Elusive Alabama shales need more work, Energen says

Mushwad is an acronym for malleable unctuous shale, weak-layer accretion in a ductile duplex. After the ductal Conasauga shale was deposited in Cambrian time, Richardson explained, it “acted as a lubricant that allowed the overlying strata to break and thrust upward as they glide on top of the shale. The shale is piled up against basement ramps and becomes thousands of feet thick.”

Energen acquired and reprocessed more than 1,000 miles of 2D seismic to enhance the mushwad signature and gained enough comfort to drill some distance from Big Canoe Creek field.

Marchant 22-16 had eight strong shows at 6,500-12,400 ft, and the companies attempted to complete the deepest and most notable, at 11,525-730 ft.

The Conasauga is a carbonate-dominated sequence of interbedded shales and carbonates alternating every few inches to every few feet, Richardson said.

“There is nothing like the Conasauga anywhere in the country; it is a different kind of formation,” he said.

A Sept. 15 frac at 11,558-723 ft contained 165,000 gal of crosslinked gel and 220,000 lb of sand and resulted in a disappointing flow of less than 50 Mcfd despite strong mud log shows.

This suggested that the completion technique didn’t work but could be the result of the geologic complexity of the mushwad, Richardson said.

“Our theory is that hydraulic fracturing may not be effective in forming a conduit to enhance the production from a zone that is so broken and deformed. If so, the question is, does this apply to all of the mushwad or is it a localized occurrence?

“Our thought is to hydraulically stimulate one or more of the additional zones of interest in this well. If they do not yield satisfactory results, we may consider lateral drillouts in order to contact more of the gas-bearing rock,” Richardson said.

From 3,000 to 4,000 ft the same well encountered a zone “that was not waded, had very low dip rates, and had slightly higher shale content than the lower strata that was ultimately completed.

“This very thick zone at a shallow depth may offer some potential in the future in a more traditional geologic setting,” Richardson said.

Chattanooga shale

The Chattanooga shale has long been of interest in Alabama because it appeared rich in organics but was usually only 25-40 ft thick.

Energen and Chesapeake recognized the existence of a subbasin along the Appalachian thrust with the potential for encountering intervals of the Devonian age Chattanooga shale that were 100 ft thick or more, Richardson said.

The Lamb 1-3H No. 1, in 1-23n-3e, Greene County, was spud June 2 and drilled with mud. It cut 93 gross and 91 net ft in Chattanooga at 9,150 ft. The 91 net ft refers to that portion of the gross interval that had a gamma ray of 150 or more API units.

“We also encountered Floyd shale at 8,954 ft and several Pennsylvanian aged sands from 6,000-8,000 ft,” he said.

Circulation was lost in several formations at 4,500-5,500 ft, making detailed analysis of most of these zones difficult.

“We were unable to obtain a complete logging suite or a full core.” The incomplete core implied encouraging values of porosity at less than 4% and permeability a bit above 200 nanodarcies, Richardson said.

The companies gained enough encouragement to proceed with a horizontal leg, but it encountered a fault. They kicked off at 9,150 ft and drilled a 2,035-ft lateral in the Chattanooga shale and ran a four-stage frac totaling 2 million gal of slick water and 2 million lb of sand starting Oct. 30.

After recovering 50% of the frac fluids, no significant gas flow was recorded.

“We expected to see significant gas flows much earlier in the process. That we did not calls into question the completion design or the productivity of the shale itself,” Richardson said.

“Our assessment at this point is that we will likely drill and complete an additional well in a different geographic setting. Hopefully this will encounter fewer lost circulation problems and be in a better position to evaluate the Chattanooga and Pennsylvanian sands potential.

“We also anticipate testing different completion and stimulation designs. For example, after analyzing data gathered to date, we think that using an energized fluid such as nitrogen in our stimulation may be less reactive with the shale than slick water and could yield a positive result.”

Chattanooga thrust/Floyd

The original concept with the Krout well was a mushwad-type formation to the south and east of the main Conasauga play. The Krout 10-14 No. 1, in 10-22n-9e, Bibb County, was spud on Jan. 26.

“We found instead a thrust system that repeated the Chattanooga and Floyd sections,” Richardson said. “This formation gave the appearance of a mushwad on seismic due to the tectonic activity. It is very structurally complex, overturned, and thrusted with highly dipping formations.”

Mud logs from the Krout and Goodson wells 1 mile apart depict greatly different geologic conditions.

The Krout mud log shows five Chattanooga sections and an abnormally thick Floyd section.

“It appears that the Floyd section has been overturned on itself and has a gross thickness of more than 400 ft with a net thickness of 158 ft as measured by gamma ray of more than 150 API units.”

The companies attempted completion in the Lower Chattanooga at 8,210-50 ft and 8,300-90 ft. This zone had 130 ft of net Chattanooga shale.

A hydraulic frac on Oct. 8 with 200,000 gal of cross-linked gel and slick water and 150,000 lb of sand yielded a disappointing flow of less than 50 Mcfd.

“Therefore,” Richardson said, “we have no plans for future Chattanooga shale completions in this play, but we do plan to evaluate the abnormally thick Floyd that we encountered.”

Arawak Energy Ltd., Jersey, Channel Islands, UK, reduced oil production at Akzhar, Besbolek, Karataikyz, and Alimbai fields in Kazakhstan Dec. 5 in connection with high taxes and export duties and the drop in oil prices.

After authorities imposed a customs export duty, Arawak and other small producers began offering oil for sale locally and those prices fell to below the cost of production.

Arawak cut output to the minimum levels needed to maintain processing facilities. Production from the nonoperated Saigak field, governed by a production sharing agreement, is not affected.

Arawak expected net production to drop to less than 2,000 b/d from 13,700 b/d in mid-November after a five-rig development drilling program in Akzhar and Besbolek fields.

Santos International Holding Pty. Ltd. has committed to Phase 2 of its five-block exploration program in Kyrgyzstan as a farmee of Manas Petroleum Corp., Baar, Switzerland.

Santos completed the first phase, spending $10 million for geological studies and reprocessing and shooting seismic surveys. It will drill three exploration and three appraisal wells in phase two, spending up to $7 million/well.

Circle Oil PLC said its CGD-9 exploration well on the 296 sq km Sebou Permit in Morocco’s Rharb basin northeast of Rabat sustained 8.86 MMcfd of gas from the Lower Guebbas formation. The discovery will undergo an extended well test, and the company plans to further assess the resource. The rig has moved to the KSR-8 well, third of a planned six-well program. Circle has 75% working interest, and Morocco’s ONHYM has 25%.

Meanwhile, on the Ouled N’Zala concession the ONZ-6 discovery that sustained 3.32 MMcfd is likely to be commercial, and ONZ-4 is on continuous production at 1.5 MMcfd.

Richards Oil & Gas Ltd., Calgary, is starting up a 75% owned processing plant and compressor to handle gas at Thorsby, Alta., southwest of Edmonton.

Nine standing wells are to be connected. The company has drilled 18 wells to date, including five in the quarter ended Sept. 30 targeting Horseshoe Canyon coals and Edmonton sands. Initial flow rates at the five were 200 Mcfd to more than 800 Mcfd/well. The plant is designed for low inlet pressure to maximize CBM production. Regulatory approval to commingle is being sought.

The company, which owns 88% working interest in more than 23 sections, believes the property has net production potential of 9-12 MMcfd.

Callon Petroleum Co., Natchez, Miss., suspended development of its 50% owned Entrada field in 4,650 ft of water on Garden Banks Block 782 in the deepwater Gulf of Mexico.

The company cited costs much higher than expected to date and commodity prices that have fallen to less than half their levels when development began in mid-2008.

Callon said the No. 3 well, drilled to 21,100 ft, needs to be sidetracked toward the No. 2 discovery well. It said it does not anticipate returning to the project under current economic conditions. Callon had expected Entrada to go on production in mid-2009.

CIECO Energy (US) Ltd., a subsidiary of Tokyo-based ITOCHU Corp., owns the other 50% interest in Entrada.

Royale Energy Inc., San Diego, plans to acquire 75% interest in more than 1,000 acres in what is believed to be a southern extension of North Tejon oil and gas field in the San Joaquin basin.

Royale will operate and fund the future development of the field in 35 and 36-11n-20w, Kern County, Calif.

It will attempt to recomplete the Windgap 42-36 well in Oligocene Vedder sandstone. Drilled in 2006, it cut two potential pay zones, the lower of which had virgin pressure and strong oil and gas shows, and flared gas while testing.

Royale Energy and Laris Oil & Gas LLC, Littleton, Colo., believe a freshwater mud system damaged the reservoir. Oil based drilling fluid was used to develop the rest of the field. Royale will drill short laterals. Then the companies plan continuous drilling on the 1,000 acres held by Laris.

East

Meridian Resource Corp., Houston, said its latest completion in the East Texas Austin chalk flowed at the rate of 18.6 MMcfd of gas and 2,800 b/d of oil with 1,300 psi flowing tubing pressure while still cleaning up.

The Sutton A-574 No. 1 in Polk County went to vertical TD of 12,200 ft and has 5,200-ft and 6,500-ft laterals in the chalk. The company’s working interest is 63%.

The rig has moved to drill the dual lateral BSM A-278 No. 1 well, and the dual lateral BSM 507 No. 2 is being completed.