The Troll Story

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17110, “Success Factors in Troll Geosteering,” by S. Leiknes and I. Osvoll, Norsk Hydro ASA, prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission. Hydro has produced oil from horizontal wells in the thin oil layer of the Troll West field offshore Norway since 1995. The main challenge is to drain the thin target sands efficiently, within a remain-ing oil column less than 20 m thick covering an area of approximately 500 km2. New horizontal producers are continually being drilled. Vertical geosteering is performed on a centimeter scale, and quick decision making within the well teams is needed to optimize the well paths while drilling. Introduction The Troll field is the largest producing oil and gas field on the Norwegian continental shelf. The field is in the northern North Sea on the margin of the Viking graben and is divided by two major north/south trending faults separating the field into three provinces: Troll West oil province, Troll West gas province, and Troll East. Oil has been produced from horizontal wells in the Troll West oil and gas provinces where the initial oil-column thickness was 22 to 27 m and 11 to 13 m, respectively. More than 150 horizontal producers have been drilled in Troll West, and approximately two-thirds of the total oil reserves of 1.4 billion bbl has been produced. The oil column in Troll East is 1 to 4 m thick, and only the huge gas cap has been considered commercial. New horizontal producers are drilled in the progressively thinning oil layer. As shown in Fig. 1, well planning and drilling are increasingly difficult because of the ever-larger number of existing producers, the consequent decrease in remaining targets, and movement of the fluid contacts resulting from production. Collaboration between geophysicists, geologists, and reservoir and production engineers is crucial to meet this challenging task. Reservoir Framework The reservoir consists of stacked, off-lapping, shallow marine sandstones and intervening siltstones mostly in the Upper Jurassic (Oxfordian) Sognefjord formation. Reservoir zones correspond to the finer and coarser portions of the prograding wedges (parasequences) and can be mapped with good confidence over most of the field. For geomodeling and well-planning purposes, the depositional succession is simplified into clean sand and micaceous sands. The clean sands generally are well sorted, with permeabilities ranging from 1 to 30 darcies, while the micaceous sands are characteristically finer and silty, with permeabilities ranging from 10 to several hundred millidarcies.

Approximately 19.4 billion bbl of oil and 119 tcf of nonassociated gas have been discovered in the Mid-Continent as of January 1, 1978. Although these volumes of hydrocarbons were trapped in thousands of fields throughout the Mid-Continent, the bulk of these resources were emplaced in a relatively few fields: about 14.2 billion bbl of oil have been found in 111 significant and giant oil fields, and 103 tcf of nonassociated gas have been discovered in 57 significant and giant gas fields. Permo-Carboniferous reservoirs are important in 101 of the large oil fields and 55 of the large gas fields; these fields contained 9.5 billion bbl of oil and 99 tcf of gas, respectively. Our calculations of the total oil and gas accumulations in Permo-Carboniferous reservoirs are extrapola ed from these data. About 2.1 billion bbl of oil and 5.1 tcf of nonassociated gas accumulated in Lower Carboniferous (Mississippian) reservoirs. Most of this oil and gas was stratigraphically trapped in Upper Mississippian sandstones and carbonates which are truncated at the pre-Pennsylvanian unconformity surface. Approximately 8.8 billion bbl of oil and about 31.9 tcf of nonassociated gas have been found in Upper Carboniferous (Pennsylvanian) reservoirs in the Mid-Continent. Most of these oil and gas accumulations were stratigraphically trapped in lenticular sandstone bodies; the environments in which the majority of these sandstones were deposited range from fluvial-deltaic to shallow marine. About 2 billion bbl of oil and 77.7 tcf of nonassociated gas accumulated in Permian reservoirs. Most of these hydrocarbons accumulated in rocks of Lower Permian age in the Hugoton-Panhandle-Panoma fields. The oil and gas in these fields were trapped by regional changes in lithofacies with associated hydrodynamic gradients. Significant stratigraphic accumulations of oil and gas will continue to be discovered in the Mid-Continent even though much of this region is now in a late mature stage of exploration and development.

Syria is an important oil producer in the Middle East region with estimated hydrocarbon reserves of 2.5 billion barrels of oil and 8.5 trillion cubic feet of gas. Prospective areas of Syria with proven industrial oil and gas potential are the northeastern part of the Mesopotamia basin, the Euphrates graben, complicated by the Tual-abba-Sinjar uplifts system, the southern part of the Aleppo plateau and the Palmyra region. The Euphrates graben is located in Southeastern Syria with an area of about 90 x 160 km and is part of the fault system that arose in the Late Cretaceous. It is of great economic importance as one of the largest oil fields in Syria and contains the most important oil fields in Syria, where the estimated production reserves about 1 billion barrels of light oil with less quantities of natural gas. The Euphrates rift system can be divided into several structural elements: it is the deepest lower central element and an adjacent group of grabens surrounding the central depression of the Euphrates, and stable relatively elevated blocks. The main part of the gas and oil fields are located in the fields of Taym, Al-Ward, Teshreen and Al-Jibsa. In terms of oil and gas prospects in Syria, it is possible to distinguish the following areas: promising with proven industrial oil and gas potential; promising with direct signs of oil and gas; promising, but little studied; studied, but unpromising; unexplored. In the Euphrates graben there is a sufficiently large number of oil and gas source rocks and productive reservoirs, which indicates the presence of favorable geological factors that determine the prospects of oil and gas sedimentary cover in the Euphrates basin. The oil and gas potential of the Euphrates graben is associated with deposits of the Poleozoic, Triassic, Cretaceous, Paleogene and Neogene. The set of studies performed shows a favorable prospect for the discovery of new hydrocarbon deposits in the continental part of Syria.

The Troll Field is located on the northwestern margin of the Horda Platform,<br>approximately 80 km northwest of Bergen. The field is divided by two major northsouth<br>trending faults that separate the field into three provinces; Troll West Oil<br>Province (TWOP), Troll West Gas Province (TWGP) and Troll East, see Figure 1.<br>Since 1995 Norsk Hydro have produced oil from horizontal wells in TWOP and<br>TWGP, where the oil column is 22-26 m and 12-13 m, respectively.

This paper summarizes the technical findings of a regional assessment of oil recovery potential through advanced primary and secondary processes for reservoirs in Texas, Oklahoma, and New Mexico. Intensive infill drilling, polymer-augmented waterflooding, permeability profile modification, and selected combinations of these processes show significant promise for increasing recovery and sweep efficiencies in certain geologic reservoir settings. Given the current technical development and costs of these processes, their application could be feasible in a wide range of reservoirs in the region analyzed, even at oil prices below $20/Bbl. These advanced recovery techniques are all directed at producing unrecovered mobile oil (UMO), which is displaceable by waterflooding but remains in the reservoir at the conclusion of conventional production due to reservoir heterogeneity and unfavorable mobility differences between water and oil. The analysis, which was sponsored by the Department of Energy's Bartlesville Project Office and Office of Planning and Environment, evaluates nearly 500 reservoirs described in the data base. The data base, process predictive models, and analytical methodology used in the study are described in this paper. In addition, Important case study results and comparisons to published results for key reservoirs and other detailed analyses are discussed. The results indicate that UMO extraction has significant future potential to increase oil reserves and maintain domestic production. This potential is large even at low to moderate oil prices and utilizing existing technology. However, the key to maximizing UMO recovery is the development and wide-scale application of advanced techniques resulting from focused research and development (R&D).

At least 187 giant oil fields and 79 giant gas fields are known in the world today. Giant fields are those that contain 500 million bbl or more of recoverable oil, or 3.5 Tcf or more of recoverable gas, or an equivalent combination of gas and liquids which has a calorific value equivalent to 500 million bbl of oil. Altogether these fields contain an estimated, minimum ultimate recoverable reserve of 638.77 billion bbl of oil and 1,180 Tcf of gas or approximately 30-40% of the total known world recoverable gas. Most giant fields (190 = 71%) are in the Eastern Hemisphere; only 76 (29%) are in the Western Hemisphere; 81% of those in the Eastern Hemisphere (58% of the world's total) are in a U-shaped belt 10,000 km long and 750-1,300 km wide that extends from Algeria to the A ctic Ocean at the longitude of the Polar Urals. Giant accumulations show a distinct preference for certain geologic environments. Platform, semiplatform (parageosyncline), and platform-margin areas contain 83% (221 fields) of all giants; only 17% (45 fields) are in other geologic environments (e.g., fold belts, actively subsiding grabens, etc.). The numerous giant fields in platform-related areas suggests that giant fields are more likely to be preserved in tectonically stable environments. Of the reserves in giant oil fields, 58% are in sandstone and 42% are in carbonate reservoirs (an unusually large percentage of carbonate reservoirs are in the Middle East); of the reserves in giant gas fields 75% are in sandstone and only 25% in carbonate reservoirs. A total of 29% of the oil and 10% of the gas are in Tertiary strata; 63% of the oil and 65% of the gas are in Mesozoic beds; and 8% of the oil and 25% of the gas are in Paleozoic reservoirs. The abrupt increase in the number of giant fields in Mississippian and younger beds very possibly reflects the sudden proliferation during Late Devonian and Mississippian times of plant life in the terrestrial and, particularly, in marine environments. However, giant accumulations are not restricted to marine sediments. Of the 266 gi nt fields 6% (5 oil fields, 10 gas fields) are in rocks of nonmarine origin and 15% contain major oil and/or gas reserves of probable nonmarine origin. Giant hydrocarbon accumulations require (1) abundant organic source materials; (2) depositional and postdepositional environments suitable for accumulating, preserving, and converting the organic materials into mobile hydrocarbons; (3) efficient carrier beds; (4) voluminous and/or high-quality reservoir rocks; and (5) a giant trap, ideally syndepositional. Unconformities, though important in some fields, are not important in most. Geothermal gradient can be of importance in controlling the types of hydrocarbons present and their degree of mobility during migration. End_of_Article - Last_Page 341------------

E&P Notes (April 2022)

Throughout Permian time, eastern Colorado, like western Kansas, was on the shelf area of the Anadarko basin; and the Las Animas arch, as reflected on top of the pre-Pennsylvanian unconformity, was a south-trending nose in the north part of the Anadarko basin. This relation was very similar to that of the Central Kansas uplift, from which over 2 billion bbl of oil has been produced from pre-Cretaceous rocks. Many other geologic similarities can be discerned between the Las Animas arch and the Central Kansas uplift. The two most dissimilar factors are (1) that the pre-Pennsylvanian unconformable surface on the Central Kansas uplift is underlain chiefly by Cambro-Ordovician rocks, whereas on the Las Animas arch, Mississippian rocks underlie most of the area; and (2) that the dip of the pre-Permian beds in northeastern Colorado was reversed during the Laramide orogeny. The entire pre-Pennsylvanian sequence in eastern Colorado and western Kansas demonstrates a very subnormal but continuous pressure system. Over most of eastern Colorado, the Mississippian is the porous and permeable stratigraphic unit of this very low-pressure system. Fluids will migrate from the higher energy Pennsylvanian system to the lower energy Mississippian. Thus, the Mississippian is capable of deriving hydrocarbons transversely as well as laterally. Since 1965, exploratory interest has been primarily in Mississippian reservoirs, although some Pennsylvanian oil and gas fields also have been found. Since 1965, 20 Mississippian and Pennsylvanian oil and gas fields have been found and over 200 wildcat wells have been drilled. The data from these wells have resulted in new interpretations of hydrocarbon accumulations. Early Pennsylvanian growth strongly influenced Mississippian accumulations, and recent refinements in seismic techniques have allowed definition of these growth features. By incorporating recent subsurface interpretations with the extensive seismic control available, numerous prospects are being defined and doubtless will result in additional pre-Cretaceous discoveries. End_of_Article - Last_Page 660------------

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112616, "Troll West Oilfield Development-How a Giant Gas Field Became the Largest Oil Field in the NCS Through Innovative Field and Technology Development," by Richard Dyve Jones, StatoilHydro, and Erland Saeverhagen, SPE, Arve K. Thorsen, SPE, and Sveinung Gard, SPE, Inteq, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed. The Troll West oil field has been developed with more than 110 horizontal subsea wells including 53 multilateral (ML) wells. The thin oil rim was developed through extensive use of multilateral drilling and wells containing up to 7 horizontal branches. The process of drilling the ML wells and the benefit/risk evaluation for the ML process are discussed. Introduction The Troll field is offshore Norway on the Norwegian Continental Shelf (NCS) in 300-m water depth, as shown in Fig. 1. The field was discovered in 1979 and covers an area of 750 km2. Drilling of the production wells began in 1994, and production began September 1995. Oil production to September 2007 was 188.3×106 m3 of oil, all from horizontal wells. The 250 horizontal sections have drilled 900 000 m, including 560 000 m of reservoir section. Field Description and Challenges Gas and oil are found mainly in the Sognefjord formation and in the underlying Fensfjord formation. The oil in the Troll West is from a 22- to 26-m thick oil column under a small gas cap. In the Troll West gas province, there is a 12- to 14-m-thick oil column and a gas column up to 200 m thick. The Troll reservoir sands are of two distinct types, with large grading between. The C sand is a clean coarse sandstone, with permeability ranging from 1 to more than 10 darcies. The M sand is micaceous, with a finer grain size than the C sand, and, in general, has permeabilities in the range of 1 to 100 md. The sorting in this sand is poorer than in the C sand; therefore, the permeability is less. Recovery Strategy. Oil production is through long horizontal wells drilled just above the oil/water contact (OWC) in the thin oil zone. The main recovery strategy is pressure depletion, but with simultaneous expansion of the gas cap above and the water zone below the oil. In the Troll West oil province, some of the gas produced has been injected back into the reservoir to optimize the oil production. One important aspect is to recover the oil quickly, because less oil can be extracted when the pressure declines in Troll East. Therefore, limits were placed on gas extraction from Troll East.

Hibernia is the pioneer development for the emerging Canadian east coast offshore oil industry. As the first operator in this area, the Hibernia Management and Development Company Ltd. (HMDC) is developing local skills and infrastructure which can support future developments. The Hibernia field is located 315 kilometres east southeast of St. John's, Newfoundland. It consists of two reservoirs - the Avalon and the Hibernia reservoirs, located at average depths of 2400 metres and 3700 metres respectively. Containing approximately three billion barrels of oil in place, Hibernia is the fifth largest discovered oil field in Canada. Recoverable reserves are estimated to be 615 million barrels. Limited data is available on the Avalon reservoir at this time, and initial drilling activity is expected to identify significant reserves upside. A fixed drilling and production platform is being assembled in Newfoundland to produce the field. Its design includes a first-of-its-kind concrete Gravity Base Structure, which has a 15 metre thick ice belt that can withstand the impact of multi-million tonne icebergs. The completed platform is scheduled to be towed to its offshore location in June 1997, with first oil expected in December. The platform has a design production capacity of 150,000 barrels of oil per day. Average production of 135,000 barrels of oil per day is expected during the 6 year plateau period. Other discoveries around Hibernia offer the opportunity for subsea tiebacks for processing and storage of crude in the future. Hibernia has a pre-production budget of US$4.4 billion, and total development costs are estimated to be US$8.0 billion, excluding transportation costs. Introduction The waters off the east coast of Newfoundland are host to 16 undeveloped oil fields containing estimated recoverable reserves of 25 1 million m3 (1.6 billion barrels). The area also contains an estimated 234 billion m3 of gas, and 58 million m3 of natural gas liquids1. With oil in place estimated at 477 million m3 (three billion barrels) and recoverable reserves of 98 million m3 (615 million barrels), Hibernia is by far the largest discovery offshore Canada to date. In fact, it is the largest undeveloped oilfield in Canada, and by the turn of the century is expected to produce approximately 10% of Canada's light crude oil production. Once Hibernia begins production in December 1997, it will be leading the development of a new offshore oil industry for Canada. However, one field does not constitute an industry. In order for an industry to evolve, Hibernia has to prove that it can compete with similar operations by achieving its goal of top quartile industry performance in relation to the North Sea. This goal is achievable but will present challenges, especially in the area of platform support costs. Using present day technology, it will take 18 years todeplete the estimated 98 million m3 (615 million barrels) of recoverable oil from the Hibernia field.

AAPG Bulletin, March 1979, v. 63, no. 3, p. 511. Corrected abstract by Richard B. Powers. POWERS, RICHARD B., U.S. Geol. Survey, Denver, Colo. Resource Appraisal Predictions and Exploration Performance--Case Studies for Onshore United States Geologic estimates of undiscovered recoverable oil and gas resources in the United States were published in U.S. Geological Survey Circular 725 in mid-1975, based on data through 1974. In the 1975 study, 47 onshore provinces, included within 11 regions, were evaluated. Three of these geologic provinces, (1) West Texas-Eastern New Mexico, (2) North Slope, Alaska, and (3) the Overthrust belt of Idaho-Utah-Wyoming, were selected as case studies to show the relation between the 1975 resource assessments and subsequent exploration results. U.S. Geological Survey resource estimates for the maturely explored West Texas-Eastern New Mexico province range from 4 to 14.4 billion bbl of oil and 35 to 100 Tcf of gas, based on the 95% and 5% probability percentiles. Exploration wildcat drilling from 1975 through 1977 resulted in more than 417 oil and gas discoveries, mainly of small field size. Exploration results in this province, based on finding-rates and the amounts of oil and gas discovered, do not appear to have met the resource predictions. Resource estimates for the immaturely drilled North Slope province range from 5 to 16 bbl of oil and 14 to 49 Tcf of gas. About 30 wildcats were drilled from 1975 through 1977, resulting in 3 successful oil or gas wells. Two oil discoveries appear to be in the >50 million-bbl field-size (A class). Resource predictions appear to have been met or exceeded for the North Slope, based on this recent exploration performance. Estimates of resources for the Overthrust belt, the most recently successful of the three provinces, range from 0 to 0.2 bbl of oil and 0 to 1.1 Tcf of gas. Thirteen gas and oil fields were discovered out of 64 total wildcats drilled from 1975 through 1978; at least five of which are estimated to be of A field-size class or greater. Exploratory performance to date has exceeded the earlier resource estimates in the Overthrust belt. End_of_Article - Last_Page 1148------------

For 50 years a principal Gulf of Mexico frontier has been exploration in water deeper than the deepest existing platform. Progress was steady but not always smooth. Selected historical highlights provide some of the story behind the progress. A pattern of leasing in deeper water than drilling and drilling in deeper water than production is illustrated by plotting the extent of leasing, drilling, and production on maps for each decade from the first oil discovery in 1938. By 1988, leasing has reached 9,300 feet of water, drilling has reached 7,520 feet of water,, and production has reached 1,025 feet of water soon to be extended to 1,760 feet of water. Industry action appears to be fueled more by guest for reserves than by current or near term economics or politics. Successes have resulted from optimism, technical advances, and a favorable political climate. Failures have resulted mostly from industry's exploring of the high risk very high reserve prospects. Over 11 billion barrels of oil and 130 trillion cubic feet of gas have been discovered in the United States waters of the Gulf of Mexico, and half again more may remain to be discovered. Through 1985, value of oil and gas sold was $166.46 billion. The United States has received $67.85 billion in bonus, royalty, and delay rentals. The challenge is to fully explore the Gulf of Mexico. Many of the circumstances facing' the industry in the 1980's are not dissimilar to those that faced the industry in the 1940's. INTRODUCTION For 50 years, oil and gas exploration into deeper and deeper waters of the Gulf of Mexico has been fueled by optimism. Optimism that large accumulations of oil and gas are there to be found; optimism that earth science, drilling, and producing technology could find and produce the oil and gas, and finally, optimism that cash income at the time of production and 20 to 30 years thereafter would be ample to cover investments and have some left over to keep the program going. Exploration in federal and state waters has resulted in the discovery of over 11 billion barrels of oil and 130 trillion cubic feet (TCF) of gas (Forrest, 1986). About 7 billion barrels of oil and 80 TCF gas have been produced, leaving proved reserves of about 4 billion barrels of oil and 50 TCF gas. Risotto and Collins (1986) estimate economically recoverable undiscovered reserves (risked mean oil resource) to be 6.03 billion barrels of oil and 59.64- TCF gas. Their five per cent probability estimate for undiscovered reserves is 11.90 billion barrels of oil and 121.87 TCF gas, which provides a range within which most prognostications fall. Through 1985, the total value of oil, condensate and gas production when sold from the Gulf of Mexico Outer Continental Shelf (OCS) was $166.46 billion.

Sixteen oil and gas fields have been discovered and developed along the western margin of the South Viking Graben in Quadrant 16 of the United Kingdom Continental Shelf. Late Jurassic extension created the graben, and submarine fan conglomerates and sandstones along its margin form most of the fields’ reservoirs. In the early 1970s, 2-D seismic was able to identify structures beneath the Base Cretaceous unconformity, which became the targets for initial drilling. The first well was Shell’s 16/8-1 in 1972, drilled toward the graben center. This well found hydrocarbons in interbedded sandstones and shales later developed as the Kingfisher field. Drilling in the more proximal Brae Formation conglomerates began in 1974 when 16/7-1 discovered the North Brae gas condensate field. However, an appraisal well to the south found an oil column, and this subsequently became Central Brae field. In 1976, drilling on another submarine fan two blocks to the south discovered the Thelma field. However, the key to developing the area was the discovery of the world-class South Brae oil field in 1978. This was rapidly appraised in the next two years and the Brae A platform was installed, with first oil produced in 1983. Meanwhile, the compulsorily relinquished portions of Blocks 16/7 and 16/8 were awarded to BP and Conoco, respectively, who discovered the Miller field extending across the block boundary in 1982. A further four platforms have been installed in the area: Brae B on North Brae, onstream in 1988; Miller in 1992; and East Brae and Tiffany in 1993. A further 12 fields have been developed by subsea tieback or by extended reach drilling. A billion barrels of oil and 7 tcf of gas have been produced from these fields.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191574, “Delivering Drilling Automation II: Novel Automation Platform and Wired Drillpipe Deployed on Arctic Drilling Operations,” by Riaz Israel, Doug McCrae, Nathan Sperry, Brad Gorham, Jacob Thompson, and Kyle Raese, BP, and Steven Pink and Andrew Coit, SPE, NOV, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. This paper presents a case history of drilling automation system pilot deployment, including the use of wired drillpipe, on an Arctic drilling operation. Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig’s drilling control system. The second component was a wired drillstring, which provides high-speed delivery of downhole data from a series of distributed downhole sensors. Introduction In an effort to enhance the safety of its operations, improve well construction efficiency, and leverage the potential opportunities presented by digitalization of drilling, the operator has initiated a Remote Operations and Intelligent Automation Project. The project involved the deployment of an automation operating system (AOS) on top of an existing drilling control system. The AOS provides the ability for secure, programmatic control of the rig’s major drilling hardware through the use of software. The software interface allows for custom configuration of several routine drilling activities for automated execution. The project also evaluated the latest version of the service company’s wired drillpipe (WDP). At the time of writing, the project has delivered eight wells, with various combinations of the technology implemented. The overall objectives of the project were to evaluate The readiness of the AOS for wider deployment The reliability of the latest version of WDP The maturity of the AOS drilling applications The effectiveness of this technology in reducing well costs For each well, key performance indicators (KPIs) were defined that aligned with the project-level KPIs and are dependent on the specific aspect of the technology being used on that well. Field Description The giant Prudhoe Bay field, on the North Slope of Alaska on the edge of the Arctic Circle, was discovered in 1968 with an initial estimate of 22 billion to 25 billion bbl of oil in place and has been in production since June 1977. Since the field began production, it has generated more than 12.5 billion bbl of oil, making it the most productive US oil field. The field has been a proving ground for advanced drilling techniques, including multilateral and coiled tubing, now used in oil fields around the globe. Production from Prudhoe Bay is supported by ongoing drilling activity. Technology Description An overview of the automation technology is presented in Fig. 1.

Sub-Andean Peru comprises the Maranon, Ucayali, and Madre de Dios basins which, together with three subsidiary basins, cover an area of 370,000 km2. These basins extend considerable distances northward into Ecuador and Colombia and southeastward into Bolivia. More than 5 billion bbl of recoverable oil have been discovered in these basins, of which over 1 billion bbl of oil and almost 7 tcf of gas are in Peru. The Tertiary foreland basins in front of the Eastern Cordillera are filled with up to 4 km of Tertiary molasse sedimentary rocks. The basins are mainly of Miocene age and overlie older Paleozoic and Mesozoic depocenters. Three major compressional episodes are recognized: a Middle Triassic event, an Early Cretaceous event associated with major unconformities in some areas, and a regionally pervasive late Miocene-Pliocene (Quechua III) event expressed in thrusting and compressional folding over most of sub-Andean Peru. Two families of oils are differentiated in the Maranon basin, related to Permian and Cretaceous source rocks. Three groups of oils in the Ucayali basin derive from Devonian, Carboniferous, Permian, and Triassic sources. Oil samples in the Madre de Dios basin correlate to Devonian and Carboniferous shales. A variety of trap types have been identified. The foreland can be divided into areas where preexisting faults have been reversed by late Tertiary compression and flexural uplift, and areas unaffected by this deformation where older, more subtle traps are important. To the west, the sub-Andean belt comprises regions where basement-involved thrusts predominate and other areas characterized by thin-skinned thrusting. The Oriente-Maranon-Ucayali basin complex has at least one large hydrocarbon accumulation in each trap type. The level of exploration is low, and many areas are virtually unexplored.