HERE ARE STRATIGRAPHIC charts and accompanying discussion of existing and potential reservoir and source rocks.
The areas covered are several basins in Canada`s Maritime Provinces; the Chindwin basin of far northwestern Myanmar along the border with India; the Baltic syneclise region of Latvia; Sacramento gas basin of northern California; and several basins in the Hashemite Kingdom of Jordan.
Sacramento basin, California
More than 150 fields have been discovered in northern California`s Sacramento basin (Fig. 1). The 114 fields with cumulative recovery of 1 bcf or more have a combined probable ultimate recovery of 9,546.3 bcf of gas, writes Bakersfield consulting geologist Nat H. MacKevett.
It is reasonable to expect another 500 bcf of new ultimate production from fields in the basin, which would hike all time ultimate recovery to more than 10 tcf.
Relatively minor amounts of oil and condensate have been produced from the southern part of the basin. The main fields for liquids are Brentwood, Livermore, Rio Vista, and Lindsey Slough. This oil and condensate are produced mainly from Upper Cretaceous sandstones, with lesser amounts from Lower Eocene sandstones. The main oil source rock for these Lower Eocene and Upper Cretaceous objectives is considered to be Upper Cretaceous Moreno shale.
Here is a breakdown by formation of cumulative production through Jan. 1, 1997, from 46 fields that have each yielded 25 bcf or more:
- 32.3% of the gas came from Upper/Middle Eocene and younger reservoirs, including Nortonville, Suisun, Domengine, Capay, and Hamilton.
- 26% of the gas came from Lower Eocene and Paleocene reservoirs, including Meganos, Midland, Anderson, Wagenet, Martinez, McCormick, and First Massive (Mokelumne).
- 18.4% of the gas came from later Upper Cretaceous reservoirs, including Moreno, Second and Third Massive (Mokelumne), Bunker, Garzas, Blewett, Starkey, Peterson, K-1 and 2, Winters, Tracy, and Lathrop.
- 23.3% of the gas came from earlier Upper Cretaceous reservoirs, including Kione and Forbes.
Numerous independent operators have conducted 3D seismic surveys in the basin the past few years. Coverage is believed to total several thousand square miles. The payoff has been in new fault block, new pool, and new field discoveries.
Jordan`s main basins
Two main play concepts can be identified in the different sedimentary basins of the Hashemite Kingdom of Jordan, according to the Natural Resources Authority.
Tertiary and Mesozoic plays can be identified in the Azraq block in central Jordan and including Hamza oil field; North Jordan Block; Basalt plateau; and Jordan Rift Valley (Fig. 2).
Paleozoic plays can be identified on the Sirhan Block; Jafr-Central Jordan Block; and Risha Block, which contains Risha gas field.
The Azraq basin lies between the highcentral plateau in the west andtheBasalt plateau in the east.
Seismic available on the Azraq Block is of fair to good quality and extensive coverage. Following the oil discoveryat Hamza, 17 wells were drilled there and more than 13 wells were drilled in other parts of the basin.
TheFuluk growth fault is the main structural element responsible for the development of a NW-SE trending asymmetrical graben with significant thickening of Cretaceous and Paleogene sediments. The sedimentary section reaches a maximum thickness of about 7,000 m near this fault, whereas the vertical throw is more than 2,500 m to the southwest.
The traps in the basin are fault controlled structural features of relatively small size. Possible reservoirs are found in Triassic sandstones, Lower Cretaceous Kurnub sandstone, and in Campanian Azraq sandstones. The proven oil bearing reservoirs are Cenomanian-Turonian fractured limestones and dolomites of the Shueib and Hummar formations.
Source rocks are interbedded Cenomanian and Turonian limestones and marls; however, geochemical data suggest additional source rock potential in Triassic and possibly Paleozoic sediments that may have contributed to the hydrocarbon accumulation.
All wells in the Azraq basin have penetrated a 30 m section of Maestrichtian oil shale of carbonate quality at depths of 900-1,000 m.
The North Jordan Block, known also as the northern highland, is the site of a broad arch that plunges northward towards the Damascus basin.
The Damascus basin is seen as the kitchen in which source shales and limestones of Permian, Triassic, and Cretaceous ages are possible source rocks. The generation of oil is proved by the existence of oil seeps associated with spring waters flanking the Ajlun dome. Live oil shows were observed in a core from Jurassic limestones obtained from the NH-2 well near the border with Syria.
The Triassic and Jurassic carbonates and evaporites are ideal reservoir and seal alternations, the carbonate reservoirs exhibiting porosities of up to 20%. These are interbedded with anhydrites, which form good seals.
Northeast Jordan`s large Basalt plateau is a Mesozoic fault controlled basinal area, as shown by inward dips on both flanks.
The QA-1 well, drilled by Petrofina in 1990, is the only exploration well drilled in this large area. It encountered shows during the drilling of the Ghareb argillaceous limestones (the equivalent of the oil shales found on the surface and in many other areas at 815-1,015 m). Analysis of samples revealed an excellent source rock. However, the source is immature at this burial depth. Geochemical data indicated that if the formation were found buried at 2,000 m it might be mature.
Two other formations have some degree of source potential in Mesozoic, although not as good as Ghareb. They are the Turonian Wadi Essir formation and the Upper Cenomanian carbonates Hummer and Shueib formations.
The Wadi Essir formation is the source for Hamza oil field in the Azraq block.
A third source potential may be present in the Silurian shales if these extend beneath the basalt. This concept assumes charging either Ordovician sands from the Silurian source or charging Triassic sands from Silurian shales near the Silurian erosional edge, since the two dips are in opposite directions.
The primary reservoir intervals anticipated are Kurnub sandstones and Jurassic and Triassic carbonates and sands.
Several small oil and gas fields have been discovered on the Israeli side on the western flank of the Jordan rift valley. There is no lack of good quality reservoir rocks in the area. The section is known to have thick Miocene sand of reservoir quality. Cretaceous Kurnub sands are another target. On the shoulder blocks various sands from the Cambrian to the Triassic and Jurassic can be targets along the length of the valley.
Paleozoics are prospects in the Sirhan basin, since the Mesozoic and Tertiary sections are thin and presumably immature. Existing seismic coverage has partly defined numerous attractive structures in Paleozoic rocks, including several structures of about 5 by 10 km.
The target horizons lie at the top, sand-prone levels of the Ordovician or else in deeper, coarse clastic Lower Paleozoic beds. In addition, basal Mesozoic structures of potential interest lie in the northern part of the block. The sedimentary column reaches more than 13,000 ft in thickness, mostly Paleozoic clastics with relatively thin Mesozoic cover.
Indicated source rocks for this large Paleozoic basin are thick, widespread Silurian shales as much as 400 m thick in exploration wells. Although not well defined seismically, the Silurian is known to thicken toward the basin`s southern and eastern areas. Trap types are horsts and arches formed by intersecting fault trends, together with the associated drape and rollover features in the overlying beds. Existing seismic control suggests that reversals at several Paleozoic levels tend to stack vertically, but not with the identical internal geometry. Another additional attraction is the presence of a deep graben in the adjacent Saudi territory where the Cretaceous is buried deep enough to have reached maturation.
The Jafr-Central Jordan basin is a present-day topographic low bounded to the north and east by the Zakimat and Al-Karak-Wadi Fiha Tertiary activated wrench zones. Tertiary age sediments in the center of the basin overlie Cretaceous limestones and marls that crop out locally along the uplifted margins of the fault zones.
The primary reservoir is the porous arkosic sandstone of the prerift Salib formation, sourced from downdip synrift shales or from the Middle Cambrian Burj limestone/shale unit.
Secondary objectives are Ordovician sandstones found to have good reservoir facies in the Hunt Oil Co. Jafr-1 well drilled in 1989. Silurian "hot shales" were found to be organically rich in Jafr-1 (up to 9% TOC) albeit immature on structure. However, in the nearby Wadi Sirhan-3 well a maturity range of 0.7-0.8% has been interpreted based on graptolite reflectance, Tmax, etc.
The main play in the Central plateau, just north of the Jafr depression, is at the Middle Cambrian level. Potential reservoirs occur throughout the sandy Cambrian (Salib, Umm Ishrin, and Disi formations). Reservoir potential also exists within the Numayri dolomite member of the Middle Cambrian Burj formation.
Regional extensive seals are thought to exist in the Middle Cambrian Burj, base Silurian Mudawwara, and possibly Middle Ordovician Hiswa formations.
The Risha/Safawi Block comprises some 15,250 sq km in northeast Jordan. The main regional feature of the sedimentary column, which reaches more than 7,000 m in thickness, is a widespread angular unconformity that separates Mesozoic and Paleozoic rocks. This unconformity records a reversal ofbasintilt, because Paleozoic rocks beneath it both dip and thicken in an easterly direction,where theoverlying Mesozoicsection thickenstoward the west and dips under the Basalt Plateau.
NRA collected 9,057 line km of multifold seismic data and drilled twoexploratory wells on Mesozoic anomalies at the western margin of theblock.This activityrevealed the existence of thick, rich Silurian sourcerocks beneath the Mesozoic unconformity. Selective reprocessing of the seismic data after drilling thewellshas shown that the source rock section thickens toward the east and covers all of the Risha block.
The RH-2 well encountered asphalt at a shallow depth. When analyzed geochemically, the asphalt was shown to have a carbon isotope rating characteristic of Paleozoic oils worldwide. This piece of evidence is in strong support of the existence of a petroliferous Paleozoic basin in the Risha Block. The RH-3 well, drilled in the eastern part of this area, discovered commercial quantities of natural gas. Risha field production averages 25 MMcfd. The gas is being used to generate electricity.
Chindwin basin, Myanmar
Tertiary and Cretaceous targets lie buried in the remote Chindwin basin of northwestern Myanmar, along India`s eastern border (Fig. 3).
This is, for commercial purposes, a nonproducing basin about 150 miles northwest of Mandalay. This caveat is necessary because an unofficial oil industry thrives in the area, as reported by Ed F. Durkee in Oil & Gas Journal.
Local people have drilled hundreds of wells 50-200 ft deep using bamboo derricks and bale 40° gravity crude west of Kalewa along banks of the Myittha River. The wells produce a few gallons to as much as 20 gal/day for exceptional wells. This operation has no relation to Myanmar Oil & Gas Enterprise.
This oil occurrence testifies to the potential oil source rocks of the Eocene in the Chindwin basin, Durkee concludes.
About 40 miles northeast of Kalewa lies abandoned Indaw oil field. Indaw, discovered in 1918, is named for Indaw anticline, a surface feature with an area of closure 45 miles long and four to five miles wide, for an area of about 250 sq miles.
Indaw field produced 1.5 million bbl of oil during 1918-42 from discontinuous Miocene sandstones at 800-1,200 ft. It fed a 25 mile, 4 in. pipeline to a small refinery at Pantha on the Chindwin River. The facilities were destroyed in 1942 before the advance of the Japanese Army.
It seems likely, Durkee wrote, that the oil potential of the Eocene at Indaw makes the structure a good candidate for a deep, giant discovery. The oil at the old field likely migrated upwards from Eocene source rocks or reservoirs along a major thrust zone and associated faults into the shallow Miocene reservoirs.
Yukong of Korea spent around $70 million in seismic and exploration work and drilled one well at Indaw less than a decade ago. Yukong`s 1989-90 helicopter seismic data show nearly 2,000 ft of vertical structural relief in an east-west direction on seismic reflections from about 14,000 ft and deeper. Reservoirs at this depth could be associated with oil source rocks seen in the outcrop belt to the west, including the Kalewa oil fields.
Yukong drilled a well, Indaw-1, abandoned at 9,435 ft before reaching what is believed to have been the company`s primary objective in the Eocene Pondaung formation at 10,000-15,000 ft on the subthrust crest of the structure. Burmah Oil Co. drilled its Indaw 76 well in 1963 to 7,425 ft. Both wells failed because of drilling problems in overpressured section.
Oil saturated outcrops, oil and gas seeps, and shallow wells extend along the Eocene outcrops for 100 miles in a north-south direction about 40 miles west of Indaw.
Yenan anticline, west of the Chindwin River and west of Indaw, is another very large surface structure. It provides one of the few places were Cretaceous strata, which are untested in Myanmar, can be penetrated at reasonable drilling depths.
Latvia/Baltic geology
Here is how the State Geological Survey of Latvia sums up the geologic prospectivity of this Baltic region (Fig. 4):
The Paleozoic succession of the Baltic Region is proven petroliferous, with oil production from Cambrian and Ordovician reservoirs in several countries. Latvia is currently not producing oil; however, discoveries onshore and the wells drilled offshore show positive results.
There is an accepted geological and exploration model for the region, stating that the prospectivity will increase in a southward direction in the Baltic area, based on the fact that the sedimentary succession thickens towards the south. This model, however, is too simple and does not take into account the local tectonics governing the geological development and ultimately the areas prospectivity.
It is expected that the Cambrian transgressive and regressive sands are highly prospective within Latvia, both onshore and offshore. A majority of the so-called exploration wells drilled during the Soviet period prior to 1991 (most wells were drilled prior to 1971) were drilled off-structure. Several of the undrilled and drilled structures should be reappraised using modern exploration techniques. Although some of these structures are rather small in size, their shallow depth of burial will allow for reduced exploration costs.
The Ordovician carbonate reefs or build-ups are also highly prospective in the Baltic Region and are analogous to the oil-bearing reefs on the Swedish island of Gotland to the west. The trend of organically formed carbonates, exhibiting reefoid structures on the seismic, can be followed from this area into the Latvian area. This trend is regarded as highly prospective and these prospects should be among the early candidates to be tested in a new phase of exploration, the Latvian survey statement continued.
The generalized stratigraphical columns of Latvia exhibit a series of both proven and potential reservoir rock units, but some of the younger, e.g. Devonian sandstones, are found in a position too shallow to be of any exploration value. It should be noted, however, that their offshore occurrence in Latvia is currently documented in only a limited number of wells, and that their distribution pattern may prove to be more extensive with further exploration.
The source rocks of the area are of risk, since few, mature units have been currently identified. Within both onshore and offshore Latvia the classic Alum shales of the Baltic Region are missing, but organically rich shales are found within the Upper Ordovician (Mossen and Fjacka formations) and Silurian (Dobele formation) successions. Their positions in relation to potential reservoir units are still to be resolved and will require further investigations to map, especially their offshore distribution. It is, however, generally accepted that potential mature source rocks have expelled hydrocarbons from kitchen areas, most likely to the south, and charging reservoir units within structural and stratigraphic traps. The lack of proven Cambrian source rocks in Latvia represents a considerable risk, the survey noted.
It is anticipated that the southern part of Latvia, in both onshore and offshore areas close to the Lithuanian border, will have source rocks and kitchen areas in common with the countries to the south. It is also known that Alum shales have been identified in wells both in Poland and the southern part of the Baltic Region (in Sweden), and that a black organic rich shale has been found in the Kaliningrad District.
Onshore wells are numerous in Latvia, but the majority of these wells were drilled before 1970, with well sites chosen based on limited quality seismic. The wells all had targets in Lower Paleozoic prospects, but based on current knowledge many of these exploration wells were drilled off-structure. It must also be understood that during the Soviet period, Latvia was only one of the many republics, and the Soviet oil industry had access to vast areas, which were probably regarded as far more prospective than the present Baltic states. The well data available onshore is therefore from wells of many different kinds and status, from exploration wells with discoveries, shows, and dry holes, to wells drilled only for stratigraphic purposes.
The onshore well data base is extensive and available to the oil industry for purchase and inspection. The wells are not only logged, but well cores are kept in stores administrated by the State Geological Survey of Latvia.
Offshore wells are far more limited in number, only three wells have been drilled currently. The P6, E6, and E7 wells, were drilled from 1982-88, and the latter two are exploration wells. The P6 well is a stratigraphical borehole. E6 was given an oil discovery status but was never declared commercial, and E7 was a well with shows.
P6 was a test well for drilling equipment and was never regarded as an exploration well. The well is truly a stratigraphic well. Located off-structure, it drilled through the whole Paleozoic succession and a further 300 m into Precambrian crystalline basement before terminating at 1,835 m.
Maritimes Canada basins
Canada`s Maritime provinces began to see a serious round of exploration in 1997-98.
Catalysts for the action, which seemed likely to persist into 1999, was the start-up in late 1997 of oil production from Hibernia field on the Grand Banks off Newfoundland and the designation of the route of the Sable Island gas pipeline from Scotian shelf fields via eastern Canada to the New England U.S.
Acreage blocks were in force in the Gaspe Peninsula, Anticosti and Magdalen basins, Gulf of St. Lawrence, Prince Edward Island, New Brunswick, Nova Scotia, and western Newfoundland (Fig. 5).
The Anticosti basin covers the St. Lawrence River estuary and the northern part of the Gulf of St. Lawrence. The basin`s depositional area covers about 170,000 sq km, about 80% offshore. Sedimentary rocks are Hadrynian-Cambrian to Pridolian (Upper Silurian) in age and reach about 12 km thickness in the deeper part of the monocline, according to information supplied by Corridor Resources Inc., Halifax.
The Anticosti basin contains dominantly carbonate rocks of Ordovician age. On Anticosti Island, the main reservoir targets are the porous and permeable dolomites associated with the shoreline of the ancient Iapetus ocean bordering eastern North America during early Ordovician time. These reservoir units are referred to as the "Romaine" formation or the "Beekmantown" in Quebec. They are the equivalent of the Ellenburger and Arbuckle dolomites in Texas and Oklahoma.
The Canadian shield is well exposed in Labrador and Quebec along the north shore and is composed of Precambrian rocks of the Grenville Group. The Long Range Complex in the western part of Newfoundland resembles the Grenville, which forms the basement for the offshore area. Overlying the Precambrian basement, sediments encountered in the Anticosti subsurface on the sequence lying in the western part of Newfoundland ought to be found.
Ordovician and Silurian sediments present a relatively stable carbonate shelf on Anticosti Island and overlay the Precambrian basement with angular unconformity. On Mingan Island, the Lower and Middle Ordovician rocks of the Romaine and Mingan formations, which could include part of Black River-Trenton formations, overlay Precambrian basement with angular unconformity and thicken to the south and possibly to the east.
Upper Ordovician and Lower Silurian age carbonates of the Vaureal, Ellis Bay, Becscie, Gun River, Jupiter, and Chicotte formations outcrop on Anticosti Island. The Romaine dolomite, Mingan sandstone, Black River-Trenton limestone, and Macasty bituminous shale (Utica equivalent) rocks are also encountered in the subsurface. This rock assemblage shows a monocline dipping gently (3°) toward the south with the expectation of normal faults. This sequence was for the most part unaffected by the Middle Ordovician Taconic and Middle Devonian Acadian orogenies, which disturbed equivalent older or younger age rock in Gaspesia and Newfoundland.
Gaspesia is characterized by two distinctive rock sequences. The first sequence consists of Cambro-Ordovician allochthonous sediments emplaced during Taconic Orogeny. The second major sequence consists of Upper Ordovician to Middle Devonian sediments of the Gaspe-Connecticut synclinorium resting unconformably on the Cambro-Ordovician sequence. Locally both sequences are covered by Late Carboniferous rocks equivalent to the Canso-Riversdale Groups (Mississippian).
According to St. Julien and Hubert, with an analogy with the St. Lawrence Lowlands, we can recognize two tectonic domains in the Cambro-Ordovician sequence. The internal domain contains metamorphic sediments, volcanics, and interpreted remnants of former oceanic crust. The external domain is subdivided into inner and outer belts. The inner belt consists of slivers of platform sediments transported by gravity slides. The outer belt, which consists of thrust-imbricated structures, is characterized by the Cloridorme par-autochthonous flysch sediments and is separated from the inner belt by Logan`s line.
The present day structural contact between the autochthonous platform (Romaine-Mingan-Black River-Trenton and Macasty formations) and the external domain is not recognized in Gaspesia. It is interpreted that this contact occurs offshore and forms the southern limit of a sedimentary sequence relatively unaffected by Taconic movements with the exception of normal faulting.
In western Newfoundland, the sedimentary sequence is composed of autochthonous Cambro-Ordovician sediments overlain by allochthonous sequences (Hare Bay and Humber Arm) of the same age that were transported during the Taconic Orogeny. The Humber Arm allochthonous and the Mainland par-autochthonous flysch are overlain unconformably by Post-Taconic Long Point Group (neo-autochthonous) and Clam Bank formations that include part of Cambro-Ordovician rocks deformed by the Middle Devonian Acadian Orogeny.
The basal portion of the autochthonous rocks is a Cambrian sequence of clastic and carbonate sediments. Locally, in the Blanc Sablon area near the Quebec-Labrador boundary and in western Newfoundland, small patches containing the Labrador Group-Bradore-Forteau-Kippens-Hawke Bay March Point and Petit Jardin-Eddies Coves formations rest unconformably on the Precambrian.
This assemblage is overlain by the Lower and Middle Ordovician carbonates of the St-George Group (dolostone) and the Table Head Group (limestone), which become shalier as it grades into the graptholite bituminous black shales of the Black Cove formation. This Ordovician sequence is equivalent to the Romaine, Mingan-Black River-Trenton, and Macasty formations encountered in the subsurface of Anticosti Island.
An important disconformity observed in western Newfoundland between the Long Point and the Clam Bank formation is probably related either to the Late Silurian Salinic disturbance (?) or to an early phase of the Acadian Orogeny, wrote Rogers in 1970.
Considerable oil and gas exploration has occurred in these basins the past 140 years. Most significantly the Newfoundland Hunt Oil Co./PanCanadian Petroleum Ltd. Port au Port 1 well near the southwest tip of Newfoundland`s Port Au Port Peninsula flowed oil and gas at respectable but subcommercial rates on drillstem tests from the St. George and Table Head Groups. This well is the most nearly successful in a modern round of exploration that is extending into 1999 with the planned drilling of an exploratory well at Shoal Point on the Port au Port Peninsula.
The earliest drilling was undertaken in the Hillsborough basin of southeastern New Brunswick. Dr. Tweedel from Pittsburgh drilled the first two wells there in 1859, contemporaneous with Col. Drake`s discovery of oil in Pennsylvania.
After only marginal early exploration success, Stoney Creek oil and gas field was discovered in 1909. It supplied natural gas to Moncton by pipeline for about 80 years.
Maritimes Canada`s only commercial onshore field, it ultimately produced some 28 bcf of gas and only 830,000 bbl of oil from more than 20 million bbl of oil in place in the Albert member of the Mississippian Horton formation at about 1,700 ft. The low recovery was due mainly to the old fashioned drilling and completion practices employed.
Later exploration in areas surrounding Stoney Creek field failed to yield more commercial discoveries until 1998, when a well drilled by MariCo Oil & Gas Corp., Fredericton, N.B., on the Hillsborough prospect flowed a reported 2.5 MMcfd of gas from Albert/Horton.
Three exploration core holes and four exploration wells were drilled on Anticosti Island between 1963-74. Several encountered substantial shows of both oil and gas, but none was a commercial discovery. Dozens of very shallow exploratory wells and a few deeper wells were drilled on Gaspe, primarily near the eastern end of the peninsula, from the late 1800s to the mid 1970s. Several encountered numerous shows of oil and gas but no commercial hydrocarbons.
Nine exploration wells were drilled on Prince Edward Island from the 1950s to 1978, with two wells encountering substantial shows of natural gas but no commercial developments. On the Magdalen Islands, numerous very shallow coreholes were drilled in the early 1970s on the tops of salt domes to determine their suitability for salt mining.
Drilled to depths of only a few hundred feet, some of these core holes encountered substantial shows of natural gas, but their potential for gas production was not evaluated. No deeper wells have as yet been drilled on the islands to test the shoulders or flanks of these salt domes for natural gas or oil.
Subsequent tensional and compressive tectonic deformation has resulted in the formation of large structures along major fault events, some of which position the source-rich Macasty shale structurally below the Beekmantown reservoirs. Anticosti Island is well positioned in the oil and gas window, with the greatest potential for natural gas in the deeper reservoirs along the southern side of the island.
The Gaspe Peninsula also contains Anticosti basin carbonates of Ordovician age overlain by Silurian and Devonian sediments (mainly limestone) in the central part of the peninsula. Major thrust faulting occurs in the Ordovician, with the large Shick-Shock fault separating the thrusted Ordovician formations in the north from more gently folded Devonian/Silurian formations to the south. Most of the area has traditionally been considered "overly mature" or "cooked," but such assumptions are recently being re-thought in certain circumstances. A key challenge is the location of porous and permeable reservoirs with the Ordovician Beekmantown, Silurian Sayabec, and Devonian West Point formations offering the best prospects for reservoir development. Recent evidence for Silurian and Devonian reefs is encouraging companies exploring in this area.
The Magdalen basin is comprised predominantly of interbedded Carboniferous sands and shales sourced primarily from the Appalachian mountains located to the southwest. The marine Windsor formation is present throughout the basin and is comprised of limestone, sandstone, anhydrite, and salt. It separates the underlying Mississippian Horton (Albert) sand-shale sequence from the overlying Pictou/Riversdale sands and shales.
Structural features are generally either basement (fault) related in the Albert formation or result from Windsor salt deformation in overlying sediments. The Albert formation contains oil source-rich shales (lacustrine) that generated the hydrocarbons present in Stoney Creek field. Shales and widespread "coal measures" across the basin provide source rocks for natural gas reserves in the Riversdale and Pictou sands. In general, these sediments have been severely compacted through deep burial, significantly reducing porosities and permeabilities of the sands in this basin. Consequently, the higher mobility of natural gas relative to oil makes this basin comparatively a better candidate for gas development than for oil.
Wells were also planned in 1998-99 on prospects on Anticosti Island, Gulf of St. Lawrence, Gaspe Peninsula, southeastern New Brunswick, Prince Edward Island, and the Magdalen Islands.
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