11TECHNICAL SESSIONS
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TECHNICAL SESSIONS |
1. BASIN ANALYSIS IN OIL EXPLORATION
THE BRAZILIAN EXPERIENCE
F. U.H. Falkenhein (TRINTOC)
(November 1987)
"It is essential to spare those who lean towards what Lavorgen called "creative geology", the
trouble and the avalanche of routine work in which any of our leading geologists are too often bogged down. let
us remember that the future of an exploration company is founded on the competence of its geologists".
SCHNEEGANS, 1947.
"A society without risks and hence without responsibilities would be a society without hope and without a
future, and we as Economic Geologists take the risks and enjoy the benefits of these activities, because life is
either a daring adventure or nothing".
BAILLIE, 1983.
Basin analysis in oil exploration is the interpretation and integration of Stratigraphy (depositional systems,
vertical sequences, lithofacies distribution), Structural Geology (stress analyses, deformations, tectonic regimes,
structural maps), Paleontology (biostratigraphy and palaeoenvironmental studies), Geochemistry (thermal evolution
of organic matter), Geophysics (seismic stratigraphy and seismic expression of structural styles) and Sedimentology
(lithofacies, sedimentary structures, petrofacies and clay mineralogy), in order to understand the sedimentary
and tectonic evolution of a basin, and to identify prospective hydrocarbon accumulations based on the spatial
relationship of source rocks, reservoir rocks and traps
The exploration, production, transport and refining of oil and gas is a state monopoly in Brazil and has been executed,
since 1954, by Petroleo Brasileiro, S.A. (PETROBRAS), the only Brazilian oil company. PETROBRAS started in 1954
with a production of 14,000 bbls/day, inherited from previous oil companies, and mostly supported by government
agencies.
In 1970, Brazilian oil production reached 167,000 bbls/day, mostly from the onshore oilfields of the Reconcavo
and Sergipe-Alagoas basins, located in NE Brazil. In 1986, production reached 600,000 bbls/day (Fig. 3) with proven
reserves of 2 billion barrels, 70% of which is derived from offshore oilfields. In 1987, a very conservative figure
of 10 billion barrels of recoverable oil was estimated.
Offshore exploration in Brazil started in 1970, off the state of Sergipe, with the discovery of the Guaricema oilfield,
in about 30 metres of water.
In 1973, the Federal government decided to establish oil exploration through risk contract agreements with PETROBRAS,
in each of the 10 Brazilian sedimentary basins covering an area of about 3 million square miles.
At the same time, PETROBRAS decided to adopt 4 new strategies in exploration, in order to accelerate the understanding
of hydrocarbon accumulations in their basins and therefore effect a rapid production increase:
(i) simultaneous exploration of all sedimentary basins;
(ii) intense exposure of the exploration staff to foreign expertise;
(iii) hiring of some geologists with MS and PhD degrees from American universities, and
(iv) overseas joint ventures with foreign companies, by means of its new subsidiary, BRASPETRO.
This atmosphere created a highly favourable environment for intense basin analyses in PETROBRAS, which was the
main basis for PETROBRAS reserving only 20% of the Brazilian sedimentary areas for direct exploration. The remaining
80% of the sedimentary areas, available for risk contracts, were the targets of 56 inter-national oil companies,
which spent US$2 billion in 10 years and have drilled 31 wells to date. So far only one commercial discovery of
gas, offshore of the State of Sao Paulo, was the result of risk contracts and was achieved by PECTEN in 1985.
Basin analyses developed by PETROBRAS geologists led to the discovery of oil in turbidites of maturely explored
basins like Reconcavo and Sergipe-Alagoas, oil and gas in Paleozoic sandstones in the Amazon and oil and gas in
the Equatorial and southeastern offshore regions. The discoveries in the latter areas are presently adding 8 billion
barrels of recoverable oil to the country's reserves.
Brazilian sedimentary basins can be classified into 3 types:
(a) Paleozoic intraplate basins,
(b) Mesozoic intracratonic basins and
(c) Mesozoic oceanic or passive-margin basins.
Paleozoic intraplate types are the Amazon, Maranhao and Parana basins which comprise immense sags, overlying narrow,
deep linear Paleozoic rifts. Basement involved thrust belts, generated by Andean tectonism, affected the Upper
Amazon sediments and created the oil and gas prone structures of Jurua and Rio Urucu. These discoveries will double
the current reserves of gas and increase significantly the onshore reserves of oil in Brazil.
Most of the Middle Amazon Basin is presently under risk contract, being actually the largest sedimentary area in
the world under such an agreement. The operating consortium comprises 5 international companies which are currently
analysing the basin, after an intense seismic survey which was required in order to remove about 3000 metres of
basalt overburden on top of Permian reservoirs.
The two other Paleozoic basins, Maranhao and Parana, are being studied by PETROBRAS, although previous basin studies
condemned them due to lack of favourable structural developments and marginal geochemical criteria.
The Mesozoic intracratonic types comprise the maturely explored Reconcavo and Sergipe-Alagoas basins and consist
of the Brazilian counterparts of the African-Brazilian Neocomian triple junction rifts, which originated during
the opening of the South Atlantic. These specific basins subsequently evolved to Mesozoic oceanic basins, while
the rest of the Brazilian passive-margin basins originated during Aptian times. The most explored basins are Campos,
Sergipe-Alagoas, Rio Grande do Norte and Amazon Cone.
These passive-margin basins were formed by an initial basement tectonism which generated normal faulted blocks
and syntectonic deposition of continental clastic sediments. Late Aptian tectonic quiescence permitted the development
of thick, regional evaporites.
From the Albian onwards, these basins developed thick carbonate sequences which, since the late Cretaceous, were
interrupted by prograding clastic wedges.
The main hydrocarbon reservoirs these basins are pre-evaporitic (Neocomian and Aptian) sandstones, Albian-Cenomanian
calcarenites and Late Cretaceous and Tertiary turbidites which have reserves of at least 8 billion barrels of recoverable
oil in deep water (700 - 1000 m) in the Campos Basin (Albacora and Marlin fields). Here the source rocks for hydrocarbons
a predominantly pre-evaporitic shales.
The habitat of oil is not yet fully understood in the Santos and Espirito Santo basins where a different geothermal
regime, or less rifting, may has resulted in small oil and gas provinces.
In conclusion, basin analysis requires an understanding of many diverse geological specialties and an ability to
assess and integrate the relationships between various types of evidence. The skills to perform satisfactory synthesis
are rarely taught in any university or industry course an yet, as pointed out by Baillie (1979 are demanded by
the nature of the won performed by many professionals in the petroleum industry and by those engaged in regional
projects for government surveys.
A well executed basin analysis car ultimately help to establish the optimum policy to be adopted by country, in
order to best utilize its natural resources and rationalize their exploitation. In Trinidad, Trintoc geologists
are currently undertaking such an exercise in order to define the prospectiveness of this basin and hence to establish
an exploration programme.
2. OVERVIEW OF NATURAL GAS IN TRINIDAD AND TOBAGO
A. Russel (Trintoc) (March, 1988)
This is a very broad subject, but has been narrowed to 4 specific areas as follows:
(1) What is natural gas?
(2) location of Reserves
(3) Production and Transmission
(4) Uses and Demand
What is Natural Gas?
Natural gas is defined as hydrocarbons in the gaseous phase at system temperature and pressure. In nature, natural
gas exists associated with crude oil, i.e. in solution or as non-associated gas. Gas expansion is the major oil
expulsion mechanism in subsurface reservoirs and should be conserved for optimizing oil recoveries in black oil
systems. Reservoir types grade from black oil, to volatile oils, to rich condensates, to lean condensates,
to essentially dry gas systems. In Trinidad, there are reservoirs of almost all the types mentioned e.g. dry gas
(Mahaica, NCMA), lean gas (Gulf of Paria, Iguana), rich gas Pelican Field), volatile oils (Ibis Field), black
oils (most of Trinidad's oil fields).
Natural gas has been produced ever since oil was discovered by Colonel Darwent at Aripero Estate in 1866. The historical
development of the industry begins with the collection of land gas for running refining operations at Point Fortin
and Pointe-a Pierre.
High pressure gas production began with the discovery of the Penal gas condensate field during the early '50s.
The Penal gas was produced from turbiditic Herrera sandstones at intermediate and Underthrust structural levels,
as outlined by Bitterli in his 1958 AAPG publication. The reservoirs are fault separated and in some cases are
single well systems. Twelve wells were on production and gas production peaked at 58 MMSCF/D in 1972, declining
to approximately 2 MMSCF/D at present.
The reservoir type at Penal was a retrograde gas condensate system i.e. as pressure is reduced in the reservoir
over time, condensate drops out of the gaseous phase and with further depletion it re-evaporates.
The Penal gas condensate field was used to supply gas to T&TEC Power Stations at Penal and Port of Spain, Federation
Chemicals and other small industries, during the '60s and early '70s.
Gas sales contracts terminated during 1978 and 1979. Cumulative gas produced from the Penal Field totals 250
BCF. East Coast oil discoveries and subsequent production at Poui, Teak and Samaan fields offshore East Coast of
Trinidad led to high flaring of associated gas. By contract, the associated gas belongs to the Government of Trinidad
and Tobago (GOTT). The associated gas was brought ashore via 25 miles of 24-inch submarine pipeline from Teak and
Poui fields to Beach Field, Guayaguayare are and then via 23 miles of 24-inch buried line from Beach Field to Picton.
Pipeline capacity is 400 MMSCF/D at inlet supply pressure of 1000 psig.
At that time, all of the gas produced from East Coast fields was associated gas which either had to be flared after
separation from the crude oil or put into a pipeline system for transmission to shore. Since associated gas belonged
to GOTT, the necessary transmission network was installed by National Gas Company NGC) to reduce flaring off
the East Coast and provide fuel and feedstock to users on the west coast of Trinidad. in mid-1970s, Teak gas
production was marketed at rates of 35 MMSCF/D in 1974, increasing to 89 MMSCF/D by 1984.
In 1981, the GOTT published the 'White Paper on Natural Gas', which projected a declining oil production scenario,
with foreign exchange earnings being transferred from crude oil to natural gas. Policy and taxation matters were
also addressed.
NGC installed compressor platforms adjacent to production platforms at Amoco's Poui and Teak fields, to compress
low pressure natural gas which was unable to enter the high pressure trans-country pipeline. These facilities
alleviated wanton flaring of gas off the East Coast.
A second trans-country pipeline was installed in 1982 and consists of 42 miles of submarine 30-inch pipeline
from Cassia platform to Beach Field, Guayaguayare followed by 35 miles of buried 30-inch pipeline to Phoenix Park
via Rio Claro, at a cost of $200 million TT. Present day pipeline capacity totals 1 BCFJD, with total pipeline
investment of $475 million (TT) comprising $200 million (land) and $275 million (marine). Transmission cost
is estimated at US
$0.245/MCF.
Location of Reserves
Gas reserves published by the Ministry of Energy are of 2 types: associated and non-associated, and by categories
Proved, Probable and Possible (standard definitions adopted by SPE, API and other financial institutions).
Total reserves comprise 23.4 TCF (undiscounted), 16.44 TCF (discounted) and 9.44 TCF (proved). Seventy five percent
of current reserves are located off the East Coast, with 25% from the North Coast Marine Area.
Natural Gas Production and Transmission to Market
Development wells drilled for natural gas should be designed for: maximum safety under all conditions; maximum
gas/condensate production, minimum workover intervention (i.e. be as "permanent" as possible); and simple,
reliable and field proven technology.
Offshore wells require sub-surface safety control valves to be installed +/-500 feet below the mud line for fail-safe
shut-in, if the wellhead becomes damaged or is severed.
The reservoir is managed by measuring the static BHP and making a plot of P/Z versus cumulative gas produced.
This plot reveals the nature of the drive mechanism e.g. depletion drive or active water drive. If the abandonment
pressure is known, then the remaining gas reserves can be obtained.
Produced gas flows from the reservoir, through perforations into the well bore and up the tubing. For high gas
flows tubing restrictions should be removed to reduce pressure losses.
NGC has been designated the sole transmitter of natural gas and receives gas at the outlet manifold of the HP separator
- on land or offshore. NGC is responsible for installation of pipelines to the platform and enters into a 'Gas
Sales contract' with the producer.
Total gas production averaged 690 MMSCF/D in 1984, when Amoco produced 574 MMSCF/D, or 83% of the total (Fig. 4).
The importance of East Coast fields in gas production began in 1973 and dominated the gas supply market by 1978.
Total gas available to NGC is 375 MMSCF/D. The remaining gas is either used and vented or vented without utilization.
Uses and Demand
Third Quarter 1987 gas utilization can be summarised as follows:
* Oil Companies
- Field production via gaslift (200 MM/I)
- Production use including supply to instruments, gas blankets, fuel for burners, compressors, engines, gas pumps
and local domestic supply to houses, etc.
* Fertilizer
- Fedchem, Fertrin (164 MM/I))
* Urea
- 37MM(D
* Power generation
- T&TEC (107 MM/I))
* Cement manufacture
- 7MM/D
* Steel making
- 18MM/D
* Others
- 9MM/I)
Increased demand for gaslift by Amoco has reduced net gas available for sales. Marketing of increased supplies
of natural gas assumes: continuation of existing contracts, slow growth increase per annum (2-3%) in electricity
demand, new petrochemical plants - ammonia urea, etc; adequacy of gas reserves to meet future demand; and acceptable
gas pricing.
Projected demand shows an increase from 375 MM/D in 1987 to 577 MM/D by 1995 due to addition sales to new petrochemical
plants. However, marketing of natural gas depends on the viability of end products made by the petrochemical
plant ammonia, urea, and methanol.
World gas reserves currently stand at 2573 TCF proved), of which Trinidad contributes 9 TCF.
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