This section contains six stratigraphic charts and associated discussion of reservoir and source rocks, plays, and potential.
The areas covered are the Torgay region in western Kazakhstan; the nonproducing Tarfaya basin off Morocco; the newly productive East Coast basin of New Zealand; the Murzuk basin of southwestern Libya; and the Limon basin of Costa Rica.
Torgay Region, Kazakhstan
The Torgay oil and gas region of western Kazakhstan covers 140,000 sq km, of which about 60,000 sq km are considered favorable for oil and gas occurrence. Depth to pay does not exceed 8,200-9,800 ft.
Nine fields have been discovered, V.I. Korchagin and co-authors wrote in a paper published in Geologiya Nefti I Gaza in 1996. A translation was published in 1997 in Petroleum Geology, McLean, Va.
Kumkol, the first oil field in the area, was discovered in 1984.
Torgay lies east of the southwestern Siberian province, from which it is separated by the Kustanay saddle. The Syr-Dar`ya sineklize (syncline) forms its southern boundary.
Proterozoic rocks serve as basement, and the intermediate complex consists of Middle and Upper Paleozoic rocks (Fig. 1). The sedimentary cover comprises Triassic to Paleogene sediments as well as some Neogene deposits.
Korchagin et al. write that three oil and gas bearing complexes are recognized in the sedimentary cover of the Torgay oil and gas region: Middle Jurassic, Upper Jurassic, and lower Neocomian.
The Middle Jurassic complex consists of interbedded sandstone, siltstone, and clays with total thickness of as much as 90 m.
The Upper Jurassic complex 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 Torgay`s petroleum resources are concentrated in the first two complexes, and about one-fourth is in the Neocomian.
The intermediate complex is also of interest for oil and gas. In the northern Torgay downwarp oil shows have been recorded in Upper Devonian-Carboniferous carbonates. Noncommercial flows or shows 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.
Fields discovered in the Torgay region are Kumkol, Aryskum, Kyzhlkiya, Karavanchi, Nuraly, Aksay, Bektas, Konus, and Maybulak.
Kumkol produces oil from two Lower Cretaceous zones and gas and condensate from four zones in Upper and Middle Jurassic. Aryskum produces gas and condensate from Lower Cretaceous and had gas shows in Upper Jurassic. Akshabulak produces oil from Lower Cretaceous and Upper Jurassic.
Kyzylkiya produces gas and condensate from Lower Cretaceous and had oil shows in basement, and Nuraly produces gas and condensate from Lower Cretaceous and Upper Jurassic, oil from Upper Jurassic, and gas from Middle Jurassic.
Korchagin et al. recommended that the main thrust of exploration be for stratigraphic and fault traps in the border zone of the graben-synclines and in structural saddles.
Hurricane Hydrocarbons Ltd., Calgary, held interests in eight fields in the South Torgay basin in 1999. The fields are Kumkol North and South, Nuraly, Aksay, Akshabulak, Maibulak, Kyzhlkiya, and Aryskum.
The company`s operations are in south-central Kazakhstan 625 miles west of Almaty. Hurricane, then an economically struggling independent, had its interest in the fields plus land holdings totaling 405,400 acres. It also held 100% interest in a 455,672-acre exploration license surrounding Kumkol field.
Consulting engineers estimated the eight fields contained 429 million bbl of proved and probable reserves as of Jan. 1, 1998. The reserves are shallow, averaging 3,000-5,000 ft. They produce light, sweet crude of 35-43° gravity with less than 0.4% sulfur.
Kumkol field was averaging 79,000 b/d in fall 1999 under the Hurricane-Kazakh joint venture.
Tarfaya basin, Morocco
A flurry of licensing in the late 1990s has unmasked intense interest in this previously shunned area of northern Africa`s western margin.
Drilling in 2000 and beyond is likely to reveal the area`s true potential.
The licensing has occurred in the deepwater portion of the Tarfaya basin. Shell, Lasmo, Vanco Energy, Enterprise Oil, Taurus Petroleum, and ROC Oil took blocks in the Atlantic Ocean off Agadir and Tarfaya. Morocco`s Onarep issued the first license in the current round in December 1997 to Enterprise.
The region is similar geologically to other highly productive Atlantic margin basins such as the Gulf of Mexico, Campos basin off Brazil, and offshore eastern Canada, which lay alongside the Tarfaya basin prior to rifting.
Previous drilling in the offshore part of the Tarfaya basin includes 18 wells, all located on the shelf.
Exxon`s Morocco Offshore-2 well in 1970 found heavy oil in a Jurassic reefal structure. Two appraisal wells proved the existence of a subcommercial heavy oil accumulation and the presence of lighter 38° gravity hydrocarbons.
Jarvis and others with Enterprise noted that at least five principal plays are likely to be present in the area. From oldest to youngest, they are:
- Lower Cretaceous basin-floor fan sands, capped by deepwater shales and sourced by underlying delta toe-sets or hemipelagic shales.
- Lower Cretaceous shingled turbidite sands re-deposited down-slope of the upper Tan Tan delta sandy top-sets. Interbedded hemipelagic shales act as seal and source.
- Aptian basin-floor fan sands sourced and capped by overlying Albo-Cenomanian shales.
- Lower Tertiary turbidite sands capped by Eocene/Oligocene shales and sourced by underlying Albo-Cenomanian shales.
- Oligocene turbidite sands sealed by overlying shales and sourced by either Albo-Cenomanian or Lower Tertiary shales.
Other, higher risk plays include:
- Lower Tertiary sands in stratigraphic, channel-fill traps, capped by Eocene/Oligocene shales and sourced by the underlying Albo-Cenomanian.
- Jurassic talus slope deposits forming the reservoir and stratigraphic trap, capped and sourced by Lower Tan Tan shales,
- Jurassic deepwater sandstones, sealed by intraformational shales and sourced by the Lower Jurassic.
Four reservoir units have been identified as offering potential in the area (Fig. 2). These are:
The Lower Cretaceous. The deepwater equivalents of Tan Tan delta sediments contain two types of reservoir/seal couplet. Shingled turbidite sands are predicted to be present having formed following the mass movement of Upper Tan Tan sandy delta top-set facies down into the basin. Interbedded hemipelagic shales would provide seal to these reservoirs. Secondly, basin-floor fan sands may exist associated with the mid Tan Tan unconformity seen in the shelfal wells. The overlying hemipelagic shales provide seal to this reservoir.
Aptian basin-floor fan sands. Detailed sequence stratigraphic analysis suggests that an as yet unproven reservoir may exist in the basin. This model is supported by evidence of coeval erosional channels and coarse clastic infill seen in a proximal setting onshore and time equivalent analogues seen off the American Atlantic coast (in DSDP well #603). The regional mid-Cretaceous Albo-Cenomanian mudstones provide a seal for this reservoir unit.
Paleocene to Eocene turbidite sands, sourced from the cratonic areas onshore and deposited directly into the deepwater basin. Overlying hemipelagic shale units would seal this reservoir.
Oligocene turbidite sands, deposited following further uplift of the African hinterlands. Miocene to Recent hemipelagic shales seal the sand reservoir.
Additionally, reservoir potential may exist in other units:
Jurassic deepwater clastics, though they would be deeply buried.
Jurassic talus slope deposits-debris from the steep reefal margin has collapsed into the deepwater and provides potential for additional reservoirs.
East Coast basin, New Zealand
Production capability was established in a new basin in New Zealand in mid-1998 when a gas well was tested near Wairoa.
Two discoveries represented a 150 mile jump eastward from nearest production, in New Zealand`s staple Taranaki basin.
Kauhauroa-1 tapped dry gas on land just north of the town of Hawke Bay in a producing zone that is a mix of Miocene Makaretu sands and limestones 3,600-4,008 ft deep (Fig. 3).
Neither Kauhauroa nor a second tested well were on production as of late 1999. A severe industry economic downturn in late 1998-early 1999 meant that the project remained at appraisal stage well into late 1999.
Kauhauroa-1 stabilized at 11.5 MMcfd of gas with 2,100 psi flowing tubing pressure after 60 hr of testing. It flowed at rates as high as 15.9 MMcfd. CAOF exceeded 70 MMcfd.
Tests were conducted open hole without stimulation. The gas is 100% methane, and no water or condensate surfaced.
Westech Energy Corp., Denver, and Enerco New Zealand Ltd., Auckland, the country`s largest utility, encountered gas during drilling in a zone at 2,300 ft.
Awatere-1, on a separate structure 4.3 miles southwest of Kauhauroa-1, flowed 3.1 MMcfd of gas from pay at 6,409-6,628 ft.
The companies held acreage offshore in Hawke Bay and hope to drill there eventually. The discoveries led numerous other companies to take acreage holdings in the area, and a relatively large number of seismic programs were announced.
A report by the New Zealand Ministry of Commerce said plays in the East Coast region include Cretaceous sandstone towards the western margin, Oligocene Lower and Mid-Miocene submarine fan sandstone in the basin axes and eastward, and porous Pliocene limestone in various sub-basins. Some probably overlap.
The region has many surface structures too intense to be worth investigation, but several areas contain gentler structures. The region has about 250 gas seeps, at least four major oil seeps, and 50 localities where formations are impregnated or stained with oil. Rocks in these localities include porous sandstones and some fractured formations.
Westech and Enerco, since renamed Orion, had drilled 10 wells as of fall 1999 on PEP 38329 in the initial continuous program in the basin. The main reservoir targets were Mid-Lower Miocene sands and limestones. The companies were defining a new seismic program.
Westech-Orion also assumed a 70% working interest and operatorship in adjacent Permit 38335 with remaining interests held by Indo-Pacific Energy Ltd. and Everest Energy Inc. Offshore, Westech-Orion had completed acquisition of a 590 sq km 3D survey on Permits 38325 and 38326. Westech and Orion are private companies.
Murzuk basin, southwestern Libya
Exploratory drilling in the basin has turned up world class oil reserves spread across several blocks about 500 miles south of Tripoli.
The main commercial oil bearing reservoirs in the basin are Ordovician sandstones of the Memouniat formation (Fig. 4).
Memouniat is a regressive sandstone sequence composed of massive, cross-bedded clastic units with occasional high percentages of kaolinitic matrix which degrade reservoir porosity from good to very poor. Local silicification also affects reservoir poro-permeability characteristics.
Romania`s Petrom made discoveries in the 1980s on Block NC115, and with 2 billion bbl of 36° gravity oil reserves the fields were declared commercial in 1989. Petrom`s financial difficulties led Repsol, Total, and OMV to take over the block in the early 1990s. The fields were initially referred to as Murzuk fields, and Libya ratified the development proposal in late 1994.
Now known as El Sharara, the main field started up in 1997. Reserves on the block are at least 2 billion bbl of oil.
South of NC115, Lasmo Grand Maghreb Ltd. discovered Elephant field in 1997 on NC174. The F-NC174 discovery well cut about 100 m of oil pay in excellent quality reservoir sands with average porosity of 16%.
DSTs from below 5,000 ft aggregated 7,500 b/d of high-quality, 38° gravity sweet crude, and Lasmo said the reservoir pressure data indicated that on production the well could make 10,000 bo/d
Development involved laying a pipeline about 45 miles north to El Sharara field, from which a pipeline extends to the Mediterranean coast.
In late 1998 the Repsol group found more oil close to El Sharara field on NC115. The M-1 new-pool wildcat flowed 2,500 b/d of 43° gravity oil on test. Partner OMV Oil Production Libya GmbH said the well`s output could reach 8,000 b/d using standard pumping techniques.
The partners planned to start production in 1999 and estimated the new well`s reserves at 100-200 million bbl of oil. They planned appraisal drilling and another new-pool wildcat in the area.
In the late 1980s the Bulgarian state oil company discovered five oil accumulations in the Ordovician and two minor oil accumulations in the Devonian in NC101. Reserves estimate was a combined 500 million bbl or more. This area is 100-120 km east of Elephant field and just off the eastern boundary of NC174. The discoveries were not developed because of financial shortfalls.
Repsol Exploration holds NC187, which bounds NC174 and NC101 to the south.
Explorers have not solved all of the Murzuk basin`s riddles, Lasmo said in 1999. The operator said that results of the seven exploration wells it had drilled on NC-174, including the Elephant discovery, show that the petroleum system in the basin is not as simple as it might appear. Lasmo said considerable uncertainty remains with regard to the prediction of good quality reservoir, the distribution of source rock, and the charging of structures.
Limon basin, Costa Rica
A revival in exploration seemed assured in mid-1998 when Harken Energy Corp., Houston, declared its intent to take on the challenge.
Harken signed an exploration and production contract with MKJ Xploration Inc., Metairie, La., for about 1.4 million acres in the North and South Limon back-arc basin in and off Costa Rica. The contract area consisted of Blocks 2, 3, 4, and 12.
Harken and MKJ were to create a new company, Harken Costa Rica, owned 80% by Harken and 20% by MKJ. Following environmental impact studies and Costa Rican approval of the project, Harken was to pay MKJ $4.2 million for concession rights and fulfill $8 million in initial work obligations.
Nonproducing Costa Rica in early 1997 had awarded its first private contract for hydrocarbon exploration and production in more than 30 years to MKJ, a private New Orleans-area independent. The four blocks were part of the October 1997 licensing round and totaled 1,391,489 acres. The blocks were MKJ`s first operated non-U.S. venture.
Conditions on the blocks were for a maximum 6-year exploration period, including 3 years primary term with three 1-year extensions, and a consecutive 20 years for production.
Fiscal terms included a 15% royalty to the government, subject to a 30% maximum tax rate, and no other direct government participation. MKJ bid a reinvestment percentage of 5%, meaning that 5% of any profits would be spent on community improvements.
MKJ was required to gather 96 sq km of 3D seismic data, drill 3,000 m of exploratory footage, spudding by the end of the second year, and spend a minimum $2.3 million overall.
Elf Aquitaine held the last Costa Rican area to be licensed, in 1976. Since then the country has had associations with Pemex and Petro-Canada.
The Limon basin is a Cretaceous and Tertiary back-arc basin with three parallel thrust and fold systems. Two main structures are subthrust basement features with possible overlying Cretaceous reef development.
MKJ identified two 30,000-60,000 acre anticlines based on interpretation of 2,200 miles of modern 2D seismic data and magnetic, gravity, and surface geology data.
Main reservoir targets are Middle Cretaceous rudistid reef limestones (Fig. 5). The reefs are underlain and potentially sourced by organically rich Middle Cretaceous black shales that are stratigraphic equivalents to the prolific La Luna/Querecual/Villeta oil source rocks in the Magdalena, Llanos, Maracaibo, and Maturin basins of Colombia and Venezuela.
Total organic carbon in the Loma Chumico shales in Costa Rica is generally 10-20% and ranges as high as 40-50%. The South American source rocks contain an average 4% TOC. The Loma Chumico/La Luna oil source rocks correlate with the Cretaceous oceanic anoxic event OAE-2.
The former Union Oil Co. of California drilled the Cocoles 2 well south of Block 2, on present day Block 1, in 1957. Tested at the rate of 1,800 b/d of 46° gravity oil from 4,900 ft (Oligocene), it produced only about 10 days as water cut increased.
Just northwest of that well is the San Jose well, which Pemex drilled to 15,749 ft for Recope in 1983. It is the deepest penetration on Costa Rica`s Caribbean margin.
MKJ`s onshore structure covers 24,000 acres with 3,000-4,000 ft of closure. It is a thrust faulted surface anticline with active oil and gas seeps that indicate deeper oil and gas generation and vertical migration. Reserve potential is 1 billion bbl of oil at 8,000-12,000 ft.
The onshore/offshore structure covers 56,000 acres with 2,500 ft of closure. Water depth ranges to 1,600 ft. The structure is a subthrust basement anticline with an indicated overlying massive Middle Cretaceous rudistid reef complex at 8,500-12,000 ft.
Reserve potential is 2.2 billion bbl for the Cretaceous reef and 500 million bbl (or 2 tcf of gas and 50 million bbl of condensate) for the overlying Oligocene-Miocene barrier reef at 5,000 ft. The Miocene reef has associated seismic bright spots and flat spots that may indicate hydrocarbon saturation.
A pronounced high temperature thermal anomaly and seismic velocity anomaly are associated with the structure`s crest.
The vertical seals, Uscari shales, are moderately overpressured (0.65 psi/ft). The velocity anomaly, which could result from vertical leakage from an underlying reservoir gas cap, covers 12,000 acres.
No well drilled in the Limon basin has penetrated rocks older than Paleocene (basal Tertiary), although multiple wells have tested 30-46° gravity sweet crude from shallower Tertiary formations.
Oil and gas seeps are common on the country`s Caribbean coast, and geochemical studies indicate a high geothermal gradient with indicated deeper oil and gas generation and migration.
Reserve potentials are 1-3 billion bbl for Cretaceous reef limestones and 500 million bbl for shallower Tertiary reef as a secondary objective.
A modern, 16,400 ft capacity land rig is available in the area. A power station and RECOPE`s 15,000 b/d Limon refinery are near the center of the four contiguous blocks. The refinery processes mostly Mexican Mayan and some Venezuelan crude. A national preserve area separates Block 3 into two parts.
Indus offshore basin, Pakistan
Pakistan`s Exclusive Economic Zone covers about 240,000 sq km offshore, about 40% of the country`s land area. The western part of the offshore covers the Makran sedimentary basin, while the eastern sector comprises part of the Indus basin.
The Indus offshore basin straddles the continental crust of the extension of the Sind platform and Karachi trough and the oceanic crust of the Arabian Sea east of the Murray ridge-Owen fracture zone plate boundary, write Viqar un Nisa Quadri and S.M.G.J. Quadri in Oil & Gas Journal. The continental shelf between Murray ridge and the Indo-Pak border is 120-150 km wide, cut in the southeastern corner by the submarine canyon of the Indus river.
Exploration began near shore with Sun Oil Co. in 1961-62. Conducting seismic surveys were Wintershall AG in 1969-72, Shell International in 1973, Phillips Petroleum (deep water) in 1977, Husky Oil in 1976-78, OGDC-Norad in 1982, OGDC-PetroCanada in 1986, Oxy in 1988-89, and Canterbury Resources-Sceptre (transition zone) in 1990.
Ten wells have been drilled in the Indus off Pakistan. The deepest, Sun`s Dabbo Creek 1 in 1963, went to TD 4,354 m in Upper Cretaceous (Fig. 6). Sun reported minor gas shows in Cretaceous.
OGDC-PetroCanada`s PakCan 1, drilled in 1985-86, went to TD 3,701 m in early Miocene. It flowed 3.8 MMcfd of gas with some condensate on a drillstem test at 2,743-47 m. Several other wells reported gas shows in Miocene and Cretaceous.
In PakCan 1 all samples indicated the presence of Type III kerogen. TOC values indicate fair to good source in the Miocene Gaj formation.
Maturity analysis indicated an immature zone down to 2,800 m and early mature to mature from 2,800 m to TD 3,701 m. However, there is no correlation between the results of the DST and the source rock. The condensate and gases recovered from DST samples are of peak maturity levels. As such these hydrocarbons have migrated from a deeper source.
In Oxy`s Sadaf 1 well TOC values indicate very lean source. Throughout the well the TOC values are below 0.5%. Few values are 0.5-0.6%. The kerogene type is III, thermally immature.
Geochemical analysis performed on samples from Husky`s Karachi-South A-1 well indicate that the shales of the Kirthar, Ghazij, and Dunghan formations have oil-prone kerogen and are mature for the generation of oil. The TOC values range from 0.46% to 1.6%. The Ranikot and Mughal Kot formations have a mixed type of kerogen with potential for both oil and gas. The TOC values range from 1.0% to 1.22%. Occasionally these are as high as 2.21%. These formations are mature for condensate and gas.
As of fall 1999 Lasmo plc held two large exploration concessions in the Indus offshore west and south of Karachi. Offshore Indus Blocks A and B cover a total of 14,700 sq km.
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