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A Geologic Review of the Mahogany Subsalt Discovery: A Well That Proved a Play*
(The Mahogany Subsalt Discovery: A Unique Hydrocarbon Play, Offshore Louisiana**)

Holly Harrison¹, Dwight ‘Clint’ Moore², and Peggy Hodgkins³

Search and Discovery Article #60049 (2010)

Posted April 28, 2010

*Adapted from presentation at AAPG Annual Convention, 1995, and from **extended abstract prepared for presentation at GCSSEPM Foundation 16th Annual Research Conference, “Salt, Sediment and Hydrocarbons,” December 3-6, 1995.
Extended abstract used with permission of GCSSEPM Foundation whose permission is required for further use.
Appreciation is expressed to GCSSEPM Foundation, and to Dr. Norman C. Rosen, Executive Director, for permission to use it in this adaptation.

¹ Phillips Petroleum Company, Bellaire, TX; currently BP, Houston, TX ([email protected])

² Anadarko Petroleum Corporation, Houston, TX; currently ION Geophysical Corporation, Houston, TX ([email protected])

³ Amoco Production Research, Tulsa, OK; currently Veritas Hampson-Russell, Calgary, AB ([email protected])

Abstract

The Mahogany subsalt discovery of Phillips Petroleum Company, in partnership with Anadarko Petroleum Corporation and Amoco Production Company, is the petroleum industry's first commercial subsalt oil development in the Gulf of Mexico. Located 80 miles offshore Louisiana on Ship Shoal Blocks 349 and 359, the Mahogany #1 (OCS-G-12008) was drilled in 375 ft of water to a depth of 16,500 ft and tested both oil and gas below an allochthonous salt sheet. The discovery well tested 7256 BOPD and 7.3 MMCFD on a 32/64" choke at 7063 PSI flowing tubing pressure (FTP). The #2 delineation well (OCS-G-12008) was drilled from the same surface location to a depth of 19,101 ft MD (18,572 ft TVD). A different zone in this well was tested in July, 1994, and flowed 4366 BO and 5.315 MMCFD on a 20/64” choke at 6287 PSI FTP. These flow rates suggest that high sustainable production rates can be expected, and they are confirmed by rock property studies and detailed well log analysis. A third well (OCS-G-12010 #2) was spud in September, 1994.

The primary subsalt reservoir is a high-pressured oil sand with high permeability and porosity and has tremendous deliverability. The field is located 80 miles offshore Louisiana on Ship Shoal South Additions blocks 349/359. The structure is interpreted as a faulted anticline overlain by allochthonous salt. Prestack depth-migrated 3-D seismic data was integrated into a regional geologic model that was based on 2-D time-migrated data. Regionally, the area is characterized by multiple salt sheets, which form a salt canopy sutured east of Mahogany, and several older and deeper sheets are also identified. Structural and rheological aspects of the thick salt sill have been addressed using selected examples of rotary sidewall cores and data on an anomalous "gumbo" shale immediately below the salt which contributes to the understanding of lateral variations at the base of the allochthonous salt.

Subsalt depositional fairways can be approximated by mapping relative salt-induced paleo-bathymetry. Deepwater sand fairways are closely related to salt movements and extend under the salt sheets. Depositional environments and reservoir parameters in productive sandstone intervals have been defined using whole core and well log imaging.

Introduction

	Figure 1. Map showing wells that were drilled through the allochthonous salt, as of 1995.
	Figure 2. Mahogany is generally on trend with Bullwinkle, Boxer, and Green Canyon 18 fields. These oil fields produce from Pleistocene and Pliocene slope sands - referred to as the flex trend because of the shelf/slope flexure.
	Figure 3. Map showing extent of salt sheets and the Ewing Bank thrust, which runs the leading edge of the eastern salt sheet. Seismic line A-A’ is a north-south 2-D line.
	Figure 4. Seismic line A-A’ is a north-south 2-D line that shows the Ewing Bank thrust may become listric below salt.
	Figure 5. Subsalt structure map. Deep salt features under allochthonous salt on 2-D data can be mapped and tied with regional mapping in the area. Line B-B’ runs from a deep basin in the SW to a deep basin in the NW.
	Figure 6. Seismic Line B-B’ runs from a deep basin in the SW to a deep basin in the NW. The Ewing Bank thrust terminates along this edge of the salt sheet system and emphasizes the separation of the structures above and below salt.
	Figure 7. Map of subsalt fairways shows the probable distribution of sedimentary fairways below the Mahogany salt sheet, with location of seismic line C-C’.
	Figure 8. Seismic Line C-C’ shows the important strike relationships of fairways and deep salt highs.

Exploration for hydrocarbons below salt in the Gulf of Mexico is not a new idea. Overhangs and shoulders on salt diapirs have been known and drilled since the 1920s. What is new however, is the concept of drilling through laterally continuous salt sheets that extend vertically and horizontally from deep feeder stocks. The subsalt play in the Gulf of Mexico has been active since the early 1980s (Moore and Brooks 1995). New techniques in seismic processing, such as 3-D prestack and poststack depth migrations, allow better imaging of the subsalt section. Advances in the geologic understanding of allochthonous salt sheet emplacement and deformation coupled with new seismic processing and drilling technology has lowered the risk of exploration below salt sheets in the Gulf.

In 1990, Exxon announced a subsalt discovery in water depths over 4300 ft deep in Mississippi Canyon block 211 named Mickey. Although this was the first discovery of the subsalt play, it was the Mahogany discovery in 1993 that sparked the play to new heights because it was the first commercial discovery (Figures 1 and 2). The field's commerciality is enhanced by its proximity to existing shelf infrastructure and moderate (370 ft) water depths.

This article discusses the regional geologic setting of the subsalt reservoirs and the relationship of depositional fairways to paleo-bathymetric geometry as a function of paleo-salt distribution (Figures 3, 4, 5, 6, 7, and 8). Integration of the regional 2-D seismic data with the much more localized 3-D prestack depth-migrated data was critical to mitigating risk for the prospect. Pressure and temperature gradients found at Mahogany were predicted from regional well control and other subsalt well analogs, and the results were generally typical of subsalt wells. The low-resistivity character of the primary target sand is due to fine laminations of sand and shale which are illustrated by Formation Micro Imaging logs and is also observed in other reservoirs deposited in deepwater environments (Shew et al., 1994, Darling and Sneider, 1993).

Location

Mahogany is on trend with Bullwinkle, Boxer, and Green Canyon 18 fields near the edge of the shelf/slope break (Figure 2). The field is below a large tabular salt sheet that converges with another salt sheet farther to the east at approximately equivalent depths. The Ewing Bank Thrust (Figure 2) is located along the leading edge of the eastern salt sheet and is one of the first thrust faults to be documented in the Gulf (Huber, 1989). Previous drilling in the Mahogany area was for seismic amplitude anomalies and structural closures above the salt, but no significant reserves were found. The Mahogany discovery was drilled about 6 miles from the southern edge of the salt sheet. Currently there are more subsalt penetrations through this salt sheet than in any other tabular salt sheet in the Gulf.

Sedimentation

Prior to the emplacement of the allochthonous salt sheets, the deep salt roots that ultimately fed the shallow salt sheets probably had local bathymetric relief updip (north) of the Mahogany area. Seismic data show that there may be several generations of salt sheets at different levels within the sedimentary column near Mahogany. For example, Green Canyon 18 field (Figures 7 and 8) is located south of the Mahogany field in a depositional fairway which loaded and deformed a salt sheet that is now buried much deeper than the Mahogany salt sheet. Geologic models of salt sheet emplacement (Fletcher et al., 1995; Wu et al., 1990) and biostratigraphic data in the study area demonstrate that the Mahogany allochthonous salt sheet probably formed within the lower bathyal to abyssal environment. Sand fairways in slope environments are primarily controlled by local and regional bathymetric variations. Basin depocenters were also variable as multiple generations of salt sheets impacted sand fairway distributions. At Mahogany, it was possible to map the older depositional fairways and extend them under the salt sheets once the deeper salt features were identified. The strike orientation of salt and basin distribution is critical to fairway prediction. After sand deposition, allochthonous salt flow at shallow depths below the sea floor was triggered and spread laterally about 8-12 miles downslope, blanketing the area.

Drilling Results

	Figure 9. Depth structure map. Mahogany is basically a faulted anticline with 3-way dip closure.
	Figure 10. Depth structure map showing location of NW-SE seismic line.
	Figure 11. NW-SE seismic line. In the dip direction, the base of the salt dives to the northwest (towards the original source of the allochthonous salt).
	Figure 12. Depth structure map showing location of NE-SW seismic line.
	Figure 13. The strike (NE-SW) seismic line shows the anticlinal closure to the southwest and the northeast. There are indications of other smaller faults which complicate the structure. The base of salt is more even and gently concave in the strike orientation.
	Figure 14. Electric log of the SS 349 #1 well, which drilled very little sand above salt, along with the pore pressures as mud weight per gallon, and temperature.
	Figure 15. SW-NE seismic line, with annotations about sedimentary inclusions within the salt, the underlying sediments, and pressure regime.
	Figure 16. Well log primarily of subsalt section. The high-pressured gumbo shales below salt is referred to as basal shear zone. The shallowest oil sand at Mahogany is the 'J' sand in the pressure transition zone; the P sand is the target interval.

The structure at Mahogany is interpreted as a 3-way dipping anticline (Figures 9, 10, 11, 12, and 13). The closure on the northwest flank may be due to faulting. Further seismic processing will aid in resolving this portion of the structure. Smaller faults have been identified in the wells which complicate the structure. The discovery well drilled in Ship Shoal 349 encountered very little sand above the salt and had suprasalt temperatures and pressures typical for the area (Figure 14). The well drilled a continuous salt section over 3500-ft thick which contained minor sedimentary inclusions, several of which exhibited oil and gas shows (Figures 14 and 15). Rotary sidewall cores were taken in the salt and analyzed for viscosity and strain rates. These data were used to help engineer casing designs and evaluate salt creep.

Although salt is an incompressible rock and therefore pore pressures are constant, the mud weight during drilling was increased in the salt interval to control the gas liberated from the sediment inclusions and also in anticipation of drilling higher pressures below the base of salt. The sedimentary section immediately below salt is a high-pressured "gumbo" with pore pressures that may exceed 17 pounds per gallon mud-weight pressure gradients (0.88 PSI/ft). The pressure gradient in this subsalt layer regresses with depth until a more regional gradient is achieved, although still geopressured (Figure 16). Salt has a high thermal conductivity and the temperature gradients within the salt are low (0.26 degree F/100 ft). There is a low temperature gradient zone below the salt, but temperature gradients gradually increase again with depth.

	Figure 17. Well log of the P sand target interval, which was flow tested by DST 1 and DST 1A.
	Figure 18. Wireline porosity logs (long-spaced sonic, litho density, and neutron) of the P sand.
	Figure 19. AIT/ sonic and MRIAN log of the P sand. Magnetic Resonance data (seen here as a MRIAN log display) can distinguish between ineffective porosity and effective porosity.
	Figure 20. Array Induction log, which is run at 1-ft resolution, and Formation Micro Imager (FMI) of P sand interval.
	Figure 21. FMI images of the P sand interval with the location of percussion sidewall cores (shown in Figure 26) and dips.
	Figure 22. FMI images of the P sand interval with the section from the lower part of the sand (shown in Figure 23) highlighted in red.
	Figure 23. Expanded FMI images, showing a close-up view of the section highlighted with red in Figure 22.
	Figure 24. FMI images of the P sand interval, with part of the section characterized by low resistivity highlighted in red; this is the interval represented by Figure 25.
	Figure 25. Expanded FMI images of the lowest resistivity section, which is an extensive sequence of ripple-laminated sand and silt.
	Figure 26. The two sidewall cores of this low-resistivity interval clearly show the scale of laminations.
	Figure 27. FMI images of P sand; highlighted interval (in red), of section higher in the section characterized by low-resistivity, shows flame structures in shale layers. Detail shown in Figure 28.
	Figure 28. Expanded FMI images of that part of the low-resistivity section containing flame structures in shale layers, ripple-laminated sands, and discrete shale laminations.
	Figure 29. FMI images of P sand interval, with highlighted section (in red) of channel and laminated sands that cap the sand. These are shown in more detail in Figure 30.
	Figure 30. Expanded FMI images of channel and laminated sands that cap the P sand.

The primary subsalt pay sand was flow tested in two stages. DST 1 from perforations of a low resistivity interval flowed 3700 BO and 550 MCFD (Figures 17, 18, and 19). Perforations at the base of the sand (from coarser, thicker bedded subunit) were then added, and the commingled flow rate was 7256 BO and 7.3 MMCFD on a 32/64" choke at 7063 PSI flowing tubing pressure (Figures 17, 18, 19, 20, and 21).

The low resistivity log response of the pay sand is due to fine interlaminations of sand and shale (Figures 20 and 21). The Formation MicroImaging log and percussion sidewall cores reveal individual sand laminae less than 0.25 in. thick; yet the overall laminated sequence is capable of significant flow rates.

Overall, the sand has a fining-upward texture with a more coarse-grained and thicker bedded layer at the base (Figures 22 and 23), overlain by an extensive rippled and highly laminated, low-resistivity sand and silt interval (Figures 24, 25, 26, 27, and 28), with channel and laminated sands at the top (Figures 29 and 30).

Development Plans

Phillips Production Company and partners Anadarko Petroleum Corporation and Amoco Production Company have drilled three oil wells at Mahogany-a straight-hole discovery well, and two directional wells are drilled-to the northeast and to the southwest. A fourth delineation well was spudded in May, 1995. Development plans include installing a platform with a production capacity of 45,000 BOPD and 100 MMCFD. First production is scheduled in December, 1996, with anticipated initial flow rate of about 22,000 BOPD and 30 MMCFD, making it the first subsalt oil development in the Gulf of Mexico.

Conclusions

Figure 31. NW-SE seismic line with position of discovery well and its log, which together provide a visual summary of the play.

The major conclusions about the Mahogany Subsalt Discovery are:

It is the first subsalt discovery on the shelf in the Gulf of Mexico. It is a faulted anticline overlain by allochthonous salt (Figure 31). Deepwater sand fairways were deposited prior to salt movement, and they extend under the salt sheets.
Subsalt reservoirs have tremendous deliverability. They are high-pressure oil sands, have high K and phi (up to 2.5 darcies and 33% porosity), and have exceptional flow rates.
Mahogany is also a case study for low-resistivity pays. Some of the pay sands encountered at Mahogany are not defined by standard wireline log suites. The pay can be resolved by Magnetic Resonance logs and imaging tools, such as the FMI. Sand and silt laminae down to 0.25” can be resolved by the FMI, but cores have laminae down to microscopic scale.

References

Darling, H.L., and R.M. Sneider, 1993, Productive low resistivity well logs of offshore Gulf of Mexico: causes and analysis, in Moore, D.C., ed., Productive low resistivity wcl110gs of the offshore Gulf of Mexico: New Orleans Geological Society and Houston Geological Society Special Publication, p. B-1 - B-26.

Fletcher, R. C., M. R. Hudec, and I. A. Watson, 1995, Salt glacier and composite sediment-salt glacier models for the emplacement and early burial of allochthonous salt sheets, in M. P. A. Jackson, D. G. Roberts, and S. Snelson, eds., Salt tectonics: a global perspective: AAPG Memoir 65, p. 77-108.

Moore, D.C., and R. Brooks, 1995. The evolving exploration of the sub-salt play in offshore Gulf of Mexico: GCAGS Transactions, v. 20. p. 20.

Huber. W.F., 1989, Ewing Bank thrust fault zone Gulf of Mexico and its relationship to salt sill emplacement: GCAGS Transactions, v. 39. p. 60-64.

Shew, R.D., D.R. Rollins, G.M. Tiller, C.J. Hackbarth, and C.D. White. 1994, Characterization and modeling of thin-bedded turbidite deposits from the Gulf of Mexico using detailed subsurface and analog data: Gulf Coast Section Society of Economic Paleontologists and Mineralogists (GCSEPM)15th Annual Research Conference. p. 327-334.

Wu, S., A.W. Bally, and C. Cramez, 1990, Allochthonous salt, structure and stratigraphy of the north-eastern Gulf of Mexico, Part II: Structure: Marine and Petroleum Geology, v. 7. p. 334-370.

Used with permission of GCSSEPM Foundation whose permission is required for further use.

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