Petroleum Geology of the Deepwater Jackfork Group and Atoka Formation With a Primer on the Petroleum Geology of Deepwater Depositional Systems

Based on a workshop presented by PTTC's Midwest Region - Michigan Satellite and the Michigan Oil and Gas Association on September 23, 2004 in Grand Rapids, Michigan.

BOTTOM LINE

Detailed illustrations and definitions on turbidite deposition and recognition of the architectural elements of turbidites demonstrated how the deep water deposits can form hydrocarbon traps. Models and examples from the Lewis Shale, Jackfork Group and Atoka Formation illustrate the complexities of interpreting stratigraphic sequences and identifying reservoirs. Specific details to look for in logs and cores, and how to correlate and use the information to distinguish between channel sands and sheet sands are discussed as critical to hydrocarbon exploration in turbidite deposits. Due to the nature of sediment influx and movement along a proximal to distal axis with stacking of deposits, turbidites are highly compartmentalized. Attention is focused on identification and interpretation of compartments and how to best produce them.

PROBLEM ADDRESSED

Deepwater depositional systems and turbidite deposits provide unique difficulties for interpretation of reservoir properties. Hydrocarbon targets in turbidites require high-resolution seismic data, extensive processing, and knowledge of the depositional characteristics of turbidity flows and the types of deposits formed (architectural elements) to identify oil and gas prospects.

KEY WORDS:

Deepwater Depositional Systems, Gravity Flow Processes, Jackfork/Atoka in Arkoma Basin, Lewis Shale in eastern Greater Green River Basin, Sequence Stratigraphy, Submarine Fan, Turbidite

SPEAKERS:

Roger M. Slatt, University of Oklahoma, School of Geology and Geophysics

James M. Forgotson, Jr., University of Oklahoma, School of Geology and Geophysics

Azzeldeen A. Saleh, University of Oklahoma, Sarkeys Energy Center
 

TECHNOLOGY OVERVIEW

Turbidites are defined geologically as clastic sediments transported beyond the shelf edge into deep water by sediment gravity flow processes and deposited on the continental slope and in the basin. In engineering terms deep water is defined at water depths greater than 1,500 ft above the mud line on the ocean floor. Stacking of individual turbidite flows forms submarine fan deposits.

The main stratigraphic elements of turbidite deposits are channels, sheets and levees. These architectural elements can be subdivided into six fine-grained deposits; canyon, channel, levee channel, overbanks, proximal and distal sheets progressing seaward from the sediment source. Log correlations through turbidites show fining up sequences with the coarsest material in the channel lag deposits. The most useful tools for reservoir characterization of turbidites are conventional logs, conceptual models, seismic reflection, outcrops, cores and borehole image logs, and computer 3-D geologic models.

Overview of deepwater (turbidite) deposits and reservoirs.
The most distal turbidite reservoirs are the sheet sands, which can spread out in layered amalgamated intervals extending across an entire basin. The sheet sands present difficulties in flow barriers and sealing potential due to the presence of laterally continuous shales separating sands.

Channel turbidite deposits have sharp erosional bases and fining up sequences that were confined within a depression on the sea floor at the time of deposition. Turbidite channel deposits have the potential for significant volumes of oil.

Levee-overbank deposits form reservoirs lateral to the main channel and without the coarser channel lag. A difficulty for seismic interpretation is that overbank deposits are highly compartmentalized and the resolution may be insufficient to differentiate the reservoirs. Because of the lack of communication between compartments, horizontal wells offer the greatest potential for recovery from multiple compartments. There may be good lateral continuity and pressure communication across proximal levee facies, but no communication between channel and level sands. Conceptual models based on outcrops, borehole images and seismic correlations can help with identification of the reservoir facies.

Levees deposits are complex with different characteristics from the proximal to the distal levee development. Proximal levee have higher net sand, are thin bedded with cut and fill features, mud-lined scours, climbing ripples, good connectivity and high angle and variable dipping beds. The distal levee has lower net sand, thin bedded, interbedded sand and silt, good continuity, and low angle ripple and the beds dip in a uniform manner. The channel margins of levees are more complex, due to slumping. Channel margins are discontinuous, mud-lined, and have variable fluid communication in channel levee reservoirs.

Channel levee and overbank examples from the Gulf of Mexico exhibit variable oil-water contacts across the reservoir. Channel areas are generally elongate, but show a characteristic "gull wing" shape in seismic profile. Correctly placed horizontal wells in proximal levee deposits are best placed parallel to the channel.

Two detailed examples of low permeability turbidite reservoirs were provided from the Upper Cretaceous Lewis Shale-Dad Sandstone in the Greater Green River Basin, and the Pennsylvanian Jackfork Group in Oklahoma and Arkansas. Both reservoirs produce gas. The Lewis Shale has both leveed channels and sheet sands. The sheet sands of the Dad Sandstone are continuous for long distances and have better permeability and porosity than channel sands that are internally complex and not continuous. The sheet and channel sands can be differentiated by borehole image logs or cores.

Stacking of deepwater elements; basics of deepwater sequence stratigraphy
The complete sea level cycle from high stand to low stand systems tract was described and illustrated. Turbidite sands and muds in deep water are very fine grained.

Complete vertical sequence of stacking patterns consists of: Sequence boundary; highstand systems tract (thin shales in deep water); transgressive systems tract (thin, organic rich or calcareous shales in deep water); prograding, complex or early lowstand wedge (mud-prone); leveed channel complex, slope fan or early lowstand wedge; sheet sandstones, basin floor fan or lowstand fan, mass transport complex; sequence boundary. Complete vertical sequences are normally not found in a single location.

Sea level changes occurring on a global scale contribute to the deposition of parts of the sequence in different areas, and aid in correlations. First-order cycles are major global events ranging up to 300 million years in duration. Second-order cycles include stacked sequences up to 30 million years. Third-order cycles are from 1-3 million years. Fourth-order progradational and retrogradational cycles occur on a basin level. Cross sections and diagrams illustrate the sequence stratigraphy of turbidite systems.

Condensed sections are represented by long time interval in which only mud and organics are deposited. This results in thick, organic-rich shale intervals composed of hemipelagic and pelagic sediments. Condensed sections are associated with maximum water depths and periods of maximum subsidence. In cores condensed sections are indicated by abundant and diverse microfossils, glauconite, phosphorite and siderite (authigenic minerals), organic debris, and high concentrations of radioactive elements such as iridium. Gamma ray logs values are generally high in condensed sections because of radioactive potassium, thorium and uranium. On electric and gamma ray logs condensed sections can be identified at the point where progradational sediments begin above staked transgressive tracts. In outcrop, condensed sections are seen at the base of prograding clinoforms, creating a broad downlap surface. This downlap pattern is visible on seismic sections and is associated with highstand system tracts. Condensed sections have additional value because they can be correlated across broad regional basins.

Geology of the Jackfork deepwater deposits with emphasis on exploration applications
The Pennsylvanian-age Jackfork Group in eastern Oklahoma and Arkansas is one of the best outcrop examples of turbidite deposition in the Midcontinent. Hydrocarbon traps types in the Jackfork show a variety of large-scale structures, fractures, stratigraphic pinchouts, unconformities, diagenetic changes, and traps associated with stratigraphically controlled fracture frequency. The well-exposed outcrops provide good correlation of the complex depositional sequences to the log profiles and aid in interpretation of the trapping mechanisms.

Production from the Jackfork is gas and once thought to be associated only with fractures. But recent studies indicate that there is no typical Jackfork production, but rather a more complex relationship between structure and stratigraphy. Diagenesis plays an important role in the Jackfork, as can be seen in close sandstone intervals exhibiting porous sandstone with matrix porosity interbedded with cemented sandstones with fracture porosity. Logs through outcrops can be correlated and lend valuable information for interpreting the lithostratigaphy of the friable sandstone versus the quartz-cemented sandstone intervals.

One problem discussed in interpreting subsurface Jackfork intervals is the ability to distinguish channel sands from sheet sands using logs. Depositional models based on outcrop and borehole image logs give a three dimensional representation to the Jackfork sediments showing source areas and formation of channel sands and sheet sandstones. The friable sandstone facies form the channel sandstones, and the cemented sandstone faces form the sheet sands. Sheet sands tend to be thinner intervals with interbedded shale and relatively good and uniform dip. Channel sandstones are thicker intervals with little shale and have relatively poor and variable dips. These compositional and cementation differences are related to depositional facies and diagenesis. In the thin sheet sands, transformation of smectite to illite within adjacent shale intervals liberates silica that migrates into the sandstone intervals and forms quartz cements. The channel sands lacking the abundant shale intervals have less clay to produce cement and thus are more friable. Application of diagenetic and stratigraphic intervals in the Jackfork related to hydrocarbon production is seen in the porosity types. Matrix porosity is in the channel sandstones and fracture porosity is found in the sheet sandstones. Gas production is associated with both.

Correlation of Atoka and Adjacent Strata within a Sequence Stratigraphic Framework, Arkoma Basin, Oklahoma (forgotson and Saleh)
The Arkoma Basin stretches from south-central Oklahoma across western Arkansas Ozark Uplift to a broad front along Cenozoic coastal plain deposits. The basin is formed by thrust faulting from the Ouachita orogenic belt. Pennsylvanian and Permian sediment infill to the basin came from the Ouachita Mountains in the south and the Ozark Uplift to the northeast. Over 30,000 wells have been drilled in the Oklahoma part of the basin, although most of the stratigraphy is modeled on the Arkansas part of the basin. Arkoma outcrops are much more prevalent in Arkansas. Shales are the dominant intervals in the Oklahoma portion of the basin, and regional lithostratigraphic and biostratigraphic markers are less common in Oklahoma than in Arkansas. To further complicate the Oklahoma section, tectonic movement and a large sediment supply were active during Atoka deposition. Detailed maps and well log correlations focused the presentation on interpretation of the sequence stratigraphic framework.

The key to correlating well logs and sequence stratigraphic concepts is to establish boundaries based on the shale packages and the conductivity patterns seen on the logs. Conductivity and sonic logs tend to show a good correlation for shale intervals. The shale boundaries can be used to track the stacked parasequence sets as they prograde or retrograde depending on the rate of sediment supply and accommodation rate (subsidence).
The Pennsylvanian Atoka section in the Arkoma Basin has two third-order sequences bounded by regional unconformities representing relative sea level changes. Sequence stratigraphic models can aid in prediction of sandstone distribution and hydrocarbon targets. The Arkoma foreland basin is a mature exploration province that still has opportunities. A better understanding of the sequence stratigraphy of the Atoka Formation in the Oklahoma portion of the Arkoma Basin can lead to increased exploration and production of oil and gas. 
 

CONNECTIONS:

University of Oklahoma
School of Geology and Geophysics and Sarkey Energy Center
100 East Boyd Street, Suite 810
Norman, OK 73019
Phone: 405-325-3253

Roger Slatt
rslatt@ou.edu

James Forgotson, Jr.
jforgot@ou.edu

Azzeldeen A. Saleh
azsaleh@ou.edu

For information on PTTC’s South Midcontinent Region and its activities contact:

Charles Mankin, Director, Oklahoma Geological Survey
100 E. Boyd St., Room N131, Norman, OK 73019-0628
Phone 405-325-3031, Fax 405-325-7069, Email cjmankin@ou.edu

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