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tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

tWell-log & Penn Sand interpretation

Figure 1. Location of ERT Field, Texas Panhandle, within tectonic framework (after Budnik, 1989).

Acquisition of Oil Field

Figure Captions (1-17)

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 8. Structural contour map, major faults, and other tectonic features to depict geologic setting of ERT Field, which is in the Whittenburg Trough, north of Bush Dome in the northern part of the Palo Duro Basin. Arrows show principal routes of sandstone transport (Rose, 1986).

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 11. Plot of EUR vs. discovery year, with designation of the three principal reservoir types--Penn granite wash (arkosic sandstone), Penn carbonates, and Penn sandstone (non-arkosic sandstone) and changes in seismic technology.

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.

ERT Field

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).

Regional Geologic Setting

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.

Assessing Field Size

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.

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.”

Development of ERT Field after Acquisition

Figure Captions (18-51)

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 24. Lithologic and sedimentologic interpretation of cored interval in Bivins Ranch No. 4-3, along with position of interval photographed (5200-5210 feet core adjusted to match log depth) (Figures 25 and 26). Location of well in Figure 22.

Figure 25. Brown oil-stained sandstone with irregularly distributed gray, calcite-cemented sandstone, Bivins Ranch No. 4-3, 5200-5210 feet.

Figure 26. Photograph of same cored interval in Bivins Ranch No. 4-3 as presented in Figure 25, showing sharp vertical and horizontal contacts between calcite-cemented sandstone and porous, rippled sandstone.

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.

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.

Figure 38. Same photograph as in Figure 37, with boundary between sandstone types outlined in green. Porosity changes from 12.4% in the oil-stained sandstone to 4.1% in the highly cemented sandstone. Changes in porosity occurs across a width of three sand grains (less than 1 mm).

Click here for sequence of Figures 37 and 38.

Figure 39. Bivins Ranch No. 4-3, 5213.2 feet in central part of porous shaly sandstone. Core porosity = 14.1%; permeability_(air) = 4.2 md. Good primary porosity between framework grains of monocrystalline quartz, feldspar, and other constituents. Rock is lithic arkose to feldspathic litharenite. Pseudomatrix in upper left (brown patch) is a result of compaction and alteration of argillaceous sedimentary rock fragment.

Figure 40. Bivins Ranch No. 6-2, 5596.4 ft. From base of shaly sandstone. Core porosity = 14.1 %; permeability_(air) = 4.2 md. Very thin clayey/micaceous lamination with several subrounded and equant (plagioclase feldspar) grains and secondary pores (blue). Black grains (upper right) are small zircon grains. Calcite (C) occurs as a patchy carbonate cement.

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.

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).

Reservoir Properties

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.

Conclusions

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.

Update as of August, 2002

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.

References

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.

Acknowledgments

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.