The Mississippian Lime: America’s Next Big Resource Play
 

The Mississippian Lime, located in South-central Kansas and North-central Oklahoma, is a shallow carbonate play (mostly Limestone) with depths ranging from 3,000 feet to 6,000 feet. The Lime is not a new play, but an old producing field with more than 30 years of production and 14k vertical wells drilled. It’s now being redeveloped using horizontal drilling and fracking techniques, and in that respect, could be compared to the Permian Basin of West Texas. While conventional production in the play stemmed from the “Mississippian Chat,” a reservoir with high porosity and permeability above the Lime, new development is targeting the tighter Mississippian Lime that lies underneath the Chat. The formation was subject to weathering and digenesis and erosion at the regional unconformity. This results in greatly varying reservoir properties both horizontal and vertically. Where the digenesis and weathering have enhanced the reservoir properties, the porosity is generally 15-20 per cent and can be more than 100 feet thick. Where it has not been enhanced, the porosity is only 4-6 percent and has low permeability. This results in lateral discontinuous reservoirs that are ideally developed with horizontal drilling technology.

The Lime is shallower than the Bakken and Eagle Ford, companies use smaller drilling rigs and cheaper proppants, which has led to drilling and completion costs between $3 and $3.5 million, less than half of what an operator would pay in the Bakken or Eagle Ford. The play is estimated to span 17 million acres with oil in place estimates ranging from 5.4 to 5.9 billion barrels of oil equivalent (BBOE). An intelligent discussion on the Mississippian Lime can’t be had without talking about Sandridge, which has drilled 382 horizontal wells, or 44% of the total horizontal wells drilled in the play. The company has amassed 1.7 million net acres in the Lime, from which it expects to generate estimated ultimate recoveries (EURs) of 456 thousand barrels of oil equivalent (MBOE) per well.

The Mississippian is by far the cheapest formation to produce from with respect to the peer group. The Mississippian is a play that produces more hydrocarbons per dollar with the main negative being a lower oil cut. Despite its lower oil cut, an average rate of return of 119%, a rate that has plenty of natural gas pricing upside. The Lime also gets oilier as you move from East-to-West, and several wells in Alfalfa County, Oklahoma with 30-day production rates in excess of 2,000 BOEPD (90%+ oil cut). So while it’s a gassier oil play than some would like, oil cuts vary and returns are high. These numbers aren’t going unnoticed by the oil and gas industry, but have prompted industry titans such as Chesapeake Energy, Apache, Devon Energy, Encana and Repsol to accumulate large acreage positions in the play.

 


National Oil and Gas Resource Assessment in 1995, conducted by the U.S. Geological Survey and the Minerals Management Service, has focused on assessing the undiscovered conventional and unconventional resources of crude oil and natural gas in the United States. This assessment includes for the first time a systematic resource appraisal of the in-place natural gas hydrate resources of the United States onshore and offshore regions.This gas hydrate assessment is also unique to this study in the sense that it is the only energy resource assessed that is reported as an in-place resource estimate without regards to its recoverability.

Gas hydrates are crystalline substances composed of water and gas, in which a solid water-lattice accommodates gas molecules in a cage-like structure, or clathrate. Gas hydrates are widespread in permafrost regions and beneath the sea in sediment of outer continental margins. The amount of methane sequestered in gas hydrates is probably enormous, but estimates of the amounts are speculative and range over three orders-of- magnitude, from about 100,000 to 270,000,000 trillion cubic feet. The estimated amount of gas in the hydrate reservoirs of the world greatly exceeds the volume of known conventional gas reserves.

The major goal of this resource appraisal is to estimate the gas hydrate resources in the United States, both onshore and offshore. This appraisal of gas hydrates is based on a play-analysis scheme, which was conducted on a province-by-province basis. The gas hydrate-plays in the United States are regardless of their current economic or technological status. In a play analysis method, prospects (potential hydrocarbon accumulations) are grouped according to their geologic characteristics into plays.

11 gas-hydrate plays were identified within four offshore and one onshore petroleum provinces; for each play. Estimates for each of the 11 plays were aggregated to produce the estimate of total gas hydrate resources in the United States. The offshore petroleum provinces assessed consist of the U.S. Exclusive Economic Zone (EEZ) adjacent to the lower 48 States and Alaska. The only onshore province assessed was the North Slope of Alaska, which included State water areas and some offshore Federal waters. The provinces are geographic in character; however, their formation represents an attempt to group the individual petroleum provinces along broad geologic lines.

 


 

The Cline Shale in Texas is one of the hottest new shale plays in the USA. Devon Energy (DVN) is suggesting it’s a huge play, pervasive over a very large area on the eastern shelf of the Permian Basin. Several new resource plays in the Permian are being "unleashed," and that there are so many multiple horizons or formations that are stacked on top of each other in the Permian-that are just now being accessed with horizontal drilling-that it’s like having 10 or 11 EagleFord shales stacked on top of each other.

Devon got the market’s attention earlier in April when they said they had staked over 500,000 acres and had an unrisked 3.6 billion barrels of oil there. Devon gave a “type curve” for a Cline Shale well—a guess at how much the well would produce over time—of total production 570,000 barrels of oil equivalent—and 85% of that would be oil and liquid rich gas. The well would flow an average 600 boe/d for the first month and cost $6.5 million.

The Cline is organic rich shale, with Total Organic Content (TOC) of 1-8%, with silt and sand beds mixed in. It’s about 60-150 metres (200-550 feet) thick. Contrast that to the Bakken where the payzone is often only 10-25 m thick. It lies in a broad shelf, with minimal relief (that means it lies nice and flat), and it’s in the “oil window” (a depth where the right temperature and pressure allow the ancient organic matter to turn into oil—gas is below oil) and has nice light oil of 38-42 gravity with excellent porosity of 6-12%. So there are lots of holes in the rock containing oil, but all those holes aren’t well connected, meaning it has low permeability. That is normal in these tight oil plays. And there are frack barriers above and below the shale—rock types that are really hard and would likely halt any fracturing beyond the Cline—this is important because it means that water will not likely be able to come into the well (and water supersedes oil in coming back up the well—most of the time it’s a real negative) from other formations.

Technically, the Cline Shale—also called the Lower Wolfcamp formation—looks like a great play. And because it’s in the Permian Basin, services like drilling rigs and fracking spreads are inexpensive and easy to access. The Permian Basin is already one of the most prolific oil areas in North America, producing 35 billion barrels from multiple zones. But now there are even more zones, but they’re all “tight oil.”