Arkoma basin

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Figure 1: The location of Woodford field in Arkoma basin and other famous formations in North America.
Figure 2: Locations of Arkoma basin and other basins in Oklahoma

The Arkoma Basin is a peripheral foreland basin found in Southeastern Oklahoma and the central portion of Arkansas as seen in Figure 1. "The basin is an east-west trending topographic and structural depression that covers an area of approximately 33,800 square miles."[1] The maximum length of the province is about 315 mi, east-west, and the maximum width is about 175 mi, north-south.[2] It is adjacent to the Ouachita Mountains found just south of the basin.

Geological History

During the early Mississippian and ending in the middle Pennsylvanian the Arkoma basin developed through the collision of the North American and Gondwanan plates.[3] The Arkoma basin is a peripheral foreland basin and is adjacent to the Ouachita fold and thrust belt. The Ouachita fold and thrust belt is a major influence on the sedimentary and structural history of the Arkoma basin.

The compressional environment of the basin developed many normal and thrust faults. The basin developed through periods of shallow-water marine and coastal plain environments. The trough of the Arkoma basin was a high area in the early Mississippian and began to subside through the Mississippian and Middle Pennsylvanian and sedimentation continued until the Late Pennsylvanian.[4] The Ouachita mountain uplift during the Des Moines Epoch closed off the southeast end of the basin from the sea and created a vast swamp. The Permian movement then caused the folding, faulting, and compaction of these sediments. Simultaneously the Ozark dome was re-elevated and caused beds to tilt and major block faulting to occur. The combined forces of these geological events have created a complex network of faults, folding, and thrusting of beds throughout the basin.

Deposition

Deposition of the sediments in the Arkoma Basin occurred primarily in the Middle Pennsylvanian and records the history of the subsidence, filling, and nature of the shelf environment.[3] The deposition that occurred is divided into three different stages.

The latest stage consists of fluvial-deltaic sediments that were deposited during the DesMoinesian and Upper Atokan. Examples of these sediments are the Hartshorne formation and Booch sandstones.

The next stage occurred during the middle Atokan and is primarily made of deep-water clastic. The Red Oak sandstone is an example of a reservoir in this stage.

The oldest stage of sediments is related to the subsidence of the basin and occurred in a shallow-water marine environment. The Atokan Spiro sandstone and Morrowan Wapanucka Limestone are examples of producing units in this stage.

Petroleum System Elements

The Arkoma Basin has been known for its hydrocarbon presence for well over 100 years. In fact, the first successful gas well was drilled in Mansfield Arkansas in March of 1902. Since then, it has continued to be a large producer of natural gas. In 1987, Houseknecht stated that “The Arkoma is one of the most prolific gas producing basins in the United States.”[5] This statement was made nearly 20 years before the horizontal drilling boom was spearheaded in the Woodford Shale in Oklahoma and the Fayetteville Shale in Arkansas. The horizontal wells with the advanced hydraulic fracking techniques have increased the gas production in the Arkoma Basin exponentially.

Reservoir

The Arkoma Basin contains many producing reservoirs. In fact, there were roughly 25 known gas producing zones within the basin as far back as 1966. Most all the production from these reservoirs has been natural gas. One of the earlier reservoirs exploited for hydrocarbons was the sandstone found in the Atoka Formation. Although multiple zones or reservoirs could be of interest, they pale in comparison to the gas producing potential of the 2 largest. Based off a 2010 assessment done by the USGS, more than 26 trillion cubic feet of gas (TCFG) can be found in two shale gas formations. The Devonian-Mississippian Woodford Shale and its lateral equivalent the Chattanooga Shale contain roughly 12.3 TCFG and the Mississippian Fayetteville Shale with its laterally equivalent Caney Shale containing roughly 14.3 TCFG. Figures 3 and 4 outlines the areas of the shale plays with their lateral equivalents.

Figure : Shale plays in Oklahoma.
Figure : Shale plays in Oklahoma.

Source

The most prolific source rocks found in the Arkoma Basin are of the Devonian and Mississippian age. The Woodford and Chattanooga formations are from the Devonian age and contain total organic concentrations (TOC) ranging from 2.0 to 12.5 percent. The Fayetteville and Caney formations are from the Mississippian age and have a TOC concentration range of 0.17 to 9.5 percent.  

Migration

The migrating path the hydrocarbons took within the Arkoma Basin are one of the reasons the largest fields were found first. Coleman states that “The preponderance of vertical hydrocarbon migration paths in a system of both high-angle normal faults and low-angle thrust faults has led to a highly efficient discovery process.”[6]

Current future assessment of the Arkoma Basin and its EOR

Just as a remind we learn that, the history of Arkoma Basin and Ouachita tectonic belt hydrocarbon exploration and development started with coal and asphaltite. Early drilling for oil and gas focused on surface anticlines.

The Arkoma Basin is a peripheral foreland basin. A foreland basin is a physical basin that develops analogous to a mountain belt. Foreland basins is due to the huge mass formed by crustal clotting. The foreland basin receives sediment that is eroded from the mountain belt.

Figure 5: definition of fordeep

According to Rutty, P., Schlaefer, J., & Antonio, V. As present day, Red Oak field, located in the Arkoma basin of Eastern Oklahoma, produces 200 Mmcfd of gas under pressure depletion drive with 2.6 TCF of gas recoverable. [7]The basin flank is characterized by rapid subsidence and deposition of over 20,000 feet (6000 m) of shallow to deep marine shale and stacked sandstone. This is also known as the foredeep basin system. the sedimentary and structural history of the Arkoma Basin feature is closely related to that of the Ouachita fold-and-thrust belt. on current day, several evaluations have been implemented to locate the O/G: AVO, seismic interpretation, anticline, fault. In 1902. First natural gas discovered in Arkoma Basin near Mansfield, Arkansas due to anticline exploration. And 1959. Paper by Dan Busch on Pennsylvanian delta deposits, Inc. Booch in Arkoma Basin for deep oil drilling. 1985 – 1988. Infill drilling of Red Oak Field by Amoco[8].

The future assessment is favorable due to implementation of 3D seismic survey, Wireline logs.

This allow geologist to map the amplitude change base on high-gamma ray (HGR) log. this implementation and innovation further help in application of EOR (enhance oil recovery). 3D seismic was done and the result of the survey greatly varied[7]. the satisfaction of this work is due to that the survey reveals extra target for many drilling spots. shale present in formation characterize the unconventional reservoir. In unconventional reservoir, the evaluation of among of hydrocarbon existence is quiet not possible. New experimental and methodology provides the mapping of EUR density and study the vitrine reflectance[9].

Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean volumes of 38 trillion cubic feet (TCF) of undiscovered natural gas, 159 million barrels of natural gas liquid (MMBNGL), and no oil in accumulations of 0.5 million barrels (MMBO) or larger in the Arkoma Basin Province and related areas. More than 97 percent of the undiscovered gas occurs in continuous accumulations-70 percent in shale gas formations, 18 percent in a basin-centered accumulation with tight sandstone reservoirs, and 9 percent in coal beds. Less than 3 percent of the natural gas occurs in conventional accumulations.

For future assessment, in 2009, The independent Potential Gas Committee acknowledged growth in the nation’s available gas resource. Then last summer, when it issued a resource-based estimate of 1,836 trillion cubic feet – highest in the committee’s 44-year history. The result for the research backing huge undiscoverable resource in Arkoma basin.

on the EOR level, we must first develop the matter of EOR. The Oil recovery can be separated into three phases: primary, secondary and tertiary. Primary oil recovery is restricted to hydrocarbons that naturally rise to the surface, or those that implement artificial lift devices, such as pump jacks.

Figure 6: Introduction of CO2 in an injection well for EOR.

The Secondary recovery employs water and gas injection, displacing the oil and driving it to the surface. Here we can add that, according to the US Department of Energy, utilizing these two methods of production can leave up to 75% of the oil in the well. This then led to the application of tertiary factor. We note here that on conventional reservoir one of the methods use in EOR in the introduction of co2 in the well to bust the bottom hole pressure and rise of flow rate in production.

The application of EOR methods are very costly. For this, it requires higher cost for production. The price of oil combine with the lake or poor infrastructure does not legitimize the investment at all time. 

In Arkoma basin, the enhanced oil recovery (EOR) emphasis on mostly tight sandstones, several studies were done, and all depends on the type on tight sand group (the Hoxbar Group of rocks in the southern Oklahoma, The Pennsylvanian (Missourian) Hoxbar Group). In the Anadarko Basin the Hoxbar Group (e.g., Marchand sandstone) has been a prolific producer of oil and gas.

For this work we will have to dispose strong knowledge on sedimentology, reservoir quality, sequence stratigraphy, geochemistry, geomechanical rock properties and integrated depositional and diagenetic evaluation of the tight sandstones applied to EOR.

Figure 7: Introduction of horizontal wells in the Arkoma Basin

Reservoir heterogeneity and mineralogy are important components used to evaluate EOR. Enhance method of exploration in Arkoma basin are well study but poorly publicized. Then difficulties to find document related to technical knowledge (information). Here we site couple different seminar that have been done over the time. The revolution and the implementation of horizontal wells have mostly started in 1990 and continue to present.

1988. First production of CBM. Hartshorne coal, Kinta Field

1996. Potato Hills Gas Field “rediscovered” by GHK No. 1-33 Ratcliff in sub- (mid-level) thrust Jackfork Ss.

2004. First shale gas development from Woodford Sh in Pittsburg, Hughes Counties

2012. is the meeting that lead to this publication cited 

2019. another a seminar and workshop were open to study the Arkoma basin to participate you can click here register to workshop.

For future exploration the implementation is going over in Arkoma Basin: ● Woodford Shale development ● middle Atoka Fm. sandstone facies ● transition-zone structure to east ● organic shales in middle Atoka Fm[10]

On the chart below, we can observe the production with the implementation of horizontal well and the vertical well that had been there at the beginning. Today new technique are putting into place for more production combine with the production in newly discover site.

Primary geological risk

Formation in Akoma basin has various values of horizontal stresses and horizontal stresses are much larger than vertical stresses. This is because of historical tectonic movements that causes Arkoma basin to be bounded by the Ouachita overthrust belt to the south and by the Ozark uplift to the north. Tectonic movements result in a series of anticlines and synclines trending from east to west and also causes non unified but stronger horizontal stresses[11].

Figure 10: Breakdown pressure with minimum horizontal stresses data.

However, for shale formation with horizontal wells, the strong contract between horizontal stresses can causes problems for well completion and well simulation. If well is placed in shale interval or inside shale formation and there are large differences between horizontal stresses, completion and simulation tasks can results in undesirable outcome. For example, the targeting sand is bounded by shale layers and completion is conducted in shale interval. If there are large horizontal stress contract between target sand and shale, then the bounding shale will act like barrier to increase injection rate of fracturing fluid and decrease the width of fracture so reduce the ability to place proppants inside fractures[11] .

As a result, there are great uncertainty of where well completion and stimulation should be conducted. The uncertainties is estimated by the range of maximum horizontal stresses to ensure effective hydraulic fracturing. First, by using drilling tests data such as Leak of Test (LOT) data to obtain breakdown pressures and minimum horizontal stresses.  It is realized that breakdown pressure decreases if there is a large difference between horizontal stresses and increases if horizontal pressures are similar. As the result shown in Figure 10, the ratio of breakdown pressure to minimum horizontal stresses is extremely small as 1.108. This indicate there are large differences between horizontal stresses [11].

In real cases, there are failures that are caused by large contract of horizontal stresses. For instance, in Figure 9, Arkoma basin had a time when production met failure and resulted in 40% completion efficiency. The reason of low production efficiency is caused by high injection pressure rate and early screen out during fracturing.

Figure 9: Efficiency was as low as 40% at early years of developing

As shown in the Figure 11, near wellbore pressure and perforation friction are extreme high: average of these pressures is 25000 psi and the maximum reaches 40,000 psi. High injection rate resulted in high near wellbore pressure and perforation friction can be caused by differences of horizontal stress between shale and targeting sands[12].

However, engineers solves these potential issue by developing technologies. The methods to solve these problems includes[12]:

Sacrifice fractures: fractures fracked by little or no proppant.

Reactive fluids: they are used before each fracturing stage and Arkoma basin usually react more with HCl/HF acid.

Foamed-cement completion.

Slow rate increases during the stage.

Linear gel for > 0.75 lbm/gal: it provide enough viscosity to increase density of proppants.

Perf and spacing revision.

Figure 11:

Geological uncertainties and risks

Figure 8: BP developed Performance Indicator map to study and identify variation among wells.

Arkoma basin is heavily drilled and high risks areas are left for later oil and gas exploration. For example, the areas where poor reservoir characteristics such as low porosity, low permeability and high thermal maturity, and fragmented structures created by thrust fault and normal fault. This lead to lots of uncertainties in subsurface geological environment and may causes troubles.

For example, in Woodford shale of Arkoma basin, different wells have reportedly variety of issues, and the main causes for these issues were dominantly geological rather than mechanical or operational. However, companies, such as BP, have developed method called Well Performance Indicator(PI) to identify variations existed among different wells. As shown in Figure 8, different color represent different characteristics of each well. A indicator map made by PI tool can indicate the well that is out of norm. Often, indicator map suggests geological variation contributes to well variations and issues more than technological factors[13].

High fracturing in Arkoma basin is one of risks. Fractures can prevent sealing capacity and prevent production. Fragmented structures can also prevent seismic to obtain a clear imagine of the trap beneath it.[11] But in recent years, 3D seismic has helped improving well completion by reducing errors in subsurface. For example, 3D seismic decreases risk of intersection with faults and drilling out of target zone[12].

It is easy for Woodford shale to create complex fractures when fracture treatment. It can result in problems in cementing and precaution is needed. For example, minimum amount of cement should be entering the fractures around well bore and to reduce matrix integrity to clean cement that entered fractures. Also, cement should insulate fluid flow from well bore or into well bore to prevent lost circulating and kick and father to prevent well blowout[14].

References

[15]
[16]
[17]

  1. McGilvery, T. A., Manger, W. L., and Zachry, D. L., 2016 Summary and Guidebook to the Depositional and Tectonic History of the Carboniferous Succession Northwest Arkansas. Guidebook, AAPG Mid- Continent Field Conference, September 30-October 2, 2016 Fayetteville, Arkansas.
  2. Perry, William J., Jr. "ARKOMA BASIN PROVINCE (062). " https://certmapper.cr.usgs.gov/data/noga95/prov62/text/prov62.pdf
  3. 3.0 3.1 Suneson, Neil H. “Arkoma Basin Petroleum - Past, Present, and Future.” Oklahoma Geological Survey, Oklahoma Geological Survey, 2012, www.ogs.ou.edu/geology/pdf/neilarkomabasinshaleshake.pdf
  4. Branan, C. B., Jr. "Natural Gas in Arkoma Basin of Oklahoma and Arkansas" In Natural Gases of North America vol 2. (AAPG, 1968), 1616-1635, http://archives.datapages.com/data/specpubs/fieldst1/images/a008/a0080001/1600/16160.pdf, AAPG
  5. Houseknecht, D.W., 1987, The Atoka Formation of the Arkoma basin--tectonics, sedimentology, thermal maturity, sandstone petrology: Tulsa Geological Society, Short Course Notes
  6. http://ogs.ou.edu/docs/circulars/C112B.pdf
  7. 7.0 7.1 Rutty, P., Schlaefer, J., & Antonio, V. Exploitation utilizing 3D seismic in the Red Oak gas field of the Arkoma Basin, Oklahoma. United States.
  8. Neil H. Suneson. (2012, March). Oklahoma Geological Survey Oklahoma City Geological Society & Oklahoma Geological Survey Geology Workshop March 7, 2012. Retrieved from http://ogs.ou.edu/MEETINGS/Presentations/OilGasMar2012/SunesonArkOuach.pdf
  9. Ricardo A. Olea, D.W. Houseknecht, C.P. Garrity, and T.A. Cook Formulation of a correlated variables methodology for assessment of continuous gas resources with an application to the Woodford play, Arkoma Basin, eastern Oklahoma
  10. Neil H. Suneson. (2012, March). Oklahoma Geological Survey Oklahoma City Geological Society & Oklahoma Geological Survey Geology Workshop March 7, 2012. Retrieved from http://ogs.ou.edu/MEETINGS/Presentations/OilGasMar2012/SunesonArkOuach.pdf
  11. Britt, L. K., & Smith, M. B. (2009, January 1). Horizontal Well Completion, Stimulation Optimization, and Risk Mitigation. Society of Petroleum Engineers. doi:10.2118/125526-MS
  12. 12.0 12.1 Grieser, W. V. (2011, January 1). Oklahoma Woodford Shale: Completion Trends and Production Outcomes from Three Basins. Society of Petroleum Engineers. doi:10.2118/139813-MS
  13. Carragher, P. M., Diehr, T., & French, S. (2013, November 11). Technology Advances in the Understanding of Reservoir Performance in the Woodford Shale Gas Field, Arkoma Basin, USA. Society of Petroleum Engineers. doi:10.2118/167093-MS
  14. Nelson, S. G., & Huff, C. D. (2009, January 1). Horizontal Woodford Shale Completion Cementing Practices in the Arkoma Basin, Southeast Oklahoma: A Case History. Society of Petroleum Engineers. doi:10.2118/120474-MS
  15. Whaley, J., 2017, Oil in the Heart of South America, https://www.geoexpro.com/articles/2017/10/oil-in-the-heart-of-south-america], accessed November 15, 2021.
  16. Wiens, F., 1995, Phanerozoic Tectonics and Sedimentation of The Chaco Basin, Paraguay. Its Hydrocarbon Potential: Geoconsultores, 2-27, accessed November 15, 2021; https://www.researchgate.net/publication/281348744_Phanerozoic_tectonics_and_sedimentation_in_the_Chaco_Basin_of_Paraguay_with_comments_on_hydrocarbon_potential
  17. Alfredo, Carlos, and Clebsch Kuhn. “The Geological Evolution of the Paraguayan Chaco.” TTU DSpace Home. Texas Tech University, August 1, 1991. https://ttu-ir.tdl.org/handle/2346/9214?show=full.