STRATIGRAPHIC CHARTS and well logs presented here describe the subsurface in Bulgaria, the Chaco-Parana basin of eastern Paraguay, the Turgay basin of Kazakhstan, Tanzania, the Holbrook basin of eastern Arizona, and the Indus basin off Pakistan.
Bulgaria
All producing fields in Bulgaria lie in the Moesian platform and Forebalkan areas.
The country`s fields produced 267,000 bbl of oil and 1.52 bcf during 1996. Output is declining. Production peaked in 1980 at 2.4 million bbl of oil and 6.7 bcf of gas for the year.
Bulgaria covers about 110,000 sq km and extends westward from the Black Sea, north of Greece and Turkey and south of Romania. Exploration began in 1936 with three wells drilled at Varna near the Black Sea coast. They were noncommercial.
Eight discoveries and almost as many noncommercial finds have been made since 1947, according to information from the Committee of Geology and Mineral Resources, Council of Ministers, Sofia. Targets are oil and gas in Middle Triassic carbonates, gas in Upper Triassic carbonates, oil in Upper Triassic clastics, oil and gas in Lower Jurassic clastics, oil in Upper Jurassic-Lower Cretaceous carbonates, and gas in Paleogene clastics (Fig. 1).
Here are the commercial fields:
Tyulenovo, 19° gravity oil from Lower Cretaceous.
Dolnni Dabnik, 42° gravity oil from Middle Triassic.
Gorni Dabnik, 40° gravity oil from Middle Triassic.
Chiren, gas and 63° gravity condensate from Lower and Middle Triassic and Lower Jurassic.
Devetaki, gas and 56° gravity condensate from Middle Triassic.
Dolni Lucovit, 40° gravity oil from Lower Jurassic.
Aglen, gas and 57° condensate from Triassic.
Butan, gas and 51° gravity condensate from Lower Jurassic.
Noncommercial oil and gas finds included Bardarski Geran, Marinov Geran, and Staroseltzi. Uneconomic gas finds came at Kriva Bara and Bazovetz.
Eight licenses and joint operating agreements resulted from a 1989 bidding round in which more than 18 oil companies bid. They included six Black Sea shelf blocks and two onshore blocks. More than 10,000 km of new seismic data were acquired and 10 wildcats were drilled during the next 5 years.
Texaco, Enterprise Oil, and OMV of Austria announced the Galata gas discovery 20 miles southeast of Varna on Block 3 in August 1993. It flowed 30 MMcfd of gas from 3,400 ft. The well went to 8,700 ft in 115 ft of water. It was uncertain when this gas might reach market, but one Bulgarian source indicated it would be tied in during 1998.
The country was preparing to launch a third licensing round at the end of 1997 or early in 1998. The round was to include 12 onshore blocks in the northern half of the country from the western border to the Black Sea, and possibly several offshore blocks.
Chaco-Parana basin, Paraguay
This landlocked South American country, which has never produced oil or gas commercially, finds itself near the crossroads of major hydrocarbon projects.
The country is sandwiched between Bolivia, Brazil, and Argentina. A major natural gas pipeline from constrained Bolivian gas fields to hungry Brazilian gas markets will pass north of Paraguay.
Adair International Oil & Gas Inc., Houston, held the only concessions in Paraguay at this writing in late 1997. The San Pedro and Alto Parana blocks cover a combined 21,000 sq miles in southeastern Paraguay. Adair`s holding took effect May 30, 1997. Spectrum Oil Corp., Bakersfield, Calif., previously held the blocks but was unable to meet farmout obligations.
Previous operators by 1997 had recorded about 15,000 km of seismic data and drilled 47 wildcats since 1945 in the ParaguayanChaco-Parana basin. Byron R. Ayme, a Bakersfield consulting geologist and geophysicist, reported that 16 of those had oil shows.
Distribution of the shows was three in Ordovician-Silurian, 11 in Devonian, four in Permo-Carboniferous, and one in Cretaceous. Six wells had gas shows: three in Ordovician-Silurian, seven in Devonian, and five in Carboniferous. Three deep wells have been drilled on the two blocks, all with oil shows, and four wildcats in the Brazil side of the basin flowed gas from Permo-Carboniferous sandstones.
The Chaco-Parana basin covers most of Paraguay and part of Brazil, Uruguay, Argentina, and Bolivia. The main reservoirs (Fig. 2) are the Cariy sandstones of Silurian/Llandoverian to Ludlovian age and the Santa Elena sandstones of Devonian/Pragian age with porosities of 6-9% and 9-19%, respectively; Coronel Oviedo channelsandsofPermo-Carboniferous/ Stephanian to Sakmarian age with porosities of 12-22%; and the San Miguel deltaic-fluvialsandstonesofPermian/ Saskmarian to Kungurian age with 20-23% porosities.
The oil window in the western Parana basin is at 6,500-14,750 ft. The section is normally pressured, and migration from source to reservoir is assumed to be lateral or vertical.
The main pay zones are expected to be the Cariy and Santa Elena sandstones sourced by Silurian/Sakmarian Llandoverian Vargas Pena shales. Secondary but equally important pay zones are the Permo-Carboniferous channel sands sourced by the Lima shales. The third pay zone is the San Miguel formation sourced by either San Miguel or Tacuary shales.
Turgay basin, Kazakhstan
The Turgay sineclise in central Kazakhstan covers about 140,000 sq km, some 60,000 sq km of which is favorable for oil and gas.
The area`s first oil and gas field, Kumkol, was discovered in 1984. The other fields include Maybulak,Aryskum, Kyzylkiya,Nuraly,Aksay, Konus, Bektas, and Akshabulak. All of the discoveries are in the Aryskum downwarp.
Western interests in the area are growing. RWE-DEA AG and Erdol-Erdgas Gommern GmbH, a joint venture of Gaz de France and Bayernwerk AG, secured a $106.7 million loan in late 1997 to develop Akshabulak oil field. They foresee a $320 million stage development.
Production was to start in mid-1998 and continue 20 years from reserves estimated at 110 million bbl. Crude was to be shipped 800 km to the Kazak refinery in Chimkent. That oil would be swapped for a similar volume produced in western Kazakhstan and shipped through Russia, Belarus, and Poland for refining in Germany.
A Calgary company, Hurricane Hydrocarbons Ltd., acquired Kazakhstan`s Yuzhneftegaz in the closing days of 1996 for $120 million. That organization produced about 50,000 b/d of oil from Kumkol field and had 317 million bbl of proved and probable reserves. Hurricane has a further 23 million bbl of reserves in the country through its interest in the Turan petroleum project, a joint venture that holds rights to Kizyl-Kiya, Aryskum, and Maybulak fields and the South Kumkol exploration area.
V.I. Korchagin, V.I. Karpov, and I.V. Puzanova described Turgay`s oil and gas potential in an article in Geologiya Nefti i Gaza No. 5 in 1996, reprinted in Petroleum Geology.
They wrote that three oil and gas bearing complexes are recognized at Turgay: Middle Jurassic, Upper Jurassic, and Lower Neocomian (Fig. 3).
The Middle Jurassic complex consists of interbedded sandstone, siltstone, and clays with thickness up to 90 m. Upper Jurassic is composed of sandstone, siltstone, and clays less than 100 m thick. The Lower Neocomian clastic complex is represented by alternating members of sandstone, siltstone, and clay. It is host to two productive horizons. Thickness of this complex does not exceed 30 m.
About three fourths of Turgay petroleum resources are in the Jurassic complexes, and about one fourth is in the lower Neocomian. Depth to pay is generally no more than 8,200-9,800 ft.
In the north of the Turgay downwarp oil shows have been recorded in Upper Devonian-Carboniferous carbonates. Noncommercial flows or films of oil were found in Carboniferous sediments during drilling of 13 wells in the Shcherbakov, Lesnoy, Ospanov, and Silant`yev areas. Novonezhin well 119 yielded 1.5 tons of oil from Visean limestone.
Early explorers quickly evaluated the anticlines, so the main thrust of exploration is now for stratigraphic and fault traps in the border zone of the graben-synclines and in structural saddles.
Tanzania basins
Tanzania has been explored for hydrocarbons on and off since 1952, but it will likely be late 1998 before the country`s first sustained hydrocarbon production begins.
Three offshore wells and two wells are slated to produce a combined 60-70 MMcfd of gas from Lower Cretaceous at about 6,000 ft at Songo Songo Island off the Rufiji River delta. A 230 km pipeline will transport the gas from processing plants on the island north to industrial plants in Dar es Salaam.
The only other indicated discovery is Mnazi Bay-1, a 1982 gas discovery in Oligocene sands just offshore near the border with Mozambique. Unappraised, it is judged to contain reserves of about 1 tcf of gas, about the same size as Songo Songo.
Tanzania contains a string of coastal, mostly onshore basins-from north to south the Ruvu basin, Dar-es-Salaam platform, Rufiji trough, Mandawa basin, and Ruvuma basin-and the Selous basin of the interior. The Coastal Basin complex consists of the offshore-onshore Pemba and Zanzibar basins north of Dar es Salaam and the Mafia basin just south of the city.
Only about 32 wells have been drilled in Tanzania.
Tanzania Petroleum Development Corp. says the stratigraphic evolution of the Ruvu basin in the north has produced a broad range of lithofacies which, under appropriate conditions, provide excellent reservoir potential in the Karroo sandstones of the Tanga and Ngerengere beds, Middle Jurassic limestones, Aptian/Albian sandstones and limestones, and Upper Cretaceous turbidite sands (Fig. 4).
Drilling in the Dar es Salaam platform has confirmed the presence of potential reservoirs throughout the stratigraphic column, ranging in age from Lower Jurassic to Tertiary. However, in the deeper parts of the basin such as the Bigwa embayment the primary targets are provided by Cretaceous sandstones comprising Lower Cretaceous sands equivalent to those that form the main reservoir in Songo Songo gas field, and Campanian and Maastrichtian turbidites. In the Ruaruke-Wingayongo area and westwards towards Kisangire, however, excellent reservoir potential exists in the Middle Jurassic and Karroo.
Target reservoirs in the Rufiji trough occur throughout the section and range from Karroo continental fluvial and deltaic sandstones, Middle Jurassic carbonates, Lower Cretaceous sandstones equivalent to those forming the Songo Songo reservoir, and Upper Cretaceous turbidites.
Reservoir is thought to be the main risk in the Mandawa basin, and porosity and permeability characteristics of Lower Jurassic sandstones in wells drilled through 1995 are poor. Target sandstones occur throughout the Lower and Middle Jurassic (Karroo, basal Mbuo, intra-Mbuo, intra-Mihambia, and Mtumbei), limestones in the Mtumbei, and Lower Cretaceous sands on the eastern flank of the basin.
Tanganyika Oil Co. Ltd., Vancouver, B.C., in 1996-97 drilled the East Lika well to 6,568 ft as a dry hole with no oil or gas shows and the Mita G-1 well to 7,800 ft. The wells are in the Mandawa basin onshore southwest of Songo Songo gas field.
Mita G-1 encountered live oil shows during drilling, but test results did not indicate hydrocarbon flow. Independent research laboratories and consulting companies, after reviewing detailed reprocessed seismic data, confirmed that the well penetrated residual liquid hydrocarbons. Geochemical analysis of oil extracted from cores and mud samples proved it to be light crude.
Analysis of the electric logs concluded that there are nonmoveable hydrocarbons in the sandstone reservoir below the Jurassic salt. All of the data strongly point to a remigration of the oil and gas from its original host rock at the Mita G-1 location as a result of structural modification to a potential shallower reservoir within the same structure. The company planned to drill Mita A-1 in late 1997 or 1998 on the 47 sq km Mita A structure, a large and high closed structure with its crest 9 km west of the Mita G-1 well.
Farther south is the Ruvuma basin. Although the basin`s reservoir potential has only been partly tested by deep drilling, information from outcrops, boreholes, and wells in the Mandawa basin suggest potential reservoirs in fluvio-continental Karroo sandstones, shallow marine-tidal Middle-Upper Jurassic sandstones, estuarine/nearshore Neocomian/Aptian and Albian sands, Turonian submarine fans, and the Oligo-Miocene sands of the Tertiary Ruvuma delta.
Karroo deposits were laid down in the failed rift Selous basin in response to rift pulses with facies evolving from a coarse, proximal character near to rift faults, into a fining-upward, distal, and maturing succession.
Depositional models predict that optimum conditions for reservoir development are in median locations where reservoir units occur in high energy braided fluvial systems. Reservoir quality sandstones of these types have so far been identified in the Lower Permian, Triassic Rufiji Series, and the Liassic Madaba Series. From the larger number of porosity/permeability measurements made on these sandstones, it is apparent that porosities of over 15% are not uncommon.
Holbrook basin, Arizona
The Holbrook salt basin of eastern Arizona and western New Mexico had not notched into the producing column by the end of 1997. However, the basin seemed to be getting close to the establishment of commercial volumes of carbon dioxide. And hydrocarbon shows that tantalized explorers since the 1950s continued to turn up.
At least 11 wells were drilled in the basin in 1997, most of them in Arizona. Operators planned exploratory drilling in both states in 1998.
The Holbrook basin measures 160 miles by 100 miles in Arizona alone, and thousands of square miles remain untested.
Sedimentary rocks in the Holbrook basin range in age from Cambrian to Tertiary, with most interest being centered about strata of Devonian and Permian age, writes Tucson consulting geologist Edgar B. Heylmun (Fig. 5). All of the rocks are shallower than 5,000 ft.
Cambrian rocks lie on Precambrian schist and granite to the west, but in much of the basin the Cambrian is missing and Devonian strata lie directly on the Precambrian. Heylmun describes the sedimentary units of greatest interest to drillers, starting with the oldest:
Martin formation (Devonian). The Martin consists mainly of limestone and dolomite of marine origin, interbedded with green and red shale. A basal sandstone may or may not be present. The Martin ranges from a few feet to over 500 ft in thickness, being thickest to the west. It is not present in the eastern part of the basin.
Numerous oil shows have been encountered in the Martin, and there are unconfirmed reports of free oil in some wells that penetrated the unit. The Martin is also petroliferous on outcrop where it is exposed south of the Mogollon Rim and deserves to be tested wherever present in the subsurface.
Naco limestone (Pennsylvanian). The Naco correlates in part with the productive Paradox sequence in northeastern Arizona and southeastern Utah. It consists of limestone, shale, sandstone, and anhydrite of marine and tidal flat origin, ranging up to 1,000 ft or more in thickness.
The unit is not present in the eastern part of the basin. The wells drilled to date have had no oil or gas shows of consequence, but in view of oil and gas production in the Paradox sequence to the north the Naco should be tested wherever it is present in the subsurface.
Supai formation (Permian). The Supai formation is the principal drilling objective in the Holbrook basin. It has been responsible for most of the oil and gas shows encountered in wells. It consists of sandstone, siltstone, shale, limestone, dolomite, anhydrite, and salt, depending on location.
Salt occurs in the central part of the basin, where it is 500 ft or more thick, and is used for subsurface LPG storage. Anhydrite is ubiquitous throughout much of the basin and apparently was deposited, along with dolomite, in sea-margin sabkha environments similar to those seen today in the Persian Gulf region tof the Middle East.
Almost all wells drilled in the Holbrook basin have encountered oil and gas shows in Supai, including small amounts of free oil in some tests. The presence of these shows would indicate that most of the rocks are thermally mature and in the oil window.
The Fort Apache member of Supai, a limestone or dolomite of lagoonal origin, is found throughout the Holbrook basin, sometimes being overlapped and underlain by evaporites. Oil and gas shows have been encountered in numerous wells, and it is petroliferous at outcrops south of the Mogollon Rim. Oil and gas shows have also been found in limestone and dolomite beds that lie above Fort Apache. The member is 140 ft thick in the eastern Holbrook basin but thins gradually to the west and north to 10 ft or less.
Supai as a whole ranges up to 2,000 ft or more in thickness and offers a variety of potential drilling objectives. It correlates in a general way with productive formations in the Permian basin. At some Holbrook basin wells, petroliferous Supai intervals were acidized and swabbed without success.
Coconino sandstone (Permian). The porous Coconino sandstone overlies the Supai throughout the Holbrook basin, but for some unknown reason it has not acted as a petroleum reservoir rock. It does act as an important aquifer, and it is the principal reservoir for helium at the abandoned Pinta Dome field in eastern Arizona discovered in 1950.
Indus basin, Pakistan
Pakistan has two distinct offshore provinces. The Indus basin in the Indian Ocean off Karachi is separated by the Murray ridge from the Makran offshore basin to the west.
Only 10 wells have been drilled in the Indus offshore, for a density of one well per 6,985 sq km. The deepest penetration went to 4,354 m. One of the wells, OGDC-Petro-Canada PakCan 1, flowed gas at the rate of 3.8 MMcfd with some condensate from Miocene at 2,743-47 m in 1986.
Two other wells had no shows. The other seven had gas shows in either Miocene, Paleogene, Paleocene, or Cretaceous.
At least four reservoir types should be considered objectives. They are Middle to early Miocene Gaj formation, Oligocene Nari, Eocene Kirthar and Laki, and Paleocene Ranikot (Fig. 6).
The following play types have been observed on seismic:
Seismic anomalies that appear to represent reef development, at edges of Oligocene carbonate platform, Paleocene carbonate platform, and Cretaceous carbonate platform, of Oligocene, Paleocene, and Cretaceous ages, respectively, with superimposed/parallel reefal anomalies of younger ages.
Rollover anticlines against growth faults in shelf margin basin.
Wrench fault structures and anticlines.
Structures associated with distribution and continuity of sandstone reservoirs and channel sands/turbidites related to submarine canyon fan systems.
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