Oriente Basin Research Articles

Aspects of the petroleum geology of the Oriente Basin, Ecuador

Abstract The Oriente Basin of Ecuador is one of the most productive of the South American Sub-Andean Basins. Cumulative production of oil to the end of 1986 was over one billion barrels, and current production stands at approximately 300 000 barrels per day. At least 20 oil fields have been discovered to date, including five giant fields, and exploration is currently in the early stages of a new and already successful phase in which ten new operators are scheduled to drill over 40 wells between 1985 and 1992. The Oriente Basin contains a sedimentary fill of Palaeozoic to Recent age. Major commercial interest is confined to the Cretaceous depositional cycle and all of the significant production comes from fluvio-deltaic and marine sandstones of the Hollin and Napo Formations. Most of the productive structures are low-relief, north-south orientated, anticlines of two distinct types: foot wall anticlines associated with normal faults, (Type 1) or hanging wall anticlines associated with reverse faults, (Type 2). Evidence points to the importance of pre-Miocene structural growth, comprising either early-mid Cretaceous rejuvenation of pre-Cretaceous ‘basement’ faults in the case of Type-1 structures and ‘Early Andean’ (latest Cretaceous to Oligocene) compression in the case of Type-2 structures. Few commercial discoveries have been made associated with ‘Late Andean’ (Miocene-Pliocene) compressional structures, essentially because these structures appear to post-date the main phase of primary oil generation and migration. The origin of the oils is problematical because the potential source rocks, the marine claystones and limestones of the Cretaceous Napo Formation, are generally immature or marginally mature within the confines of the present-day Oriente Basin. Oil analyses indicate a single family of oils. Available evidence, combined from structural and geochemical data, supports a major phase of Early Andean age oil generation and migration. There is a considerable variation of oil type from 37° API paraffinic oils with a GOR of 250–300 to altered 10° API oils. Marked variations exist not only between oilfields but also between reservoirs in the same well. The observed trends can in most cases be accounted for systematically in terms of: early primary oil generation, migration and entrapment; and subsequent structural evolution locally involving the processes of biodegration, water washing and/or flushing, and oil remigration.

Petroleum Geology of Heavy Oil in the Oriente Basin of Ecuador: Exploration and Exploitation Challenge for the 1990s: ABSTRACT

Published Ecuadorian government forecasts suggest that Oriente basin light oil (21-32{degree} API) production may start to decline in the early to mid-1990s. To maintain stabilized production into the next century, heavy oil reserves (10-20{degree} API) will have to be aggressively exploited. The Oriente's undeveloped proven plus probable heavy reserves are substantial and are expected to exceed 0.5 billion bbl. A recent discovery made by Conoc Ecuador Ltd., operator of Block 16 for a group which consists of O.P.I.C., Maxus, Nomeco, Murphy and Canam, is a good model for future exploration and exploitation of heavy oil in the remote eastern regions of the basin. Amo-1 tested a low-relief anticline (less than 100 ft vertical closure) and encountered 10-20{degree} API oil in five Cretaceous sandstone reservoirs (8,000-10,000 ft depth). Cumulative test production was 1,062 BOPD. Subsequent drilling along the trend resulted in three additional discoveries. The Cretaceous sands were transported from the Brazilian shield by the westward flowing proto-Amazon River and were deposited in fluviodeltaic, tidal, and high-energy marginal marine environments. Air permeabilities are high and geometric mean values approaching several darcies. Porosities average 18-22% in generally well-consolidated sands. The heavy oils are the result of mild biodegradation and/or expulsion from amore » thermally immature source. Oil-to-oil correlations suggest that all of the basin oils have the same or similar origin, probably marine calcareous shales of the Cretaceous Napo formation. The Block 16 project will provide a major step toward the strategic exploitation of the Oriente basin's heavy oil reserves, when it comes on stream in the early 1990s.« less

Age of the Payogastilla Group: Implications for foreland basin development, NW Argentina

The Corte El Cañón Tuff from the lower part of the Angastaco Formation, Payogastilla Group, NW Argentina, was dated at 13.4±0.4 Ma by the 40Ar/ 39Ar method. The Payogastilla Group was deposited in an Andean foreland basin, includes strata associated with the development of the modern arc, and is now exposed in the southern Cordillera Oriental. To date, the Payogastilla Group has been correlated with the Saladillo Formation/Santa María Group sequence that is exposed immediately to the south in the northern SierrasPampeanas. The date of the Corte El Cañón Tuff shows that as much as the lower third of the Payogastilla Group strata is older than the oldest Saladillo Formation/Santa María Group strata. This suggests that the region of the northern Sierras Pampeanas was topographically higher than the region of the southern Cordillera Oriental when foreland basin deposition began. It may also suggest that the eastward progression of Andean deformation was more rapid at the latitude of the Cordillera Oriental than at the latitude of the northern Sierras Pampeanas.

Regional Variations in Formation Water Salinity, Hollin and Napo Formations (Cretaceous), Oriente Basin, Ecuador

Salinity concentrations of formation waters in Cretaceous reservoirs of the Oriente basin of Ecuador range between 500 and 130,000 ppm NaCl equivalent. These values conform to salinity gradients detected within and vertically between stratigraphically discrete sandstones. Well logs and drill-stem test data document a consistent pattern of increasing salinity from east to west within individual sandstones and vertically from deeper to shallower sandstones. A model describes the hydrodynamic flow of meteoric water entering the basin through elevated and exposed section to the west, with expulsion occurring along the basin's eastern shallow rim. The outcropping Hollin sandstone at the base of the Cretaceous section provided the only passage through which meteoric water could have initially entered the buried section. This freshwater-bearing sandstone is the source for fresh water within the younger Cretaceous sandstones of the Napo Formation. Connate fluids associated with these younger sandstones were increasingly displaced vertically and to the east where the entire Cretaceous section thins and the sandstones merge into a single column. This zone of merger is the principal vertical pathway for fluid communication between older and young r sandstones and explains the lateral and vertical gradients observed from salinity maps and electric-log profiles.

First-Cycle Quartz Arenites in the Orinoco River Basin, Venezuela and Colombia

Modern first-cycle quartz arenites are forming in the Orinoco drainage basin by at least two distinct mechanisms. Common to both mechanisms is an environment of intense chemical weathering and extended time over which weathering can occur. In the Llanos (Andean foreland basin), extended time is provided by temporary storage of orogenically derived sediments on extensive alluvial plains. In lowland portions of the Guayana Shield, long soil mineral residence times are produced by very low erosion and transport rates, resulting from low relief and tectonic quiescence. Both weathering intensity and the duration of weathering are important in the modification of sand composition. First-cycle quartz arenites are produced in diverse tectonic settings and cannot be used by themselves to infer paleotectonic settings of ancient sequences. Furthermore, although tectonic setting is of great importance in determining sand composition, modifications during transport and deposition can overprint the effects of the tectonic regime. In extreme cases, such as first-cycle quartz arenites, the tectonic signal may be virtually obliterated. Many criteria used in the past to discriminate between first-and multi-cycle quartz arenites are invalid when applied to the quartz arenites of the Orinoco drainage basin. At present, the only unambiguous criterion is that the presence of sedimentary lithic fragments and syntaxial quartz overgrowths is clearly indicative of a multi-cycle origin for at least one component of a sand.

Geological Model for Oil Gravity Variations in Oriente Basin, Ecuador: ABSTRACT

Geological Model for Oil Gravity Variations in Oriente Basin, Ecuador: ABSTRACT

Cross‐channel mixing and its effect on sedimentation in the Orinoco River

At high discharge, cross‐channel mixing of water in the Orinoco River main stem requires several days and up to 500 km of downriver transit for completion. During mixing, substantial amounts of < 0.063 mm sediment are lost from suspension. The water closest to the left bank appears to lose the most, probably by deposition onto the floodplain. This occurs in two ways. First, sediment‐laden left‐bank tributaries draining the Andes, such as the Apure, deposit sediment in distributary systems following impoundment by the Orinoco backwater. Second, when sediment‐laden waters from the Andes actually join the Orinoco, the slow nature of cross‐channel mixing causes the water and sediment to be confined more to the left side of the channel. Significant sediment loss or storage probably occurs only near flood stage. Since sedimentation occurs preferentially on the left (Andean foreland basin) bank, the Orinoco remains stably situated on the border of the foreland basin with the Guayana shield.

Oil and Gas Developments in South America, Central America, Caribbean Area, and Mexico in 1986

Exploration activity in South America, Central America, the Caribbean area, and Mexico in 1986 was considerably reduced compared to 1985. Brazil, Colombia, Ecuador, Guatemala, and Venezuela had increased oil production, with Colombia showing a dramatic 71% increase attributed mainly to bringing on-stream the pipeline connecting Occidental-Shell-Ecopetrol's Cano Limon complex to the port of Covenas. Significant discoveries were reported from Argentina in the Olmedo, Oran, and San Jorge basins; Brazil in the offshore Campos and Amazon basins; Colombia in the Llanos basin; Ecuador in the Oriente basin; Mexico in the Bay of Campeche; Peru in the Ucayali basin; and Venezuela in the Eastern Venezuela basin. Eastern Venezuela's Furrial discovery is reported to have recoverable r serves of more than 1 million bbl of oil, and Shell's Ucayali basin discovery is reported to hold more than 7 tcf of gas.

Stable carbon isotopes and biomarkers as tools in understanding genetic relationship, maturation, biodegradation, and migration of crude oils in the Northern Peruvian Oriente (Maranon) Basin

The geochemistry of 15 oils produced from the Cretaceous Vivian and Chonta formations in the Northern Peruvian Oriente (Maranon) Basin was studied. This study demonstrates the usefulness of both stable carbon isotopes and biomarkers in understanding genetic relationships (source), maturation, biodegradation, and migration of oils. Specifically, using stable carbon isotopes and statistical factor analysis, two groups of genetically different oils were identified in the northern Oriente (Maranon) Basin. The Chonta Formation is the reservoir for one group while the other is exclusively contained in the Vivian Formation. Both oil families seem to be derived from a marine organic source which had some terrigenous organic input. The presence of demethylated hopanes in somme of the Vivian oils indicates that these oils have been severely biodegraded in the past by meteoric water influx. Breeching of the Vivian Formation to the North, shortly after accumulation at the Cretaceous-Tertiary boundary, allowed the penetration of the meteoric water. Biodegration stopped in early Tertiary when the Vivian unconformity was covered with impermeable red beds. Following this, a secondary pulse of nondegraded Vivian-type oil has reached some of the biodegraded Vivian reservoirs. The secondary pulse was identified by the presence of n-paraffins in the biodegraded oils, and stable carbon isotopes aided in identifying the source of this later oil. This secondary pulse may have been triggered by a southern tilting in Eocence time or by the differential subsidence of the basin that resulted from the rising of the Andean Mountains (with major movements in Miocene time). Using this iormation, it was concluded that the distribution of biodegraded oils in the Vivian Formation reflects the extent to which fresh water has penetrated the subsurface. The distribution of reservoirs with a secondary pulse was controlled by the availability of reservoirs filled with nondegraded oil in the direction from which the secondary migration originated, the size of the pulse, and the distance it has migrated. variations in the salinity of the Vivian Formation waters are likely the result of replacement of the meteoric waters (that caused biodegradation) by highly saline formation waters originating in deeper parts of the basin. Using steranes and triaromatic steranes, it was found that the Chonta and Vivian oils were generated from mature source rocks (triaromatic steranes indicate that the maturity of the source was equivalent to vitrinite reflectance of approx. 1.0–1.35%). Because of the low maturity (and low organic content) of rocks in the neighborhood of the reservoirs, it was concluded that the oils was generated and migrated most probably from the west in what is now the Andean Mountains. Because of the time constraints put by the biodegration event in the Vivian Formation, most of the migration of the early oils must have been completed by late Cretaceous. During the time span required for the first migration, the maturity of the source rocks of the oils increased from vitrinite reflectance 1.0 to -1.35%. The mode of accumulation in the basin was generally from west to east with the more recent and more mature oil replacing the earlier and less mature oil in the reservoir. The earlier oil continued then to migrate to the east, accumulating in the next reservoir.

Oil and Water Production in a Reservoir With Significant Capillary Transition Zone

Summary Analytical and numerical methods are used to investigate the mechanism of water production in a high-permeability sandstone reservoir that has a capillary transition zone height comparable to formation thickness. Production rates are well above those for transition-zone water production alone. Consequently all wells are affected production alone. Consequently all wells are affected by coning shortly after the start of production. It is found that water cut is largely insensitive to total fluid production rate for the same recovery. The depth of well penetration and the effect of radial capillary pressure gradients are shown to be of secondary importance pressure gradients are shown to be of secondary importance in these circumstances. The predictions are confirmed by the results of a long-term pilot production test. Introduction This paper considers the mechanism of water production in a highly permeable sandstone reservoir with a 22API [0.9-g/cm3] under saturated oil and a strong edge aquifer drive. The findings are drawn from a study recently performed on the M-1 Sand reservoir of the Fanny field, performed on the M-1 Sand reservoir of the Fanny field, which is located on the eastern flank of the Oriente basin in Ecuador. M-1 Sand belongs to the Napo formation of the Cretaceous Age and consists of moderately to poorly cemented quartzose sands of high permeability. Reservoir depth is approximately 7,700 ft [2347 m]. A characteristic feature of the reservoir is the wells' predisposition to develop substantial water cuts after predisposition to develop substantial water cuts after short periods of production. Attempts have been made in the past to reduce water production by squeeze cement jobs and recompletions. However, these operations have not been effective but for the very short term and consequently the study has concentrated on attempting to define the nature of fluid movement within the drainage area of the wells. Reservoir Description M-1 Sand shows lithological features characteristic of a fluvial channel depositional environment. These features are exemplified by the Induction Electrical Survey of Well 18-B-2 (Fig. 1), which shows a basal unit 45 to 55 ft [14 to 17 m] thick, overlain by a variable number of smaller units that are separated by shale breaks and tight streaks. These upper units are of poor quality and limited lateral continuity. In contrast the basal unit contains no correlatable shale breaks although thin shales were encountered in some wells and early completion practices attempted unsuccessfully to make use of them. Because of this early experience and the absence of correlation it has been concluded that such shale breaks are of limited lateral extent and do not contribute materially to the prevention of water-cone development. prevention of water-cone development. The basal unit contains more than 90% of the original oil in place, estimated at 48 × 10(6) STB [7.6 × 10(6) stocktank m3]. Currently all wells are completed in this unit, which has provided all production to date. The upper units have been neglected for the purposes of this paper. The structural configuration of the reservoir is a faulted asymmetrical anticline of low structural amplitude. Fig. 2 represents the structure on top of the basal sand unit and shows the intersection of the oil/water contact (OWC) with this surface, giving rise to a maximum oil column of 65 to 70 ft [20 to 21 m]. A comparison of sand thickness with oil column height indicates that the base of the sand is everywhere close to the OWC and that all wells have high basal water saturations. Pressure support is by edge aquifer influx, but with strong underrunning giving behavior characteristic of a bottom aquifer. Reservoir and Fluid Properties The basal unit is variable in quality but characterized by high porosity and permeability averaging 20 to 25% and 2 to 3 darcies, respectively. Figs. 3 and 4 are capillary-pressure and relative-permeability curves representative of the basal unit. These curves are typical of a sandstone that contains large, well-interconnected pores. Sands of this unit are generally poorly cemented and friable. No fractures are evident from either cores or logs. There is no evidence of any fracture-induced effects on pressure buildup data, which correspond to a single permeability intergranular system. Average oil and water fluid properties are presented in Table 1. The oil and water viscosities at reservoir conditions are 12 and 0.35 cp [12 and 0.35 mPas] respectively, which give a very unfavorable endpoint mobility ratio. The displacement of oil by the encroaching aquifer is thus an unstable displacement and the strong underrunning of water quickly results in high producing water cuts in the wells. JPT P. 1559

Significant Features of Oil Occurrence in the Oriente Basin, South America

Significant Features of Oil Occurrence in the Oriente Basin, South America

Hydrocarbon Potential of Amazon Basins of Colombia, Ecuador, and Peru: ABSTRACT

The Oriente, Ucayali, and Madre de Dios basins in the Amazon drainage of Colombia, Ecuador, and Peru are members of a series of large asymmetric depressions between the Andean cordillera and the Guiana and Brazilian shields. They are separated from one another by basement arches and have areas of 458,000, of 200,000, and of 95,000 sq km, respectively. The area is topographically low, covered by heavy rain forest, traversed by many huge tributaries of the Amazon and is sparsely populated. From early Paleozoic time until the Maestrichtian, seas repeatedly invaded the area, depositing a variety of sediments, but mostly calcareous and silicate clastic deposits. At the beginning of the Tertiary, dominantly marine deposition gave way to nonmarine deposition, reflecting the Andean orogeny and topographic development of the Andes Mountains. The depositional cycle of major importance for hydrocarbons took place in the Cretaceous. A complete marine cycle of miogeosynclinal sedimentation is represented with a maximum thickness of 2,500 m, but it thins and becomes sandier toward the east. Although the cycle consists mainly of sands and shales, limestones and sandy limestones are important potential reservoirs. Most prospective structures in the basin are anticlines, generally fau t-bounded and steeper on the east. Salt domes and other diapiric structures are also present. Amplitude of structures and intensity of deformation decrease eastward. The formation of structures and the migration and entrapment of hydrocarbons appear to have occurred at various times in the Tertiary. The state of exploration in the Colombian part of the Oriente basin is well advanced with low-undiscovered potential. In Ecuador, although the peak of exploration activity has been passed, the future potential may be substantial. In Peru exploration drilling in the Oriente basin already has discovered reserves on the order of 400 million bbl of oil. On the basis of these facts and on information from Colombia and Ecuador, the total potential of the Oriente basin is estimated to be 25 to 35 billion bbl. About 20 wildcats have been drilled in the Ucayali basin with the discovery of two small oil End_Page 1463------------------------------ fields and an undeveloped, but potentially large gas field. From these results, and estimates for the Oriente basin, the Ucayali basin has an estimated potential of 5 to 10 billion bbl. In addition, Paleozoic sediments also have some potential. Favorable conditions are known to exist and oil seeps are present in the Madre de Dios basin, the least known of the three. A potential of 3 to 8 billion bbl is estimated. The total estimated potential for the three basins is about 40 billion bbl. End_of_Article - Last_Page 1464------------