Basin-centered gas evaluated in Dnieper-Donets basin, Donbas foldbelt, Ukraine

Nov. 23, 1998
An evaluation of thermal maturity, pore pressures, source rocks, reservoir quality, present-day temperatures, and fluid recovery data indicates the presence of a large basin-centered gas accumulation in the Dnieper-Donets basin (DDB) and Donbas foldbelt (DF) of eastern Ukraine ( Fig. 1 [122,758 bytes] ). This unconventional accumulation covers an area of at least 35,000 sq km and extends vertically through as much as 7,000 m of Carboniferous rocks. The gas accumulation is similar, in many
B.E. Law
Consulting Geologist
Lakewood, Colo.

G.F. Ulmishek, J.L. Clayton
U.S. Geological Survey

B.P. Kabyshev
Ukrainian State Geological Institute
Chernigov, Ukraine

N.T. Pashova, V.A. Krivosheya
Ukrainian State Geological Institute
Poltava, Ukraine

An evaluation of thermal maturity, pore pressures, source rocks, reservoir quality, present-day temperatures, and fluid recovery data indicates the presence of a large basin-centered gas accumulation in the Dnieper-Donets basin (DDB) and Donbas foldbelt (DF) of eastern Ukraine (Fig. 1 [122,758 bytes]).

This unconventional accumulation covers an area of at least 35,000 sq km and extends vertically through as much as 7,000 m of Carboniferous rocks. The gas accumulation is similar, in many respects, to some North American accumulations such as Elmworth in the Alberta basin of western Canada,1 the Greater Green River basin of southwestern Wyoming,2 and the Anadarko basin of Oklahoma.3

Even though rigorous assessments of the recoverable gas have not been conducted in the region, a comparison of the dimensions of the accumulation to similar accumulations in the U.S. indicates gas resources in excess of 100 tcf in place.

Basin-centered gas systems

Basin-centered gas systems, sometimes referred to as deep-basin gas, tight gas, and continuous gas accumulations, are regionally pervasive gas accumulations lacking down-dip water contacts. This type of gas accumulation typically occupies the deeper parts of a basin, is abnormally pressured, contains low-permeability reservoirs, covers hundreds or thousands of square kilometers, and may be several thousand meters thick.

In countries other than the U.S. and Canada, basin-centered gas accumulations are not well known. This report on the DDB and DF describes one of only a few such accumulations ever reported outside of North America.

Dnieper-Donets basin

Geologic setting

The DDB and DF are located in eastern Ukraine and adjoining areas of Russia (Fig. 1). A generalized stratigraphic column for these regions is shown on Fig. 2 [74,823 bytes], and regional cross-sections are shown on Fig. 3 [61,370 bytes], Fig. 4 [71,132 bytes] and Fig. 5 [85,188 bytes].

The DDB and DF regions constitute parts of a Devonian rift system that extends northwest into the Pripyat basin of Belarus and southeast into Russia. Rifting commenced in Late Devonian (Frasnian) time on a clastic platform and continued until the end of the Devonian.

The synrift sequence is poorly known because of deep burial and very few well penetrations. The synrift sequence (Fig. 2) is composed of a complex set of facies which includes shallow-water carbonates on the rift margins and inner horsts, deepwater carbonates in grabens, clastics in the southwestern marginal zone of the rift, and volcanic rocks in northwestern areas of the rift.4

In the DDB, the sequence includes two salt formations of late Frasnian and late Famennian age that form structural domes and intrusive plugs (Fig. 5). Thickness of the rift sequence is estimated at 5-6 km.5

The rifting stage was followed by intensive subsidence and the formation of a post-rift sag during Carboniferous and Early Permian time. The Carboniferous section (Fig. 2) is dominantly composed of siliciclastic rocks of alluvial, deltaic, nearshore marine, and deeper-marine facies. Most of the clastic material was deposited by a large river system flowing from the northwest, along the strike of the basin. Some carbonate beds are present on the basin margins.

In the southeastern part of the DDB and in the DF, the Upper Visean-Upper Carboniferous section is represented by a paralic series which includes coal beds, the number and thickness of which increase toward the DF where several large coal mines have been productive for decades. During Early Permian time, changes in climate resulted in deposition of red beds, carbonates, and evaporites including thick salt in the central part of the DDB (Fig. 2). Thickness of the sag sequence is 1-2 km in the extreme northwesternpart of the basin, increasing to 10-12 km or more in the southeastern part of the DDB and in the DF.

Post-rift subsidence was terminated in Artinskian time (Early Permian) by compressive stress related to collision of microcontinents (which are presently incorporated into the basement of the post-Hercynian Scythian plate) with the southern margin of the Russian craton. The compression resulted in structural inversion, thrusting, and folding in the Donbas region and uplift and partial truncation of older rocks in the southeastern DDB. The amount of truncation decreases northwestward and from the southern to the northern basin margin.

Sedimentation in the DDB resumed in Triassic time and continued into the Tertiary (Fig. 2). Although maximum thicknesses of post-rift rocks are as much as 2-2.5 km in the DDB, sedimentation occurred in platform conditions and covered areas far beyond the boundaries of the late Paleozoic rift basin. The platform sequence includes several unconformities, the most significant of which developed in pre-Paleogene time when a new pulse of compression from the south resulted in uplift and deep erosion in approximately the same areas as in pre-Triassic time.

Dnieper-Donets and Donbas basin-centered gas system

The gas accumulation in the DDB-DF is sub-divided into two parts that are coincident with the structural subdivisions of the region; an overpressured part in the deeper parts of the DDB (Fig. 6 [48,935 bytes]) and an underpressured part in the DF.

The underpressured part of the accumulation most likely extends southeastward into Russia. The top of gas-saturated rocks has not been identified with certainty because of sparse high quality pressure data. In the absence of reliable pressure data, we have attempted to use indirect data to approximate the top of the gas accumulation.

Based on basin-centered analogs in North America, the top of basin-centered gas accumulations is commonly coincident with the top of abnormally high pressure. However, in the DDB, the top of the basin-centered gas accumulation is not coincident with the top of abnormally high pressure; the depth to the top of regional overpressuring in the DDB is shown on Fig. 6.

Instead, the top of the basin-centered gas accumulation occurs well below the top of overpressure and is more closely associated with a vitrinite reflectance value of 0.9% or present-day temperatures of about 100° C. For comparisons of the top of overpressure to iso-lines of 0.9% Ro and 100° C., we have superimposed the top of abnormal pressure, 0.9% isoreflectance, and 100° C. isothermal lines on cross sections A-C (Figs. 3-5).

In our judgment, the 0.9% isoreflectance is a conservative estimate of the top of the gas accumulation, while the 100° C. isotherm may be viewed as an optimistic choice. Pressure and fluid recovery data from several wells indicate that a 0.9% Ro isoreflectance value is well within the gas accumulation. Alternatively, observations of overpressured basin-centered gas accumulations in the U.S. have shown that the tops of active hydrocarbon generating, basin-centered gas systems occur at temperatures of about 100° C. The coincidence between active hydrocarbon generation and a present-day temperature of approximately 100° C. assumes close stratigraphic proximity (probably less than 300 m) to viable source rocks, thereby requiring short migration distances from source to reservoir.

The inability to better define the top of the gas accumulation based on indirect methods may be due to multiple causes of abnormal pressure and the presence of a good evaporite seal in Permian rocks. In the North American examples cited previously, hydrocarbon generation is the dominant cause of abnormal pressure. In the DDB, abnormally high pressures may have originally been caused by a mechanism such as compaction disequilibrium sealed by Permian evaporites.

As the Carboniferous coal-bearing rocks continued to subside, they became thermally mature with respect to hydrocarbon generation and large volumes of hydrocarbons were contributed to the pore system, forceably expelling mobile, gas-saturated water into overlying lower-pressured rocks, thereby supplanting the earlier overpressuring mechanism of compaction disequilibrium. In such a case, Permian evaporites would serve as an effective seal for the mildly overpressured gas-saturated pore water and the top of the moderate to highly overpressured gas-saturated basin-centered accumulation would occur below the top of regional overpressuring.

In contrast to the DDB, the underpressured, Carboniferous rocks in the DF are in a state of thermal disequilibrium. That is, present-day temperatures are insufficient to account for the observed levels of thermal maturity, indicating that paleo-temperatures were significantly higher than present-day temperatures. Because of this thermal disequilibrium state, indirect methods of determining the top of the gas accumulation are not applicable, and no analogs exist to identify the top of the gas accumulation.

Pressure and pore fluid data from a well in the northern part of the DF indicates the top of the gas accumulation occurs at a vitrinite reflectance of about 0.75%. The top of underpressuring in this well occurs at a depth of about 1,500 m, and drillstem tests below this depth recovered gas with no water. Core plugs taken below the top of underpressuring indicate the presence of very low permeability sandstone reservoirs. In other parts of the DF, pressure data indicate the top of the gas accumulation may be as shallow as 1,000 m.


Gas reservoirs in the basin-centered accumulation are mainly Carboniferous sandstones deposited in fluvial, deltaic, and marine environments. We conservatively estimate the amount of sandstone in the gas-bearing interval at about 30%.

Core plug analyses of sandstone reservoirs in the DDB indicate porosity ranges from 5-19% and permeability ranges from 0.04 to 115 md. Porosity and permeability values in the DF are lower than those in the DDB. Natural fractures have significantly enhanced reservoir properties.

A cursory examination of Carboniferous sandstone reservoirs from some of the abandoned gas fields in the DDB deeper than 4.5 km reveal that most of those fields produced from unstimulated reservoirs with surprisingly good porosity and permeability, suggestive of the development of regionally good quality reservoirs. In contrast, Carboniferous reservoirs in the DF have very low porosities and permeabilities even though they occur at considerably shallower depths than in the DDB.

Source rocks

The principal source rocks in the DDB are Upper Devonian and Lower Carboniferous (Visean) black shales containing as much as 3 to 13% total organic carbon (TOC), respectively. Organic matter contained in both of these source rock intervals is predominantly gas-generating (Type III) with secondary amounts of oil-prone material (Type II) as indicated by Rock-Eval Hydrogen Indexes consistently less than about 300 mg hydrocarbons/g TOC. Although there are no source rock analyses available from Middle Carboniferous rocks, coals and carbonaceous shales are also likely sources of gas in both the DDB and DF. Levels of thermal maturity in Carboniferous rocks are generally high throughout the basin (Figs. 3-5).


We suggest that the seal for the basin-centered gas accumulation is different from the regional top of overpressuring shown on Figs. 3-6. The regional top of overpressuring in the DDB is within or below Permian rocks (Figs. 3-5). Permian age salt beds are the most likely seals for the regional overpressuring in the DDB.

Although seals in basin-centered gas accumulations may be coincident with lithologic boundaries, they are most often not associated with lithologic seals such as shales or evaporites. In the specific case of the DDB, the top of the gas accumulation is not coincident with the regional top of overpressuring.

In basin-centered gas accumulations in North America, it is generally believed that the presence of two or more fluid phases in low-permeability reservoirs provide an effective permeability barrier to gas and is sometimes referred to as a capillary or relative permeability seal.6 7 Because capillary seals are independent of structure or stratigraphy, the tops of basin-centered gas accumulations often cut across structural and stratigraphic boundaries. Within the gas accumulations, however, the presence of more conventional lithologic seals can reinforce entrapment of gas.


The DDB and DF contain large amounts of gas (in excess of 100 tcf in place) in regionally pervasive, low-permeability Carboniferous reservoirs referred to here as a basin-centered gas accumulation. However, more detailed work is required to determine the quality of reservoirs and the spatial boundaries of the accumulation. Following those tasks, "sweet spots" or areas of enhanced reservoir development need to be determined.


The authors are grateful for the cooperation and contribution of information from the Ukranian State Committee on Geology and Utilization of Mineral Resources. This work was funded by the U.S. Agency for International Development. Comments and suggestions by T.S. Dyman and V.F. Nuccio greatly improved the manuscript.


  1. Masters, J.A., Elmworth-Case study of a deep basin gas field, AAPG Memoir 38, 1984, 316 p.
  2. Law, B.E., Relationships of source-rock, thermal maturity, and overpressuring to gas generation and occurrence in low-permeability Upper Cretaceous rocks, Greater Green River Basin, Wyoming, Colorado, and Utah, in Woodward, J., Meissner, F.F., and Clayton, J.L., eds., Hydrocarbon source rocks of the greater Rocky Mountain region, Rocky Mountain Association of Geologists, 1984, pp. 469-490.
  3. Law, B.E., and Spencer, C.W., Gas in tight reservoirs-An emerging major source of energy, in Howell, D.G., ed., The future of energy gases: U.S. Geological Survey Professional Paper 1570, 1993, pp. 233-252.
  4. Ulmishek, G.F., Bogino, V.A., Keller, M.B., and Poznyakevich, Z.L, Structure, stratigraphy, and petroleum geology of the Pripyat and Dnieper-Donets basins, Belarus and Ukraine, in Landon, S.M., ed., Interior Rift basins, AAPG Memoir 59, 1994, pp. 125-156.
  5. Kabyshev, B.P., Paleotectonic studies and petroleum productivity in aulocogens (Paleotektonicheskiye issledovaniya i neftegazonosnost v avlakogennykh oblastyakh), Leningrad, Nedra, 1987, 192 p.
  6. Jennings, J.B., Capillary pressure techniques: Application to exploration and development geology, AAPG Bull., Vol. 71, 1987, pp. 1,196-1,209.
  7. Watts, N.L., Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns, Marine and Petroleum Geology, Vol. 4, 1987, pp. 274-307.

The Author

Ben E. Law is a consulting petroleum geologist in Lakewood, Colo. Previously, he was employed as a research geologist with the U.S. Geological Survey in Denver, where he devoted over 20 years investigating unconventional gas systems in the U.S., Canada, Russia, and Ukraine. He has been the editor of USGS and AAPG special publications focusing on coalbed methane, basin-centered gas accumulations, and abnormal pressures. He received BS and MS degrees in geology from San Diego State University. E-mail: [email protected]
Gregory F. Ulmishek is a research geologist with the USGS in Denver. He immigrated to the U.S. in 1980 and was employed by Argonne National Laboratory until 1987, when he joined the USGS. He is a member of the USGS World Energy Resources Program, where he has studied petroleum basins in the C.I.S., China, and Arctic. He received an MS degree in geology from the Moscow Petroleum Institute and a PhD from the Institute of Geology and Exploration for Fossil Fuels, Moscow.
Jerry L. Clayton is a research geochemist with the USGS in Denver. His main research interests are applications of organic geochemistry in basin analysis and petroleum exploration, geochemistry of sulfur, and environmental effects of petroleum occurrence. He has conducted research in Hungary, Poland, Russia, Belarus, Ukraine, and China, as well as the U.S. He received BS and MA degrees in geology from the University of Missouri and a PhD degree in organic geochemistry from Colorado School of Mines, Golden, Colo.
Boris P. Kabyshev is director of the Chernigov Branch of the Ukrainian State Geological Institute. His main scientific interests are in the study of regularities of formation and distribution of oil and gas fields. He received an MS degree in geology from Lvov Polytechnical Institute, Lvov, Ukraine, where his major was, "Geology and exploration for oil and gas fields.

" He successfully defended PhD and Doctor of Sciences theses.

Natalia T. Pashova is a senior research geologist with the Ukrainian State Geological Institute in Poltava, Ukraine. She has spent her entire career in Ukraine. Prior to her present position, she worked in the exploration enterprise Poltavaneftegazgeologia, then the Ukrainian Research Institute for Gas. Her main scientific interests are in structural geology and tectonics. She graduated with an MS from the Dnepropetrovsk Institute of Mines, Ukraine, where her major was geophysical methods of exploration.
Valery A. Krivosheya is a senior researcher with the Ukrainian State Geological Institute, Poltava, Ukraine. Previously, he worked for the exploration enterprise Poltavaneftegazgeologia, conducting gas exploration in Ukraine. His main scientific interests are reservoir geology and geochemistry. He received an MS degree in geology from Kharkov State University, Kharkov, Ukraine. He successfully defended his PhD thesis.

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