McMoRan sees Davy Jones find revitalizing much of gulf shelf

Jan. 25, 2010
An apparent Eocene-Paleocene discovery just off the central Louisiana coast could eventually produce 2 tcf of gas or more from Wilcox, appears to have shallower Eocene pay, and is being deepened to test more of the Paleocene section, said McMoRan Exploration Co., New Orleans.

An apparent Eocene-Paleocene discovery just off the central Louisiana coast could eventually produce 2 tcf of gas or more from Wilcox, appears to have shallower Eocene pay, and is being deepened to test more of the Paleocene section, said McMoRan Exploration Co., New Orleans.

McMoRan cautioned that flow tests and confirmation drilling are needed to identify the content of liquids, if any, in the hydrocarbons and the areal extent of the Wilcox sands, but it hailed the Davy Jones well as an important data point in overall Gulf Coast/Gulf of Mexico exploration.

The Davy Jones well, in 20 ft of water 10 miles south of Marsh Island, La., is about 85 miles south of the nearest deep Wilcox production to the north in the 30-year-old Cretaceous Tuscaloosa Trend just north of Baton Rouge and 170 miles north of Lower Tertiary discoveries such as Shenandoah in the Walker Ridge area of the deepwater Gulf of Mexico.

The apparent pay in Wilcox below the salt weld is a "great signal" that operators might also encounter Tuscaloosa sands if they drilled even deeper on the shelf, said James R. Moffett, cochairman. In the deepwater gulf discoveries, sands are thicker in the Lower Wilcox than in the Upper Wilcox, Moffett noted.

McMoRan, leader of a group of five entities with interests in four federal blocks that the shallow-water discovery appears on seismic data to cover, said the Davy Jones well could revive exploration on a broad area of the Gulf of Mexico shelf. It could be one of the largest shelf discoveries in decades (OGJ Online, Jan. 11, 2010).

Davy Jones progress

The McMoRan group had drilled the Davy Jones exploratory well to 28,262 ft by Jan. 11 and run logs to 28,134 ft.

The Rowan Mississippi jackup is drilling the well, and McMoRan has an option on its sister rig, Rowan Ralph Coffman.

Pipe-conveyed wireline logs indicate 135 net ft of hydrocarbon bearing sands in four zones in Eocene-Paleocene Wilcox, all of them full to base. Two zones have a combined 90 net ft of apparent pay.

Logs indicate porosity in excess of 20% and 10-20 ohms of resistivity, the best of any sands McMoRan has seen in the Wilcox, Moffett said.

The high resistivity suggests the hydrocarbons will be gaseous with low water saturation, and hydrogen sulfide and carbon dioxide are possible if not likely. Advanced well design handled the problems of producing high pressure-high temperature Jurassic gas in Mobile Bay in the 1980s, he noted.

The presence of condensate and gas liquids is unproven, but McMoRan has obtained as much as 100 bbl/MMcf from some Miocene wells, Moffett said.

The quality of the Wilcox sands "assures us…that we're just a mirror image of what's going on out in the Shenandoah-Kaskida-Tiber Wilcox trend" in the deepwater gulf, he said.

"If development drilling confirms what we see on seismic, which is one big uniform structure that covers 20,000 acres…this is going to be a huge reserve and significant to the entire strike and dip sections in the shallow-water shelf," he said.

If present, Tuscaloosa sands would be below the Davy Jones well's projected total depth of 29,000 ft.

Moffett said, "The whole landscape of the subsurface geology of the shelf has been reshaped."

The logs also indicated more than 400 ft of multiple porous sand intervals in the Yegua/Sparta interval of the shallower Eocene, McMoRan said. Logs indicate porosity as high as 24%, a record for a Yegua sand, Moffett said.

The group is considering whether to attempt rotary or sidewall cores at the discovery well.

Shelf implications

McMoRan envisions the shelf extent of the Eocene depositional fairway, sourced from areas in and north of the present-day Atchafalaya Basin, at 19,000 sq miles: from shore to the northern Garden Banks and Green Canyon areas and from easternmost Texas waters to western Mississippi Canyon.

Results from Davy Jones and the Blackbeard West exploratory well about 90 miles east-southeast on South Timbalier Block 168 brighten the outlook for ultradeep hydrocarbon potential on 200-300 sq miles of gulf shelf, Moffett said.

A McMoRan group drilled Blackbeard West to 32,997 ft. Permitted to 35,000 ft, it logged four potential hydrocarbon-bearing zones in Miocene Rob-L below 30,067 ft. The group is considering whether to run production tests, which require specialized equipment, or deepen the well to the Wilcox (OGJ Online, Oct. 24, 2008).

These two wells are the only ultradeep control points on the vast shelf, on which thousands of wells have been drilled to unlock the potential of the shallower Miocene and Plio-Pleistocene sections, Moffett pointed out.

McMoRan topped Wilcox at 26,000 ft at Davy Jones and expects to encounter it below 34,000 ft at Blackbeard West, he said.

McMoRan groups have 12-13 other drill-ready Wilcox prospects below the salt weld plus 15-20 prospects and several leads above the salt weld in what it calls the Flat Rock-JB Mountain-Blueberry Hill minibasin, which encompasses more than 200,000 acres roughly between the two wells.

The prospects aren't necessarily contiguous because geologic frameworks are different above and below the salt.

The company controls 150,000 acres associated with ultradeep gulf shelf exploration.

Most of the 12-13 subsalt prospects would have Miocene and Wilcox potential, although some farther south would have less chance for Tuscaloosa potential, Moffett said.

Moffett said, "We envision a very busy 3 years on the exploration side and the development side of Davy Jones, Blackbeard, and other discoveries we hope to make."

Moffett also noted that the Tuscaloosa penetrated north of Baton Rouge in the 1970s-80s had much better sand quality than the Wilcox. Tuscaloosa had thicknesses of 300-500 ft and less fine material.

Testing and completion

The individual Wilcox sands in the Davy Jones well appear more like twins than brothers on gamma ray, resistivity, and porosity profiles and therefore might not require separate tests, Moffett said.

The Davy Jones well is toward the east flank of the structure, and probably 7,000-10,000 of the 20,000-acre structure is updip from the well.

Moffett said McMoRan should be able to drill development wells at Davy Jones for $100 million/well plus $50-75 million for completion.

Cost so far at the apparent discovery well exceed $70 million, including $15 million for logging. Six logging attempts were needed before the group got the right combination of drillpipe-conveyed logs and tools that had enough resistence to temperature and pressure, Moffett said.

Larger diameter holes will be needed at development wells to accommodate larger tubing to handle expected flow rates of 100-125 MMcfd and ultimate recovery of at least 100 bcf/well, he said. Formation tests of Wilcox at the discovery well are probably at least a year away.

A conventional platform will likely serve as a central production facility.

McMoRan operates the Davy Jones prospect and is funding 25.7% of the exploratory costs. It holds a 32.7% working interest and 25.9% net revenue interest.

Other working interest owners include Plains Exploration & Production Co. 27.7%, Energy XXI Bermuda Ltd. 15.8%, Nippon Oil Exploration USA Ltd. 12%, W.A. "Tex" Moncrief Jr. 8.8%, and a private investor 3%.

Energy XXI is funding 14.1% of the exploratory costs to earn its 12.6% net revenue interest in the prospect.


Victoria Oil & Gas PLC, London, encountered overpressured shale gas in a thick interval at an appraisal well in undeveloped Logbaba gas-condensate field on the outskirts of Douala, Cameroon.

The La-105 well went to TD 8,920 ft and also cut more than 300 ft of gross pay in multiple gas-bearing sands at virgin pressures at 6,017 ft to 8,330 ft. The sands can be correlated to those found and tested decades ago in the La-103 well, which flowed at rates of 5-12 MMcfd from individual sands.

After drilling the La-106 well, the company plans to build a gas processing plant. The field's pay intervals are in Upper Cretaceous Logbaba sands. Victoria Oil & Gas ran a passive seismic survey over the field in 2009.


GeoPark Holdings Ltd., Hamilton, Bermuda, plans a 14-16 well program in 2010 on Chile's Fell block at a cost of more than $50 million that follows the nine wells drilled and completed in 2009.

The Dicky-16 well is to be tested, while the Alakaluf-5 downdip appraisal well flowed 650 b/d of oil with 250 psi wellhead pressure on a 14-mm choke from a 43-ft perforated interval in Cretaceous Springhill at 7,173 ft.

GeoPark Holdings, which is moving the rig to drill Alakaluf-6, will also shoot 2D and 3D seismic and expand infrastructure in 2010. Its certified proved and probable reserves are 42.2 million bbl of oil equivalent.


Northern Petroleum PLC launched a 3D seismic survey on four licenses in the West Sicily thrust belt off Italy.

Shooting of as much as 1,520 sq km on the G.R17.NP, G.R20.NP, G.R21.NP, and G.R22.NP licenses in the next 2 months is part of the work program funded by Shell Italia E&P SPA under a farmout announced in December 2008.

The survey aims to obtain a better quality and more complete definition of the encouraging structures identified from two previous 2D seismic shoots and firm up prospects for drilling.


Namibia's state NAMCOR has been appointed by the Block 1711 Joint Operating Committee as interim operator, succeeding Sintezneftegaz Namibia Ltd.

Sintezneftegaz Namibia has transferred its interest in the 2.2 million acre block to Nakor Investments Ltd., a company affiliated with the Sintezneftegaz/Sintez Group of the Russian Federation.

EnerGulf Resources Inc., Houston, said it anticipates that the geophysics-geology work program required to evaluate Kunene-1 well data and correlate the data to existing 2D and 3D seismic should start soon (OGJ Online, July 23, 2009).


Polish Oil & Gas Co. will join Aurelian Oil & Gas PLC in exploring Aurelian's six exploration concessions in Poland's western Carpathians.

Aurelian will continue as operator, and PGNiG will gain a 40% participating interest in Karpaty West and 20% in Karpaty East that cover 2,230 sq km and 1,296 sq km, respectively.

Aurelian will reprocess and interpret 2,000 line-km of seismic provided by PGNiG, which is expected to lead to shooting new seismic in the second half of 2010.

Aurelian now partners with PGNiG in more than one third of the Polish Carpathian fold belt, where modern seismic and similar technologies have yet to be fully deployed.

PGNiG operates the Bieszczady blocks covering 3,547 sq km in Poland's eastern Carpathians, in which Aurelian has 25% interest.


ProspEx Resources Ltd., Calgary, gauged a sharply higher gas-condensate flow rate at its second horizontal multifrac well in the East Kakwa area of the Alberta Deep Basin.

The second well, at 15-19-64-4w6m, produced up casing at a final rate of 24.4 MMcfd of gas on a 38-hr test at 1,570 psi flowing wellhead pressure. It flowed up tubing at the rate of 16 MMcfd at 1,690 psi.

The first well, at 2-33-63-4w6m, made 10.9 MMcfd at 2,380 psi on a cleanup test and 6.6 MMcfd at 2,300 psi on extended test last September. On production since early November, it averaged a facility-restricted 7.8 MMcfd net to ProspEx's 60% working interest including associated liquids.

ProspEx expects to finish drilling a third horizontal well by late January 2010. The 15-19 and 2-33 wells are 8 km apart, and the third horizontal well will extend the trend 5 km farther north. ProspEx didn't identify the formation, but the area produces from five Cretaceous zones including Falher channels at 2,400-2,600 m true vertical depth.


S&W Oil & Gas LLC, private Wichita operator, tested the 24-1 Double H discovery well in southwestern Ford County, Kan., at 240 b/d, 75-98% oil, and 150-200 Mcfd of associated gas from Pennsylvanian Morrow sand.

The Rooney project area totals 7,040 acres adjacent to the north edge of existing Morrow sand oil and gas production 20 miles south of Dodge City, said interest owner American Petro-Hunter Inc., Scottsdale, Ariz.

The two companies negotiated an unspecified premium to the Kansas common oil price for the 44° gravity oil from National Cooperative Refinery Association, McPherson, Kan., American Petro-Hunter said.


Five operators submitted more than $128 million in bids for six tracts in five Pennsylvania state forests in the Marcellus shale gas play.

The high bidders are Seneca Resources Corp., Anadarko Petroleum Corp., Exco Resources Inc., Penn Virginia Corp., and Chesapeake Energy Corp. Bids ranged from $2,437/acre to $5,250/acre and averaged $4,100/acre.

The tracts total 32,000 acres in north-central Pennsylvania in Elk, Moshannon, Sproul, Susquehannock, and Tioga state forests.



Forest Oil Corp. plans to run four rigs in the eastern Texas Panhandle in 2010, where its third and fourth operated horizontal Pennsylvanian Granite Wash wells exceeded expectations.

The third well tested at a 24-hr rate of 15.1 MMcfd of gas, 1,200 b/d of oil and condensate, and 2,400 b/d of natural gas liquids in December 2009. The fourth well made 16 MMcfd, 1,300 b/d, and 2,200 b/d in January 2010.

Forest drilled 4,200-ft legs and ran 9-10 frac stages. Well costs are expected to improve from the averaged $6.8 million for the two wells. The Granite Wash acreage is in Roberts, Hemphill, and Wheeler counties.

More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on