,9
7155
.86
Exxo
nA
lask
aSt
ate
F-1
Poin
tTh
omso
nTh
omso
nSa
ndTe
st2
(92
hr,
58m
in)
16,9
20m
cfg
and
939
bc
(34.
8jA
PI)
reco
very
12,7
1855
.50
Exxo
nPo
int
Thom
son
Uni
t1
Poin
tTh
omso
nTh
omso
nSa
ndPr
oduc
tion
test
238
60m
cfg/
day
and
170
bc
(45.
4jA
PI)
reco
very
12,8
3244
.04
Exxo
nPo
int
Thom
son
Uni
t1
unna
med
Can
ning
turb
idite
Prod
uctio
nte
st3
2250
mcf
g/da
yan
d13
2bc
(44.
4jA
PIre
cove
ry)
11,3
8558
.67
1104 Reservoir Engineering
Exxo
nPo
int
Thom
son
Uni
t3
Poin
tTh
omso
nTh
omso
nSa
ndTe
st2
(9hr
,4
min
)23
16m
cfg
and
181
bc
(38j
API
)re
cove
ry
12,9
0378
.15
Hus
ky/N
PRN
orth
Inig
okun
nam
edK
inga
kSh
ale
DST
1(S
ampl
e1)
4.10
9ga
l/10
00ft3
8279
98.0
0
Hus
ky/N
PRN
orth
Inig
okun
nam
edK
inga
kSh
ale
DST
1(S
ampl
e2)
4.12
9ga
l/10
00ft3
8279
98.0
0
Sohi
oA
lask
aIs
land
-1Po
int
Thom
son
Thom
son
sand
Test
1(f
inal
14hr
)A
vera
gera
tes:
2.70
8m
mcf
g/da
y
and
175
bc/d
ay
12,8
8064
.62
Arc
oK
avik
Uni
t3
Kav
ikIv
isha
kTe
st1
onA
pril
29,
1974
0.01
1ga
l/10
00ft3
5661
0.26
Pan
Am
Kav
ik1
Kav
ikSa
gRi
ver
sand
ston
eTe
st9
onN
ovem
ber
5,19
690.
052
gal/
1000
ft342
561.
24
Hus
kyN
PRA
wun
a1
unna
med
Toro
kFo
rmat
ion
DST
10.
005
gal/
1000
ft383
290.
12
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST3
(tes
tto
olsp
lpt
)0.
382
gal/
1000
ft353
509.
10
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST3
(fou
rth
flow
peri
od)
0.63
3ga
l/10
00ft3
5350
15.0
7
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST3
(fift
hflo
wpe
riod
)0.
555
gal/
1000
ft353
5013
.21
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST3
(thi
rdflo
wpe
riod
)0.
581
gal/
1000
ft353
5013
.83
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST3
(sec
ond
flow
peri
od)
0.53
5ga
l/10
00ft3
5350
12.7
4
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST3
(ini
tial
flow
peri
od)
0.52
7ga
l/10
00ft3
5353
12.5
5
Hus
kyN
PRSe
abee
1un
nam
edTo
rok
Form
atio
nD
ST4
initi
alflo
wpe
riod
0.37
3ga
l/10
00ft3
2628
8.88
Hus
kyN
PRSo
uth
Barr
ow19
unna
med
Sag
Rive
rsa
ndst
one
DST
1sa
mpl
e1
0.14
2ga
l/10
00ft3
2180
3.38
Hus
kyN
PRSo
uth
Barr
ow19
unna
med
Sag
Rive
rsa
ndst
one
DST
1sa
mpl
e2
0.20
0ga
l/10
00ft3
2180
4.76
Hus
kyN
PRSo
uth
Barr
ow19
unna
med
Sag
Rive
rsa
ndst
one
DST
1sa
mpl
e3
0.20
5ga
l/10
00ft3
2180
4.88
Hus
kyN
PRSo
uth
Barr
ow19
East
Barr
owBa
rrow
sand
ston
eD
STsa
mpl
e1
0.08
6ga
l/10
00ft3
2008
2.05
Hus
kyN
PRSo
uth
Barr
ow19
East
Barr
owBa
rrow
sand
ston
eD
STsa
mpl
e2
0.07
9ga
l/10
00ft3
2008
1.88
Hus
kyN
PRSo
uth
Barr
ow19
East
Barr
owBa
rrow
sand
ston
eD
STsa
mpl
e3
0.07
1ga
l/10
00ft3
2008
1.69
Hus
kyN
PRSo
uth
Barr
ow19
East
Barr
owBa
rrow
sand
ston
eD
STsa
mpl
e4
0.07
4ga
l/10
00ft3
2008
1.76
Hus
kyN
PRSo
uth
Barr
ow19
East
Barr
owBa
rrow
sand
ston
eD
STsa
mpl
e3
0.01
1ga
l/10
00ft3
2008
0.26
Hus
kyN
PRSo
uth
Barr
ow19
East
Barr
owBa
rrow
sand
ston
eD
STsa
mpl
e2
0.00
5ga
l/10
00ft3
2008
0.12
Hus
kyN
PRSo
uth
Sim
pson
1un
nam
edSi
mps
onsa
ndD
ST1
(ini
tial
stag
e)0.
199
gal/
1000
ft365
254.
74
Hus
kyN
PRSo
uth
Sim
pson
1un
nam
edSi
mps
onsa
ndD
ST1
(4m
inbe
fore
shut
in)
0.16
6ga
l/10
00ft3
6525
3.95
Hus
kyN
PRSo
uth
Sim
pson
1un
nam
edTo
rok
Form
atio
nD
ST2
0.20
9ga
l/10
00ft3
6192
4.98
Hus
kyN
PRSo
uth
Sim
pson
1un
nam
edTo
rok
Form
atio
nD
ST3
0.23
0ga
l/10
00ft3
5857
5.48
Hus
kyN
PRW
alak
pa2
Wal
akpa
Wal
akpa
sand
DST
10.
236
gal/
1000
ft326
035.
62
Texa
coTu
luga
k1
unna
med
Toro
k/F
ortr
ess
Mtn
DST
40.
904
gal/
1000
ft390
6621
.52
Texa
coTu
luga
k1
unna
med
Toro
k/F
ortr
ess
Mtn
DST
4re
test
0.14
3ga
l/10
00ft3
9066
3.40
Texa
coTu
luga
k1
unna
med
Toro
k/F
ortr
ess
Mtn
DST
50.
642
gal/
1000
ft382
7115
.29
*DST
=dr
illst
emte
st;
AO
GC
C=
Ala
ska
Oil
and
Gas
Con
serv
atio
nC
omm
issi
on.
**Th
ede
pth
refe
rsto
the
mid
poin
tof
the
prod
ucin
gin
terv
al.
Dep
th=
true
vert
ical
dept
hin
feet
.y bc
=ba
rrel
sof
cond
ensa
te.
Verma and Bird 1105
For associated gas (solution gas and/or gas-cap gas),
liquid/gas-ratio data are plotted against reservoir depth
in Figure 8. Limited data on liquid/gas ratios for so-
lution or gas-cap gas in the North Slope reservoirs show
the ratios to range between 10 and 100 bbl/MMSCF
for a depth range of 8000–13,000 ft (2438–3962 m).
By way of comparison, the liquid/gas ratios for the
United Kingdom North Sea reservoirs range from 29
to 400 bbl/MMSCF at STP for similar reservoir con-
ditions (Department of Trade and Industry, United
Kingdom, 2001). Considering the above liquid/gas ra-
tios for the two areas and the value of R2 for the three
mathematical functions (0.08 for the linear, 0.19 for
the power, and 0.22 for the exponential), we chose
an exponential function to regress the data, which gave
the following equation.
Liquid=gas ratio ¼ 3:3523 � ðeÞ0:000185 � Depth ð10Þ
where Liquid/gas ratio is the condensate reported in
barrels per million standard cubic feet, and Depth is the
reservoir depth in feet below surface.
The use of equation 10 yields a liquid/gas ratio of
21 bbl/MMSCF at 10,000 ft (3048 m) and 136 bbl/
MMSCF at 20,000 ft (6096 m), the maximum depth
of NPRA oil plays. These values are within the ranges
of liquid/gas ratios for the North Sea reservoirs as well.
For the nonassociated gas reservoirs, liquid/gas ra-
tio data are plotted against depth, as shown in Figure 9.
Data were regressed using three possible mathematical
functions: linear, logarithmic, and power. We chose
the linear function (equation 11, below) partly because
of its relatively higher value of R2 (0.21) compared
with logarithmic (0.10) and power (.07) functions, and
partly because the correlation resulted in liquid/gas
ratios similar to those in North Sea and North Slope
reservoirs.
Liquid=gas ratio ¼ 0:0013 � Depth ð11Þ
where Liquid/gas ratio is the condensate reported in
barrels per million standard cubic feet, and Depth is the
reservoir depth in feet below surface.
Liquid/gas ratios of 7, 20, and 33 bbl/MMSCF for
5000-, 15,000-, and 25,000-ft (1524-, 4572-, and
7620-m) reservoir depths, respectively, were calculat-
ed based on equation 11. The maximum depth pos-
tulated for gas prospects in the NPRA is 28,000 ft
(8534 m). For the nonassociated gas reservoirs on the
North Slope of Alaska, the liquid/gas ratios range be-
tween 0.1 and 22 bbl/MMSCF. These ratios compare
well with gas reservoirs in the United Kingdom sector
of the North Sea, where ratios range from 0.2 to 16 bbl/
MMSCF for similar reservoir conditions (Department
of Trade and Industry, United Kingdom, 2001).
The ratios defined in equations 10 and 11 have
been used to estimate the volumes of in-place natural
gas liquids for the NPRA plays. Because calculations
were based on limited data, however, additional data
Figure 8. Plot showing liquid/gas ratio data for associated gasvs. depth for wells on the NorthSlope of Alaska (Table 4). Ofthree possible functions (linear,logarithmic, and exponential), theexponential function was consid-ered more appropriate to re-gress the data because of therelatively higher value of R 2.
1106 Reservoir Engineering
are required to further improve correlations and to pro-
vide better estimates of natural gas liquids for both as-
sociated and nonassociated gas.
Recovery Factor
Technically recoverable resource volumes are calcu-
lated by multiplying in-place hydrocarbons by a recov-
ery factor that, although critical to the assessments for
both discovered and undiscovered fields, is not easily
defined because of its dependence on many interrelated
parameters. Porosity, permeability, reservoir litholo-
gy, hydrocarbon composition, oil gravity and viscos-
ity, reservoir depth and thickness, reservoir pressure
and temperature, type of trap, and type of drive (so-
lution gas, gas cap, water, or a combination drive) are
among the many variables that affect recovery factors.
Considering our limited knowledge of these param-
eters and their complexities, it was possible to only
estimate average recovery factors for oil and gas for
each play in the NPRA. In making these estimates, we
gave considerable weight to the recovery factors for
producing North Slope oil reservoirs that are summa-
rized in Table 1. Our estimated recovery factors for
the NPRA plays include that proportion of in-place oil
resources that is recoverable using both primary- and
secondary-recovery techniques.
Based on the information in Table 1, recovery fac-
tors for oil were established for three different groups
of reservoirs: reservoirs with poor-, intermediate-, and
good-quality porosity and permeability parameters, as
shown in Table 5. Adequate data were available from
reservoirs on the North Slope of Alaska to establish
the basic criteria for oil recovery factors, but not for
gas recovery factors. However, having definitive data
for establishing gas recovery factors for gas reservoirs
in this region is not as critical as for oil, because the
gas recovery factor is known to be high in general; for
example, recovery factors ranging between 65 and
72% have been reported for the Khuff gas reservoir
in the Bahrain field of the Middle East (Janahi and
Dakessian, 1985); the Northeast Hitchcock field in
Galveston County, Texas (Ancell and Manhart, 1987);
Table 5. Recovery Factors (Primary Plus Secondary Recovery)
Applied to the Petroleum Plays in the 2002 Assessment of the
NPRA*
Reservoir Rock/Fluid Quality
Reservoir Parameters Poor Intermediate Good
Porosity (%) <15 20–25 >25
Permeability (md) <50 100–200 >200
Oil Gravity (jAPI) <20 20–30 >30
Oil Recovery Factor (%) 30 35–40 50
Gas Recovery Factor (%) 60 65 70
*Based on oil recovery factors for reservoirs with different fluid and rockproperties (shown in Table 2) and gas-recovery factors from a generalizedcriteria established in the text.
Figure 9. Plot showing liquid/gas ratio data for nonassociatedgas in wells on the North Slopeof Alaska (Table 4). Of the threefunctions (linear, logarithmic,and exponential), the linearfunction was considered moreappropriate to regress the databecause of relatively higher valueof R 2.
Verma and Bird 1107
and an offshore Gulf Coast field (Hower et al., 1992).
In addition, Moltz (1993) has reported a recovery fac-
tor as high as 85% for Tom O’Connor 5100-ft Sand, a
gas reservoir in Refugio County, Texas.
In some cases, observed recovery factors may be
higher than the maximum shown in Table 5 (e.g.,
Ivishak reservoir in Prudhoe Bay field at greater than
50% recovery), but these higher values are related to
tertiary-recovery methods. Our estimated recovery fac-
tors for individual plays in the NPRA, which are limited
to a maximum of 50% for oil and 70% for gas, represent
average values for all undiscovered fields in a particular
play based on the application of primary- and secondary-
recovery techniques.
APPLICATION OF DERIVED EQUATIONS TO THENPRA ASSESSMENT
Estimation of technically recoverable hydrocarbon-
resource volumes for reservoirs in each of the 24 de-
fined plays in the NPRA was one of the main objec-
tives of the 2002 U.S. Geological Survey assessment;
this was achieved by incorporating all of the available
geologic and reservoir-engineering information to first
calculate the volume of hydrocarbon-in-place and then
multiply that value by a recovery factor to estimate
technically recoverable volumes. Figure 10 shows an
example of those parts of the assessment form dealing
with recovery factors and fluid characteristics. Table 6
Figure 10. Portions ofthe 2002 NPRA oil andgas assessment formshowing postulated en-gineering parameters foroil and nonassociatedgas accumulations for anindividual petroleumplay.
1108 Reservoir Engineering
Tab
le6
.C
alcu
late
dRe
serv
oir
and
Flui
dPa
ram
eter
sat
the
50th
Perc
entil
eD
epth
and
Estim
ated
Reco
very
Fact
orfo
rEa
chof
the
24Pl
ays
Eval
uate
din
the
2002
Ass
essm
ent
of
Und
isco
vere
dO
ilan
dG
asRe
sour
ces
inth
eN
PRA
*
Rese
rvoi
rFo
rmat
ion
Volu
me
Fact
or
Num
ber
Ass
essm
ent
Play
Nam
eTy
pe(O
ilor
Gas
)D
epth
(ft
S)Pr
essu
re(p
si)
Tem
pera
ture
(jF)
Oil
Gra
vity
(jA
PI)
Gas
Gra
vity
Solu
tion
GO
R(s
cf/S
TB)
Oil
(bbl
/STB
)G
as(s
cf/f
t3)
Reco
very
Fact
or(%
)
1Br
ooki
anTo
pset
oil
5000
2500
125
37.0
0.70
060
91.
3035
gas
5000
2500
125
0.60
018
565
2Br
ooki
anTo
pset
Stru
ctur
aloi
l20
0010
0068
37.0
0.61
720
81.
0735
gas
2000
1000
680.
600
8260
3Br
ooki
anC
linof
orm
Nor
thoi
l70
0035
0016
337
.00.
733
867
1.47
35ga
s70
0035
0016
30.
600
224
654
Broo
kian
Clin
ofor
mC
entr
aloi
l10
,000
5000
220
37.0
0.76
912
391.
7435
gas
12,0
0060
0025
80.
600
271
655
Broo
kian
Clin
ofor
mSo
uth
–Sh
allo
woi
l60
0030
0014
432
.00.
707
613
1.31
30ga
s10
,000
5000
220
0.60
025
665
6Br
ooki
anC
linof
orm
Sout
h–
Dee
pga
s15
,000
7500
315
0.60
028
665
7Br
ooki
anTo
rok
Stru
ctur
aloi
l50
0025
0012
528
.00.
680
433
1.21
30ga
s40
0020
0010
60.
600
155
658
Beau
fort
ian
Cre
tace
ous
Tops
etN
orth
oil
8000
4000
182
30.0
0.73
175
91.
4235
gas
8000
4000
182
0.57
123
470
9Be
aufo
rtia
nC
reta
ceou
sTo
pset
Sout
hga
s12
,000
6000
258
0.57
127
070
10Be
aufo
rtia
nU
pper
Jura
ssic
Tops
etN
Woi
l90
0045
0020
139
.00.
762
1209
1.71
5011
Beau
fort
ian
Upp
erJu
rass
icTo
pset
NE
oil
9000
4500
201
39.0
0.76
212
091.
7150
12Be
aufo
rtia
nU
pper
Jura
ssic
Tops
etSW
oil
11,0
0055
0023
939
.00.
782
1554
1.96
50ga
s13
,000
6500
277
0.57
627
765
13Be
aufo
rtia
nU
pper
Jura
ssic
Tops
etSE
oil
11,0
0055
0023
939
.00.
782
1554
1.96
50ga
s13
,000
6500
277
0.57
627
765
14Be
aufo
rtia
nLo
wer
Jura
ssic
Tops
etoi
l50
0025
0012
530
.00.
685
467
1.23
30ga
s80
0040
0018
20.
576
234
6515
Beau
fort
ian
Clin
ofor
moi
l90
0045
0020
139
.00.
762
1209
1.71
35ga
s12
,000
6000
258
0.57
627
065
16El
lesm
eria
n-Iv
isha
koi
l90
0045
0020
123
.00.
725
648
1.37
40ga
s90
0045
0020
10.
585
246
6517
Elle
smer
ian-
Endi
cott
Nor
thoi
l80
0040
0018
225
.00.
719
627
1.34
50ga
s80
0040
0018
20.
585
235
6518
Elle
smer
ian-
Endi
cott
Sout
hga
s20
,000
10,0
0041
00.
585
304
6519
Elle
smer
ian-
Echo
oka
Nor
thoi
l90
0045
0020
124
.00.
728
674
1.38
40ga
s90
0045
0020
10.
585
246
6520
Elle
smer
ian-
Echo
oka
Sout
hga
s15
,000
7500
315
0.58
528
665
21El
lesm
eria
n-Li
sbur
neN
orth
oil
10,0
0050
0022
024
.00.
739
739
1.43
30ga
s10
,000
5000
220
0.58
525
565
22El
lesm
eria
n-Li
sbur
neSo
uth
gas
15,0
0075
0031
50.
585
286
6523
Elle
smer
ian-
Stru
ctur
alga
s21
,000
10,5
0042
90.
585
308
6024
Elle
smer
ian-
Thru
stBe
ltoi
l50
0025
0012
530
.00.
685
467
1.23
30ga
s15
,000
7500
315
0.58
528
665
*Res
ervo
irde
pth
and
oilg
ravi
tyar
ede
fined
.Sol
utio
nga
sgr
avity
islo
oked
upfr
oma
char
t.Pr
essu
re,t
empe
ratu
re,s
olut
ion
gas-
oilr
atio
,and
FVF
are
calc
ulat
edus
ing
equa
tions
defin
edin
the
text
.Rec
over
yfa
ctor
sha
vebe
enas
sign
edba
sed
ona
gene
ral
crite
ria
esta
blis
hed
inth
ete
xt.
Reco
very
fact
ors
repr
esen
tpr
imar
ypl
usse
cond
ary
reco
very
.Se
eFi
gure
2fo
rge
nera
lst
ratig
raph
ican
dst
ruct
ural
loca
tion
ofpl
ays.
Verma and Bird 1109
shows the calculated reservoir parameters and estimat-
ed recovery factors for undiscovered oil and gas fields
in each of the assessed plays. Reservoir parameters
shown are those for the 50th percentile estimate of
trap depth in each play.
The final step in the 2002 U.S. Geological Survey
assessment was to apply the U.S. Geological Survey
deposit-simulation method for oil and gas (Schuene-
meyer, 2003), which is a Monte Carlo-based system
that incorporates estimates of the geological, geochem-
ical, and engineering factors necessary to create an
oil or gas deposit. In this system, 10,000 simulations
are typically run for each play, and the resulting out-
put consists of probability distributions of field-size
distributions, as well as estimates of the in-place and
recoverable hydrocarbon volumes for each play. The
geographical distribution of plays, their estimated hy-
drocarbon volumes, and sizes and numbers of accu-
mulations provide the basic input for the economic
analysis. Total resource estimates for the assessment
area are obtained by an aggregation procedure that con-
siders interplay dependencies of hydrocarbon charge,
trap, and timing.
GENERAL COMMENTS AND CONCLUSIONS
1. Integration of reservoir-engineering factors leads to
better constrained calculations of discovered reserves
as well as estimates of undiscovered resources. More
precise estimates of the costs involved in field devel-
opment and infrastructure are also achieved, which
in turn leads to a better economic analysis of the play
area under consideration.
2. Pressure-depth and temperature-depth correlations
were established for the NPRA assessment.
3. A modification of Standing’s (1947) method was
developed to calculate GORs and FVFs for the un-
discovered oil reservoirs in each NPRA play. The
GORs are expected to be accurate within ±16% and
FVFs within ±8% for reservoirs with average reser-
voir conditions.
4. The equation for gas FVF is based on the general gas
equation, which includes a compressibility factor (z)to account for deviation in the behavior of natural
hydrocarbon-gas mixtures from that of ideal gases.
Corrections to z are required for the presence of non-
hydrocarbon gases.
5. The study provides useful guidelines for similar
reservoir-engineering studies in support of assess-
ment of undiscovered oil and gas reservoirs in other
areas.
6. The 2002 NPRA assessment provides an order of
magnitude increase in richness of engineering detail
compared to the previous (1980) U.S. Geological
Survey assessment of the NPRA. Partly because of a
scarcity of North Slope analog data and partly be-
cause the assessment method was still being devel-
oped, the 1980 U.S. Geological Survey assessment
reported only in-place oil resources and applied the
same single-value recovery factors to all assessed
plays; FVFs were not considered in that analysis. The
significance of engineering factors is easily demon-
strated by the 2002 U.S. Geological Survey assess-
ment, where the application of FVFs resulted in
surface oil volumes 15–50% smaller than in-place oil
volumes and surface gas volumes 82–308% larger
than in-place gas volumes. Furthermore, recovery
factors, assigned to each play, ranged from 30 to 50%
for oil and 60–70% for gas.
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Verma and Bird 1111