Acquisition of Oil Field
Figure 1. Location of ERT Field, Texas
Panhandle, within tectonic framework (after Budnik, 1989).
Figure 2. ERT Field, as of 1994, with
seven wells, including one dry hole and one marginal well (2-3).
Figure 3. Type log , Horizon O&G Bivins
Ranch No. 1-3, Penn Sand discovery well , and stratigraphic chart (after
Dutton, 1980).
Figure 4. Tectonic framework, Texas
Panhandle, with location of ERT Field and north-south stratigraphic
cross-section (M-M’) (Figure 5), which extends along the basinal part
(“throat”) of the Palo Duro Basin between Canyon (Missourian) shelf
margins to east and west.
Figure 5. Stratigraphic cross-section
M-M’ (north-south section across Palo Duro Basin) (after Rose, 1986).
Canyon (Missourian) facies is starved-basin. Cisco (Virgilian) section
is dominantly shale.
Figure 6. Tectonic framework, Texas
Panhandle, with location of ERT Field and west-east stratigraphic
cross-section (U-U’) (Figure 7), which extends across the west and east
Canyon shelf margins.
Figure 7. West-east stratigraphic
cross-section U-U’ (after Rose, 1986). A field is located in the area of
Cisco shale between the Canyon shelf edges.
Figure 9. Map of Potter County, Texas,
with area of 961 sq. mi., showing location of ERT Field.
Figure 10. Tabulation of reservoirs in
pre-Permian fields in northern Palo Duro Basin, according to reservoir,
date of completion, and EUR (as of third quarter, 1995).
Figure 12. Graph of pre-Permian field
size distribution, showing ERT for comparison. Pink=granite wash;
blue=limestone; yellow=sandstone.
Figure 13. Graph of pre-Permian field
size distribution, showing most likely size and size of “one-of-a-kind”
field. The shaded area indicates a rough estimate of the remaining
potential for the Pre-Permian fields in the basin.
Click here for sequence of Figures 12
and 13.
Figure 14. Penn Sand porosity logs for
first two well completed in ERT Field (Bivins Ranch No. 1-2 and Bivins
Ranch No. 1-3).
Figure 15. Penn Sand porosity logs for
Bivins Ranch No. 2-2 and Bivins Ranch No. 3-2.
Figure 16. Penn Sand porosity log for
Bivins Ranch No. 3-3.
Figure 17. Stratigraphic cross-section
A-A’ of Penn Sand. Porosity logs
were truncated so that 0% is the right margin, with 30% on the left.
Purchasing an oil field successfully
requires that that its size be accurately estimated. Determination of
the field size is literally the million-dollar question.
An
overview map of the Texas Panhandle, with counties and geologic
features, provides the setting of ERT Field (Figure
1). In 1994, Tide
West Oil Company had an opportunity to acquire this partly developed oil
field. The operator was Horizon Oil &Gas of Spearman, Texas. They had
drilled seven wells with one dry hole and one marginal well . They had
discovered what they called a “Tonkawa” sandstone reservoir. This field
was located south (“on the backside”) of the Amarillo Uplift, on the
northern rim of the Palo Duro Basin.
The log of the Penn Sand discovery well ,
Horizon O&G Bivins Ranch No. 1-3, completed December, 1991, with IPP 112
BO, 0 BW, Gas TSTM, shows the position of the producing reservoir
relative to overlying Permian?/Pennsylvanian shale below Permian
carbonates and underlying granite wash with mixed lithologies. Based on
the position of the sand relative to the Permian carbonates, a geologist
familiar with the Anadarko basin would probably think of the Penn Sand
as “Tonkawa” or even “Douglas,” essentially Virgilian in age. The
problem with assigning the sand as “Tonkawa” is that it attached a whole
string of attributes based on the technical staff’s experience with that
unit in the Anadarko Basin. The result was that there was not too much
excitement about the added potential of the producing sand.
By naming it “Penn Sand,” we recognized
how little we knew about the reservoir and how little we knew about its
producing attributes and ultimate field size potential. This made it
“new” and generated much more open-minded thinking about its potential.
At the time we evaluated ERT Field for
purchase, it consisted of seven wells (Figure
2) that had been drilled
in the following order:
1-2 = Granite wash oil discovery
1-3 = Penn Sand oil discovery
2-3 = T/A-- Penn sand tight
3-3 = Penn Sand oil
2-2 = Penn Sand oil
3-2 = Penn Sand oil
4-2 = Dry hole; Penn Sand absent.
For assessing the size of the field, we
organized the geologic research as follows:
• Analyze field size of existing fields
Field size vs. discovery date
Field size distribution
• Map existing data
• Synthesize and draw conclusions
Also, a strong sense of urgency was
given to these tasks. Palo Duro Basin references were identified and
studied from personal libraries, Petroleum Abstracts, which was cost
effective, AAPG Library and AGI’s GeoRef, Oklahoma Well Log Library, and
miscellaneous sources (e.g., colleagues).
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Understanding the stratigraphic and
tectonic settings (Figures 3 and 4) were considered to be
fundamental for study of the field. The tectonic framework (after Budnik,
1989) and stratigraphic cross-sections (after Rose, 1986) were important
data in this study (Figures 4, 5,
6, and 7). Cross-section M-M’ extends
along the basinal part (“throat”) of the Palo Duro Basin between Canyon
shelf margins to east and west (Figure 5). There was step-back of Canyon
shelf carbonates in the SW Potter County area. The shelf was either
drowned or smothered; this may have been the result of an increase of
clastic sediments from the uplift to the north in late Canyon
(Missourian), early Cisco (Virgilian) time. Dutton’s interpretation
(1980) for this area is a substantial Late Pennsylvanian clastic wedge.
ERT Field is in the Whittenburg Trough,
north of Bush Dome in the northern part of the Palo Duro Basin (Figure
8). Principal routes of sand transport are from the Amarillo Uplift and
secondarily from the Bush Dome and Bravo Dome (Rose, 1986).
In ERT Field, the non-arkosic Penn Sand
accumulation is positioned within major transport routes and major
accumulation of sediments. Hydrocarbon traps are present in Missourian
and Virgilian “wash” on the north side of the Amarillo Uplift. There is
potential for distal shale-out and dip reversal against the Bush Dome in
SW Potter County.
In Potter County, Texas (Figure
9), with
area of 961 sq. mi., about 200 acres of the 22,000-acre lease had been
developed when Tide West bid on ERT Field. About a dozen wells had been
drilled within the 100 sq. mi. centered on the field. In the county,
there were only 53 wells drilled deeper than 4800 feet to penetrate
pre-Permian; some of these were deep enough to have encountered the Penn
Sand.
In assessing the field size, research was
undertaken to (1) analyze the field size of existing fields by plotting
field size vs. discovery date and field size distribution, (2) prepare
maps from existing data, and (3) synthesize the data and draw
conclusions.
To analyze field size of existing
fields, the efforts were undertaken to:
(1)
Calculate Estimated Ultimate Recovery (EUR) of each
field/reservoir
(2)
Identify reservoir lithology
(3)
Identify reservoir age
(4)
Plot field size vs. discovery date
(5)
Plot field size distribution and curve
Ultimate recovery of 20 pre-Permian
reservoirs in fields in northern Palo Duro Basin, as of the third
quarter, 1995, was 14.5 MMBO (Figure 10). Average field size was 725 MBO,
with maximum being 4.3 MMBO; median was 86 MBO.
Based on a plot of EUR vs. discovery
year, there is no decrease of field size with time (Figure
11). This
probably indicates that the basin probably is not fully mature.
For the distribution of pre-Permian
field size, a 5th order
trend line is close to fitting the data. The trend line shown in Figure
12 is “eyeballed,” based on analysis of the distributions of field sizes
in more mature basins. The normal truncation of the “bell curve” for
the very small fields is the economic effect of drilling for oil and
gas. At some low-end economic point, the “field” turns into a “show”
and drops off the chart (Figure
12). Based on this curve and the
position of the field on the curve in its undeveloped state, a range of
field sizes can be estimated. The most likely Penn Sand field size is
estimated to be 1.5-2.5 MMBO (Figure 13); the size of a “one-of-a-kind”
field is 3.2-4.75 MMBO.
In cross-section and on an isopach map,
the reservoir is shown to thin to the south. We estimated that there
were 53 wells in the entire
county sufficiently deep to have cut the Penn Sand, with about 12 wells
within the 100 sq mi centered on the field. Only about 200 acres of the
22,000 acre lease were developed or explored to this depth in 1995. It
was estimated that a porosity pinch-out exists within one location to
the south. The operator had stopped field development with its last well
(4-2)--a dry hole. Their success rate was 5 out of 7, or 71%. The asset
was put-up for sale due to the settlement of a deceased partner’s
estate. The operator was a “driller” not a “producer.”
Completion data for the first two wells
drilled by Horizon, Bivins Ranch No. 1-2 and Bivins Ranch No. 1-3 (Figure
14), are IPP 105BO/48BW/TSTM (granite wash) and IPP 112BO/0BW/TSTM,
respectively. Additional development wells drilled by Horizon are Bivins
Ranch No. 2-2, with IPP 116BO/12BW/TSTM, Bivins Ranch No. 3-2, with IPP
122BO/BW16/TSTM (Figure 15), and Bivins Ranch No. 3-3, with IPP281BO/-/TSTM
(Figure 16). A stratigraphic cross-section
(Figure 17) of the Penn Sand
shows the best development to be in Bivins Ranch No. 3-3, which had the
highest IPP.
At the time we purchased ERT Field, its
EUR was 1 MMBO. Only one side of the field was delimited, and FSD
strongly suggested the most likely size would be 1.5 to 2.5 MMBO.
Further, the “one-of-a-kind” OOAK (say “oak” effect) was significant,
and that helped bolster confidence in the premium paid. Two 230 MBO
wells were equated to about 2.8 BCFE with an approximate PV10 of $1.5MM.
We thought that paying for two locations
was a good bid, because we had an 80% confidence level that we would
drill two, perhaps three times that many wells. Further, two wells would
make the field a 1.5 MMBO field, which fit the FSD.
This reasoning and strategy worked. We
bought the field for $1.5MM, based on primary development and recovery.
The potential for secondary recovery was discounted to zero.
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Figure Captions (18-51)
Figure 18. Porosity logs of Bivins Ranch
No. 1-2 and Bivins No. 1-3, with thin shale beds, as estimated from the
engineering reservoir “model.”
Figure 19. Porosity logs of Bivins Ranch
No. 2-2 and Bivins No. 3-2, with thin shale beds, as estimated from the
engineering reservoir “model.”
Figure 20. Porosity log of Bivins Ranch
No. 3-3, with thin shale beds, as estimated from the engineering
reservoir “model.”
Figure 21. Cross-section A-A’ showing
reservoir “model” of continuous shale interbeds.
Figure 22. ERT Field, showing 1995
development wells, including two cored wells (Bivins Ranch No. 4-3 and
Bivins Ranch No. 6-2).
Figure 23. Well log of the Penn Sand,
along with overlying and underlying sections in Bivins Ranch No. 4-3,
showing cored interval.
Figure 25. Brown oil-stained sandstone
with irregularly distributed gray, calcite-cemented sandstone, Bivins Ranch No. 4-3, 5200-5210 feet.
Click here for sequence of Figures 25
and 26.
Figure 27. Cored interval in Bivins
Ranch No. 4-3, together with lithologic and sedimentologic
interpretation, showing position of sample of shaly sandstone
photographed (5212 feet core depth adjusted to match log depth (Figure 28).
Figure 28. Shaly,
porous sandstone, with
ripple-lamination, Bivins Ranch No. 4-3, 5212
feet.
Figure 29. Cored interval in Bivins
Ranch No. 4-3, together with lithologic and sedimentologic
interpretation, showing position of photomicrograph of crinoidal clay
shale (Figure 30).
Figure 30. Some articulated crinoid
stems among the predominant disarticulated stems in clay shale.
Photomicrograph from Bivins Ranch No. 4-3, 5303 feet.
Figure 31. Well log of Penn Sand, along
with overlying and underlying sections in Bivins Ranch No. 6-2, showing
cored interval.
Figure 32. Cored interval in Bivins
Ranch No. 6-2, together with lithologic and sedimentologic
interpretation, showing interval of shaly sandstone photographed
(5586-5596 feet core depth adjusted to log depth) (Figure
33).
Location
of well in Figure 22.
Figure 33. Brown oil-stained sandstone
(in ordinary light), with patches of gray, calcite-cemented sandstone Bivins Ranch No. 6-2,
5586-5596 feet.
Figure 34. Same cored interval in Bivins
Ranch No. 6-2 as presented in Figure 33,
showing sharp vertical and horizontal
contacts between calcite-cemented sandstone (dark) and porous rippled
sandstone (yellow) (in ultraviolet light).
Click here for sequence of Figures 33
and 34.
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Figure 35. Cored interval in Bivins
Ranch No. 6-2, together with lithologic and sedimentologic
interpretation, showing position of sample of sandy shale photographed
(5626-5636 feet core depth adjusted to log depth) (Figure 36).
Location of well in Figure 22.
Figure 36. Sandy shale, interpreted as
turbidite, in Bivins Ranch No. 6-2, 5626-5636 feet, with oil-stained
(but tight) sand ripples (yellow) (in ultraviolet light).
Figure 37. Highly cemented shaly
sandstone (arrowed) vs. shaly sandstone with 12% porosity, Bivins Ranch
No. 4-3. Note sharp gray-brown color contrast that cuts across bed
boundaries.
Click here for sequence of Figures 37
and 38.
Figure 41.
Bivins Ranch No. 4-3, 5238.5 feet, near
base of shaly sandstone. Core porosity = 2.8%; permeability(air)
= 0.4md. Framework grains are extensively calcite-cemented or have been
replaced by calcite.
Figure 42. Core interval in Bivins Ranch
No. 6-2 (5586-5596 feet) (in ultraviolet light), along with interval of FMI log (5577-5579.8
feet) for correlation of core and FMI.
Figure 43. Core-FMI correlation, Bivins
Ranch No. 6-2, 5577-5579.8 feet ( log depth). Highly cemented sandstone = “bright
spot” (high resistivity).
Figure 44. Porosity distribution shows
distinct bimodality (3.5-6.5% and 11.5-16.5%).
Figure 45. Porosity vs. permeability,
showing bimodality of these parameters, cluster of which for the pay
zone is 11-16% porosity and 0.3-10 md.
Figure 46. Grain density vs. core
porosity, Bivins Ranch No. 6-2, showing a sample grouping due to calcite
cement.
Figure 47. Core- log porosity in Bivins
Ranch No. 4-3 and No. 6-2, showing good correlation where porous and
highly cemented intervals are greater than 1.5 feet thick.
Figure 48. Core- log porosity, where
porous and highly cemented intervals are less than than 1.5 feet thick,
in Bivins Ranch No. 4-3 and No. 6-2, showing that log porosity is too
high for tight intervals and too low for porous intervals.
Figure 49. A. Core- log porosity plot,
showing that log porosity in the porous sandstone is lower than core
porosity. B. Core- log porosity plot, with differences in porosity
determinations, where log porosity is less than core porosity, shown in
yellow.
Click here for sequence of Figure 49A
and 49B.
Figure 50. Cross-section A-A’. A.
Showing reservoir “model” of continuous shale interbeds (Figure 21).
B.
Showing schematically lateral continuity on an inter- well scale.
Click here for sequence of Figures 17
and Figure 50A and 50B.
Figure 51. Map of ERT Field showing 1995
and post-1995 development.
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Well - Log and Penn
Sand Interpretation
At the time ERT Field was acquired, we
needed to learn how to interpret accurately the well logs of this
low-contrast reservoir and its architecture. The Penn Sand porosity
logs, as envisioned by the technical staff, showed laterally persistent
thin beds of shale (Figures 18, 19,
20, and 21). Based on a conventional
interpretation of open-hole log signature, the engineering reservoir
“model” when ERT Field was acquired was a horizontally layered reservoir
with tight vertical boundaries. This would tend to create early or
premature water break-through, with failure of a waterflood. In other
words, the reservoir was considered to be a poor candidate for
waterflooding due to the probability of premature water breakthrough and
inaccessible compartments and potential for trapped oil that never sees
the flood. In order to test this interpretation, well - log data from the
existing control together with those from the seven Penn Sand
completions drilled in 1995 and cores from two of those wells at
opposite ends of the field (Figure 22) needed to be examined in terms of
detailed correlation, depositional environment, and diagenesis.
The cored interval in Bivins Ranch No.
4-3 is of the lower 46 feet (of 61 feet) of the Penn Sand and 70 feet of
the underlying strata (Figure 23). The Penn Sand is a shaly sand that is
ripple-laminated and is thought to be a turbidite (Figures 24,
25, 26, 27, and
28). The underlying unit is also a turbidite deposit that is a
sandy shale; it in turn is underlain by a crinoid-rich shale (Figures 24,
29, and 30). The sandstone is
brown, oil-stained, with gray,
calcite-cemented patches that are irregularly distributed. The
predominance of disarticulated crinoid stems in the shale suggests that
they have experienced some transport but have not been greatly worn
during transport. Crinoids lived in relatively shallow marine waters.
However, the overall core and basinal setting suggest the possibility
that emplacement of the massive crinoidal clay shale was by sediment
gravity flow and that the fossils are “out of place.”
The cored interval in Bivins Ranch No.
6-2 is of the lower 62 feet (of 78 feet) of the Penn Sand and 61 feet of
the underlying beds (Figure 31). The Penn Sand, as in Bivins Ranch No.
4-3, is a shaly, ripple-laminated sand that is also interpreted as a
turbidite (Figures 32, 33, and
34). The underlying section is a sandy
shale that is also a ripple-laminated turbidite (Figures 35 and
36).
The oil-stained sandstone, with
significant porosity, shows sharp vertical and horizontal contacts
between calcite-cemented (gray) and less well cemented rippled sandstone
(brown) (Figures 37 and 38). Representative samples of the oil-stained
sandstone have porosity of 12 to 14% and permeability of 3-4 md in both
Bivins Ranch No. 4-3 and No. 6-2 (Figures 38,
39, and 40). Clay laminae in the
sandstone tend to be microscopic to macroscopic flow barriers; however,
they are very unlikely to persist as inter- well vertical flow barriers.
Representative porosity in the highly cemented sandstone in Bivins Ranch
No. 4-3 (Figure 41) is 3%; permeability in this type of sandstone is
0.05-0.4 md. Cementation boundaries are very sharp and do not follow any
bed boundary. The cementation boundary is only three grains wide, with
less than one millimeter transition, well below the discrimination of
any open-hole porosity tool. The patches of highly cemented sandstone
are represented by “bright spots” of high resistivity on the FMI tool
(Figures 42 and 43).
Porosity from core analyses shows a
distinct bimodal distribution, with almost 25% of the samples showing
3.5-6.5% and approximately 70% showing 11.5-16.5% (Figure
44). The
former, of course, corresponds to the highly cemented sandstone, and the
latter corresponds to the oil-stained sandstone.
A plot of porosity vs. permeability for
Bivins Ranch No. 4-3 and No. 6-2, with 125 data points, also shows the
bimodality of the data set, with the relatively tight cluster of
pay-zone porosity from 11 to 16% (Figure 45). This cluster (within 5 PU)
reflects the dominance of single grain size (very fine) and single
sedimentary structure (ripple). Bimodality reflects the sharp boundary
(within three sand grains) between porous and cemented sand with
porosity occluded. There is little to no gradational porosity –
consistent with visual interpretation of cores. Diagenetic occlusion of
porosity by calcite cementation has created a petrographic group with
higher grain density (Figure 46).
Comparison of porosity from core
analyses and from log (density) determination shows that logs are good
in resolving porosity for porous and tight intervals thicker than 1.5
feet (Figure 47). However, for intervals less than 1.5 feet thick, log
porosity is too high for tight intervals and too low for porous
intervals (Figures 48 and 49). This effect is the direct result of thin
beds. The tight beds fall below the cut-off of 10%. Some of the porous
beds are netted, and if so, the magnitude of porosity is understated.
The original engineering reservoir
model, which was based on a conventional interpretation of open-hole log
signature, was that the reservoir is a layered system and that it was a
poor waterflood candidate due to probability of premature water
breakthrough and inaccessible compartments and potential for trapped oil
that never sees the flood. However, from integration of core studies
with log interpretation, it can be shown that lateral continuity on an
inter- well scale should be present. There should be acceptable vertical
paths for fluids to flow throughout reservoir and avoid premature water
breakthrough if flooded.
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-
Tight streaks on logs do not
necessarily represent laterally continuous shale or impermeable beds (Figure
50).
-
The porosity of the pay zone is in a
narrow range of 12 to 16%.
-
The sandstone is very fine-grained but
the pore system is homogeneous.
-
The pore throats are small (5-10
micrometers).
-
The reservoir is highly heterogeneous
on a small scale, but it is likely to be laterally and vertically
continuous on an inter- well scale.
-
Waterflood is feasible.
-
Secondary recovery potential of 3 MMBO.
-
Waterflood is valued at $19MM pv10.
Cumulative production through June 1,
2002, was 1.13 MMBO, with hyperbolic decline from 15 Penn Sand producers
(Figure 51). Remaining reserves are estimated to be about 0.95 MMBO. EUR
of the field is currently estimated to be 2.1 MMBO, or nearly exactly
the estimate based on original FSD curves. Original estimate was that
the most likely field size would be 1.5 to 2.5 MMBO.
Budnik R.T., 1989, Tectonic structures
of the Palo Duro Basin, Texas Panhandle: University of Texas Bureau of
Economic Geology Report of Investigations (RI) 187, 43 p.
Dutton, S.P., 1980, Petroleum source
rock potential and thermal maturity, Palo Duro Basin, Texas: University
of Texas at Austin, Bureau of Economic Geology Geological Circular
80-10, 48 p.
Rose, P. R., 1986, Petroleum geology of
the Palo Duro Basin, Texas Panhandle: Office of Nuclear Waste Isolation,
Battelle Memorial Institute, BMI/ONWI-589, 45 p.
Acknowledgment is made to the following
for assistance in this study:
• Questar E&P, Tulsa, Oklahoma
• Joe Campbell (regional geology)
• Mike Kuykendall (petrography)
• Rod Tillman (core interpretation &
project supervision)
• Garner Wilde (biostratigraphy)
• Technical Staff, Tide West Oil
Company, Tulsa, Oklahoma.
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