Horizontal drilling and fracturing have been the keys which have unlocked vast oil reserves in North Dakota’s Bakken Shale and Texas’s Eagle Ford Shale. The success companies have achieved while developing those two formations has led to the search for other shale formations with similar geological characteristics. Enter stage left: the Tuscaloosa Marine Shale (TMS) which is a similar geological age to the Eagle Ford Shale. The formation is deep, with depths ranging from 11,000’ to 15,000’, but contains plus 90% oil cuts and is prospective for economic quantities of oil in Louisiana and Mississippi (see map below). Depths combined with low permeability in the TMS had previously dissuaded companies from developing the formation, but new technologies have led companies like Encana (NYSE:ECA), Devon (NYSE:DVN) and Goodrich (NYSE:GDP) to explore the area with 21st century drilling techniques in their toolboxes.
Tuscaloosa Marine Shale Map
Source: LSU-Basin Research Institute.
The LSU-Basin Research Institute estimates the TMS contains seven billion barrels of oil reserves (unclear whether this is recoverable or oil-in-place) and spans eight million acres as shown by the highlighted band above. Oil generation over-pressurized the formation in this band which has led to natural fracturing and increased permeability in certain zones. The TMS refers to three different zones, the Upper Tuscaloosa (sand and shale), the Marine Shale and the Lower Tuscaloosa (sand and shale). Until recently, the only well in the TMS was the Winfred Blades #1 well completed by Texas Pacific Oil Company in 1978. This well was drilled in Tangipahoa Parish in Louisiana (Parish=County in Louisiana) and has recovered 20 thousand barrels of oil to date.
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TMS Stratigraphic Map
Source: Devon Energy.
The Tuscaloosa Marine Shale has several advantages over other shale plays, including no severance tax on hydrocarbons recovered using horizontal wells in Louisiana for two years or until cost of well has been recovered and close proximity to the St. James terminal located on the Gulf Coast of Louisiana. Crude oil sold to the St. James terminal has received a premium to WTI ranging from $10 to $20 during 2012 because the U.S. crude that reaches this terminal (most is currently sold at other terminals due to transportation costs) competes with higher priced Brent crude which is imported at St. James. While this premium is currently an advantage for the play, expect it to decline as more U.S. oil from the Eagle Ford and the TMS is sold at St. James.
Disadvantages for the TMS are that it’s a high-cost, unproven play. The high costs stem not only from its depth (deeper than both the Bakken and the Eagle Ford) and low permeability, but from complexities due to the thin layer from which natural fracturing (thus increased permeability) exists. GDP is a micro-cap that is currently delineating its acreage in the TMS with four to five wells scheduled to be completed during the remainder of 2013. In its third quarter earnings transcript, Goodrich revealed that the TMS zone which has natural fracturing is only ten feet thick. This thin layer has led to issues with wellbore stability and resulted in well costs ranging from $14 to $16 million. The company believes it's making progress with this issue and expects well costs to decrease to around $12 million per well for wells completed with a 7,500’ lateral and 25 stage frac.
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High resistivity in the TMS encouraged ECA and DVN to explore the play, with ECA drilling the first modern well in Amite County, Mississippi in 2007. While this well has only recovered 35 thousand barrels of oil (MBbls) to date, the company has been more successful with its recent wells by tweaking its completion techniques to add more frac stages.
Its Weyerhaeuser 73H-1, spudded in August, 2011 in Saint Helena Parish, was completed with 17-frac stages and produced at a 30-day IP rate of 770 BOEPD (94% oil). The company has achieved similar success with three wells in Southern Mississippi (North of the shoelaces on Louisiana's boot), Horseshoe Hill 10H-1, Anderson 17H-1 and Anderson 18H-1 which achieved average 30-day IP rates of 695, 933 and 1,072 BOEPD, respectively. The company will maintain its focus in Southern Mississippi, where it has 11 wells either drilling or permitted according to the Mississippi State Oil & Gas Board.
Encana's TMS Results
Note: The above results were calculated by The Energy Harbinger using data provided by the States of Louisiana and Mississippi. Data may differ from company reported figures, specifically in Louisiana where monthly production was assumed to be 30 days as the state doesn't report the amount of days a well produced in a month. For this reason, production may be understated.
Devon's activity is focused across the boarder in Louisiana where its Weyerhaeuser 14H-1 in Saint Helena Parish produced at an average 30-day rate of 695 BOEPD (93% oil). DVA’s other TMS wells include two drilled in the Tangipahoa Parish, the Soterra 6H-1 (completed in October, 2011) and the Thomas 38H-1 (completed during Q3’12), which produced at average 30-day IP rates of 176 BOEPD and 470 BOEPD, respectively. The company completed four wells in the East Feliciana Parish during 2011 and 2012 with average 30-day IP rates ranging from 1 BOEPD to 285 BOEPD.
Devon's TMS Results
Note: The above results were calculated by The Energy Harbinger using data provided by the States of Louisiana and Mississippi. Data may differ from company reported figures, specifically in Louisiana where monthly production was assumed to be 30 days as the state doesn't report the amount of days a well produced in a month. For this reason, production may be understated.
While I would hesitate to put too much stock into these early results, ECA's results in Amite County Mississippi are the largest and most consistent of the early wells drilled in the TMS. Its Anderson 18H-1 well, mentioned above, has produced a Bakken like 85,454 barrels of oil durings its first 141 days of production. At $95 oil (LLS currently in $105 range), this well would have grossed $5.8 million during this time period. Now these wells are running expensive (ECA's target wells cost is ~$14 million), but the early production results look robust. If ECA can get its costs down, it may have a lot of oil on its hands. Production from Louisiana's Saint Helena Parish also looks strong, with both companies completing wells averaging more than 600 Bbls per day during their peak 30 days.
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At a $12 million well cost, GDP believes EURs will need to be in the 350 MBOE range for the play to be economic. It’s worth noting that DVN is targeting EURs at 400-600 MBOE (90% oil) which corresponds to an average 30-day IP rate of 700 to 900 BOEPD, whereas ECA revealed on its investor day that it has drilled several wells which it expects to recover hydrocarbons near its target EUR of 730 MBOE (see table below). While these target EURs are more than what GDP believes it will take to make the TMS economic, I caution that neither company has drilled many wells in the formation which makes it difficult to determine how large the play could be. To that end, Halcon Resources (HK) is currently drilling a well in the Western part of the play in Rapides Parish, LA which should provide some intuition on play size.
Results over the near-term of this play will be important to pay attention to as they will be a catalyst for the companies involved. The company-wide production cuts for its first movers, Encana, Devon and Goodrich, contained 6%, 37% and 23% oil, respectively, during the three months ended September 30, 2012. One thing we do know about the TMS is that it's oily meaning that it could provide all three of these companies a significant amount of oil reserves which will improve cash flows, reserve quality and valuations for each. Below is a table describing each company's position in the play.
TMS Position by Operator
By. Braden Holt
