ABSTRACT Pikka field is located in the Colville foreland basin on the North Slope of Alaska. This prolific petroleum producing province contains several giant fields, including North America’s largest oil field, Prudhoe Bay field. Although the area was considered past its prime for exploration, in 2013 a joint exploration venture consisting of Armstrong Energy, LLC, Repsol, and GMT Exploration announced a major discovery in the Qugruk 3 well where approximately 250 ft (76 m) of net pay was encountered in the Cretaceous Nanushuk Formation, a little explored interval that is stratigraphically younger than the historically productive zones. Subsequent appraisal of the discovery has delineated a large, hydrocarbon-charged, stratigraphic trap that includes what is now the Pikka Unit. In 2017, the Horseshoe 1 and 1A wells were drilled 22 mi (35.4 km) south of the discovery well and confirmed giant status for Pikka field. The Pikka discovery established the Nanushuk as a new play and refocused the industry’s attention on exploration on the North Slope. The Nanushuk Formation represents the topset and upper foreset segments of a series of prograding clinothems that were deposited in a foreland basin during the Lower Cretaceous. Sandstone reservoirs at Pikka field are found in two individual clinothem sequences informally named the Nanushuk 3 and Nanushuk 2 zones that were deposited on a subaqueous shelf and shelf-edge delta. Net pay thickness is variable with less than 50 ft (15 m) present on the shelf part of the reservoir and up to 250 ft (76 m) in the expanded section outboard, or seaward, of the underlying shelf edge. Porosity ranges up to 29% (20% average) with permeability up to 690 md (47 md average). Oil gravity ranges from 23° to 32.5° API depending on elevation within the hydrocarbon column. To date, 740 ft (226 m) of hydrocarbon column has been proven. Preliminary estimates indicate an original oil in place (OOIP) volume for the total field area of 9.7 to 14.8 billion barrels of oil (BO) with a range of 1.9–4.4 billion BO recoverable. Most of the reserves occur in the expanded section of the Nanushuk 3 zone. The Qannik oil pool within the Colville River Unit currently produces from Nanushuk 2 equivalent shelf sandstones and appears to be part of the overall accumulation. The Pikka Unit portion of the field will be developed using a phased project concept that is focused on initial delivery of an 80,000 BOPD single drill site development. FEED will start in early 2021 with first oil planned for 2025. Additional drill sites and expansion of the processing facilities will be added in the future as warranted. ConocoPhillips is currently developing their portion of Pikka field from existing infrastructure within the Colville River Unit. Independent reserve auditor, Ryder Scott, has certified gross 2C contingent recoverable oil resources of 767.6 million barrels for the Pikka Unit portion of the field ( Oil Search Press Release, 2021 ).

ABSTRACT Explorers found a total of 82 giant conventional discoveries over the decade, defined as fields holding most likely resources of at least 500 million barrels of oil equivalent (BOE). Collectively, these giants hold total resource volumes of 129 billion BOE, representing 53% of all new field resource adds over the decade. Without these giants, the recent recovery in exploration’s fortunes would have been a quite different story. Giant oil and gas discoveries were at the heart of key exploration trends over the decade 2010–2019. The middle years of the decade were a period of profound change for the industry. Sharp falls in oil prices led to a broad reduction in the scale of the exploration business. Well completions and investment fell by more than half and look unlikely to recover. This smaller industry has become profitable again. Toward the end of the decade, a partial recovery in oil prices combined with a broad rebasing of the industry’s costs led to much improved full-cycle exploration returns. These giant discoveries are widely distributed. There are important clusters in deep-water regions of Brazil, East Africa, and the eastern Mediterranean. Frontier and early-stage exploration is the other common theme among these giant discoveries. By contrast, only 11 giants were found in mature plays, mainly in the super basins of the Middle East, West Siberia, and China.

ABSTRACT Area 1 is located in the Campeche Bay, offshore Gulf of Mexico at a distance from shore ranging from 2 km to 8 km and in water depths from 20 m to 40 m. Eni was awarded Area 1 in 2015, as part of the Mexico Ronda 1-Licitación 2 launched by the Comisión Nacional de Hidrocarburos (CNH). It consists of three separate blocks that include the Amoca, Miztón, and Tecoalli oil fields, previously discovered by Pemex in 2003, 2013, and 2009, respectively. Area 1 is situated in the Sureste Basin, in the southern sector of the Gulf of Mexico, one of the most prolific hydrocarbon provinces in the world. The geology of the basin is strictly linked to the sedimentary and tectonic evolution of the whole Gulf of Mexico. The tectonic deformation of the Sureste Basin is dominated by salt movements, which started in the Upper Jurassic with a major phase in the Upper Tertiary, together with the main regional uplift events related to the Laramide (Paleogene) and Chiapanecan (Middle Miocene) orogeny. The main contribution to the hydrocarbon charge comes from the organic-rich Tithonian shale-to-marly deposits, representing the main source rock of the Gulf of Mexico. In the Sureste Basin, reservoirs are present both within Upper Jurassic–Cretaceous carbonates and in Miocene-Pliocene clastic sequences. However, in Area 1 reservoirs are limited to Tertiary clastics, because the Mesozoic carbonates are quite deep and are expected to be in unfavorable, very tight lithological facies. In general, the Tertiary clastic section could be subdivided into two mega sequences separated by the Middle Miocene unconformity. In Area 1 the most important Tertiary reservoirs are associated with the prograding, and generally coarsening-upward, platform-slope-basin turbidite and deltaic systems, overlying the Middle Miocene unconformity. Top seals consist essentially of intraformational shale packages. In the past 60 years, approximately 50 onshore fields have been discovered in Salina del Istmo, the westernmost part of the Sureste Basin, within the Neogene geological plays, the same where Area 1 discoveries were made, with a cumulative production of more than 2 BBOE. Starting from 2003, the exploration activity moved also to the offshore sector, where some discoveries have been made both by Pemex and by international operators, most notably the Zama discovery in 2017. Area 1 exploration and delineation phase was characterized by several challenges, from both a geological and geophysical point of view. Three separate structures in a complex depositional and structural setting, in addition to multiple reservoirs with a wide range of oil gravity, were indeed a challenge to tackle. Legacy seismic data consisting of two different surveys, OBC and streamer, resulted in inhomogeneous seismic response with imaging issues, especially in the deeper sequences. In 2016–2017 Eni reprocessed the two surveys by merging them and producing new PSDM 3-D volumes. The in-house reprocessed volumes considerably improved the seismic imaging and allowed to build up a more reliable geological and structural model of the area. Seismic amplitudes showed up in sequences previously characterized by a poor seismic response and significantly de-risked untested plays that were the targets of the exploration campaign, opening up the prospectivity of the deeper levels of the Cinco Presidentes Formation and also of the shallower Orca 2 Formation. A rigorous use of seismic attributes and amplitude versus offset (AVO) analysis was also key in defining the exploration strategy. All the five exploration and appraisal wells were drilled in the fields’ sweet spots previously unseen on legacy seismic data and characterized by stacked amplitude anomalies mostly associated to a class III AVO response. In the Amoca Field, the exploration and appraisal wells not only confirmed previously discovered resources but also opened up new plays in deeper stratigraphic sections or in undrilled areas. The Amoca-3DEL well encountered 358 m of net oil pay of which 206 m in new reservoirs not investigated by the Amoca-1 discovery well. All the new Amoca wells indicate the presence of an extremely efficient petroleum system, because most of the encountered sandstone reservoirs were found oil bearing. In Miztón, a seismic amplitude and AVO-driven exploration approach also proved successful. The Miztón-2DEL well, drilled in the western sector of the structure, found 184 m net oil pay in four reservoirs, with an 80% increase compared to the total net oil pay encountered by the Mitzón-1 discovery well (102 m net oil pay). The same approach led to positive results also in Tecoalli, where the Tecoalli-2DEL well, besides confirming the presence of the Orca 2 oil-bearing reservoir, also encountered 27 m of net oil pay in the deeper and previously undrilled Cinco Presidentes Formation. To summarize, in 2017–2018 Eni ran a successful exploration and appraisal campaign in Area 1 drilling five exploration and appraisal wells and carrying out four production tests that resulted in a significant increase of the estimated hydrocarbon in place of the Amoca, Miztón, and Tecoalli fields. At the end of this campaign, the total hydrocarbons initially in place (HIIP) raised from the pre-bid estimate of 880 MBOE (million barrels oil equivalent) to 2.1 BBOE (billion barrels oil equivalent). Following the conclusion of the initial contractual period, Eni submitted the Area 1 Development Plan to the Comisión Nacional de Hidrocarburos that approved it on July 31, 2018. The Area 1 development drilling campaign started in the first quarter of 2019, and first oil was produced from the Miztón Field on June 30, 2019, only two-and-a-half years after the spud-in of the first exploration and appraisal well drilled by Eni.

ABSTRACT Field growth is a phenomenon where the estimates of known recovery tend to increase systematically over time. Generally, field growth is associated with the following: (1) boundaries of proved areas are extended by drilling; (2) new pay zones, pools, and reservoirs are found by drilling or recompletions; (3) infill wells or stimulation procedures; (4) improved drilling and completion costs; (5) and secondary or tertiary recovery. Items 1 through 4 occurred at Wattenberg, and item 5 is currently being tested. Unconventional fields experience field growth just like conventional fields. The overall economics of conventional and unconventional systems benefit from the field growth phenomenon. The giant Wattenberg Field of Colorado was discovered in 1970 by Amoco Production Company with initial production from the Lower Cretaceous Muddy (J) Sandstone. Wattenberg straddles the Denver Basin synclinal axis and is regarded as a basin-center stratigraphic petroleum accumulation covering approximately 2600 mi 2 . Subsequent to discovery, the number of producing layers and production grew to include five additional formations (Dakota Plainview, Codell Sandstone, Niobrara Formation, Terry and Hygiene sandstone members of the Pierre Shale). The Terry and Hygiene were first produced in 1971, the Codell in 1981, the Niobrara in 1985, and the Dakota Plainview in 1998. Production occurs from approximately 4000 to 8500 ft below the surface across the field. Reservoir quality in the various horizons is generally poor, which mandates hydraulic fracture stimulation for economic production. The addition of multiple productive horizons in the field area has significantly added to the total reserve number. The field is ranked by the U.S. Energy Information Administration (EIA) based on reserves as the fourth-largest oil field and the ninth-largest gas field in the United States. Original reserves were estimated to be 1.1 TCFG for the Muddy (J) Sandstone. Fifty years after discovery, the field is currently at peak production because of recent horizontal drilling activity in the Codell and Niobrara with cumulative production to date at 1060 MMBO and 9.4 TCFG from more than 40,000 wells. Estimated ultimate recovery is 1100 MMBO and 9.7 TCFG. This represents reserve growth of over 1000% from discovery. Hydrocarbon source rocks in Wattenberg are the Skull Creek Shale, Graneros Shale, Greenhorn Limestone, Carlile Formation, Niobrara Formation, and Sharon Springs Member of the Pierre Shale. Total source rock thickness in Wattenberg is 200 to 250 ft (>2 wt.% TOC). The source beds are dominantly Type II with some Type III kerogen present. The Wattenberg area is a “hot spot” or positive temperature anomaly. This is an important reason the area is so prolific. Temperature gradients range from 1.6°F to 1.8°F/100 ft on the edges of the field to about 2.8°F to 2.9°F/100 ft in high gas-oil ratio (GOR) areas. The temperature anomaly is related to where the Colorado Mineral Belt intersects the Denver Basin. The mineral belt is a northeast trending zone across Colorado of Late Cretaceous to early Tertiary mineralization. The mineralization is associated with high geothermal gradients and hot fluids. The high heat flow and hydrocarbon generation contribute to abnormal pressure in parts of the field.

ABSTRACT The Talos Energy Zama-1SON, the first private-sector exploration well operated in Mexico in 78 years, was drilled in May–July 2017 in Block 7, 50 km (30 mi) offshore Tabasco in 166 m (545 ft) of water. The Zama structure was identified before the leasing round using two three-dimensional narrow-azimuth seismic data sets. The structure consists of an upthrown fault block with three-way closure on a salt structure’s flank in the eastern Salina del Istmo basin. A 344-m (1129-ft) gross sandstone reservoir interval was penetrated, containing 29.6° API oil. The estimated reserves make Zama one of the most significant offshore discoveries globally in several years. An array of tools and techniques was used to define, drill, and evaluate the Zama prospect. These include (1) structural and stratigraphic analysis to frame the prospect in proper context; (2) predrill amplitude versus offset analysis calibrated to seismic data using existing well control; (3) petrophysical analysis using x-ray diffraction (XRD) mineralogy and image logs; (4) forward modeling for predrill stratigraphic control and reservoir thickness; (5) a full suite of logging while drilling (LWD) and wireline logs (including elemental spectroscopy, formation pressure testing, and fluid sampling); and (6) combined biostratigraphic and petrologic (XRD and x-ray fluorescence [XRF] analyses performed on cuttings while drilling, drill stem test (DST)/pressure, volume, temperature (PVT) analysis, and whole-core analysis. The reservoir section is dominated by amalgamated, coarse-to-very fine-grained, highly feldspathic, unconsolidated, poorly sorted sandstones with low clay content. Structural mapping and biostratigraphy suggest sediment may have been fed into an evolving late Miocene offshore basin from a narrow shelf and proximal alluvial fan complex in a very active geologic setting before being deposited in a deep-water environment as a submarine channel lobe complex. The base of the reservoir section coincides with a significant middle Miocene unconformity related to salt tectonics. Pressure gradient data confirmed only one hydrostatic system in the reservoir, and a pressurized fluid sample was acquired. Subsequent appraisal drilling included whole cores in two wells covering the entire reservoir interval and DST analysis to define the reservoir qualities and extent.

ABSTRACT There have been 248 giant fields (>500 MMBOE) found since 2000. Information gleaned from studying these giant fields’ data has shown that the industry has undergone at least five major paradigm shifts in the past 20 years. First, unconventional and tight gas exploration has transformed the industry. It is expanding to South America, Oman, Bahrain, China, and other countries. Second, creaming curves show step changes in success in finding giant combination and stratigraphic traps. These traps now comprise 60% of the volumes, up from 10% to 15% historically, and attributed to improved seismic imaging. The most important trends are salt-sealed carbonate reef complexes in the Caspian Basin, Egypt, Brazil, and Turkmenistan. Of equal importance are passive margin turbidites, commonly de-risked with amplitude vs. offset (AVO) and 3-D seismic reservoir imaging. Third, ultra-deep drilling to 5–9 km below mudline is finding oil, rich liquids, and porosity. Some of this can be explained by lowered geothermal gradients beneath thick salt, but other oils occur at temperatures of 160°C–180°C with very high pressures. We discuss new concepts to explain these deep liquids from the standpoint of pressure, volume, temperature (PVT) data and fractionization during migration. Fourth, giant fields have been found overlying oceanic crust, breaking a long-held paradigm that these kinds of plays do not work. Last, deep, overpressured upward hydrodynamic flow and tilted hydrocarbon contacts have been documented in many basins. This may ultimately turn out to be more of a “norm” than an exception.

ABSTRACT The story of Zohr started during mid-2012 when Egyptian Natural Gas Holding Company (EGAS) launched a competitive bid round covering 15 offshore/onshore blocks in the Nile Delta. At that time, after more than 40 years of exploration, the Nile Delta plays (mostly clastic and gas prone), from the HP/HT Oligocene pre-salt to the DHI-supported Plio-Pleistocene post-salt, had all been assessed. A new innovative play was needed to restart exploration and to renew IEOC (Eni’s affiliate company in Egypt) exploration portfolio. The opportunity was offered by several blocks on auction located along the Egypt–Cyprus border in deep water/ultra-deep water, previously explored during a 12-year period (1999–2011) without commercial success. Although looking for the extension into Egypt of the multi-Tcf, biogenic gas, Levantine-style play that had been proven in 2009–2011 in both Israel and Cyprus waters by the Noble–Delek JV (Leviathan, Tamar and Aphrodite discoveries), IEOC explorers identified something profoundly different and yet similar in the Block 9 (later to become the Shorouk block). Instead of the Oligocene to Early Miocene clastic deep-water sandstones sealed by the interbedded shales in anticlinal traps, a structural high linked to the Eratosthenes Seamount crustal block showed geometries typical of a shallow-water isolated carbonate buildup, capped by Messinian salt onto which the Miocene clastics were laterally abutting. Two targets were initially inferred for the Zohr prospect, respectively Miocene and Early Cretaceous age in analogy with the sedimentary section detected by several ODP cores on the northern flank of the Eratosthenes Seamount. The Zohr-1 discovery well, drilled in 2015 in 1450 m of water, was the first well targeting a carbonate play in the East Mediterranean. It found Miocene and predominantly Early Cretaceous shallow-water carbonates facies with a 624 m continuous biogenic gas column. The following four appraisal wells confirmed the initially estimated gas-in-place volumes. Thanks to Eni Upstream Business model, driven by time to market speed and cost-effectiveness while converting discoveries into production and based on the full integration of exploration and development, only two years after the discovery the gas of Zohr came onstream (December 2017), a record for a deep-water development project. The start-up was followed by a quick and smooth ramp up, reaching even the production plateau far ahead of the plan of development commitments. In parallel, the application of Eni dual exploration model contributed to boost the cash generation from the asset. Zohr reshaped the energy scenario of the whole Eastern Mediterranean and provided the industry with a new discovered play that was quickly pursued around the Eratosthenes Seamount in Cyprus.

ABSTRACT This chapter presents new data and statistics on the economic importance of giant oil and gas discoveries. Giant discoveries are major economic events—they reveal previously unknown subsoil riches and preview a flow of investment and revenues to countries throughout the coming decades. For lower-income countries, they can exceed in net present value terms the entire annual GDP of the country. We discuss how countries have managed these opportunities—for some it has led to decades of sustained prosperity; for others it has failed to generate anticipated benefits, creating a dependence on resource revenues; and in some cases, it has exacerbated problems of economic mismanagement, corruption, and conflict. A new strand of social science literature is now interested in the effect of discoveries in isolation from the longer-term effects of a country becoming resource dependent. We review this work, concluding that the news of a giant discovery can significantly shift the economic and political trajectories of countries, for better and for worse.

ABSTRACT In 2015, ExxonMobil and partners, Hess Guyana Exploration Limited and CNOOC Nexen Petroleum Guyana Limited (now CNOOC Petroleum Guyana Limited), drilled the Liza-1 wildcat well on the Stabroek Block, located offshore Guyana, in approximately 1750 m (5700 ft) of water depth and encountered more than 90 m (300 ft) of high-quality, oil-bearing sandstone reservoirs. Perhaps most notably, this discovery was in a basin that previously had greater than 40 dry holes testing at least four different play types. From the Liza-1 discovery well, subsequent appraisal wells, and additional exploration finds, the current gross recoverable discovered resources on Stabroek Block are at approximately 8 billion bbl (1.3 billion m 3 ) from 18 discoveries as of late 2020, with a fast-tracked Liza development plan delivering first oil late in 2019, ahead of the original schedule.

ABSTRACT With willingness to invest and good geology, the Unconventional Revolution will not remain a North American story. The first areas to reach economically successful developments of unconventional resources will probably be the petroleum-rich provinces with important legacy data, substantial existing infrastructure, and public acceptance. The Neuquén Basin (Argentina) is the first place where the Unconventional Revolution has been exported with success, and the Vaca Muerta play represents the first economical unconventional play outside North America. The history of the discovery and development of the Vaca Muerta play dances for more than a decade with an intense series of events, such as the international search of new unconventional resources, the nationalization of the main operator, dramatic shifts in fiscal regime, a quick evolution of the play concepts (from vertical to horizontal wells) and of technology (from 500 to 3000 m laterals), and the Covid-19 pandemic. Nevertheless, the situation allowed conditions for economic success. The geological knowledge of the Vaca Muerta play derives from (1) data gathered during the last decade, related to the search and discovery of the Giant Field Vaca Muerta, and (2) the legacy of 100 years of activity of the O&G industry in the Neuquén Super Basin. The integration of the geological disciplines, at different scales, presents a unique unconventional play, exceptionally thick (100–400 m), vast (30,000 km 2 ), and porous (10%–20%), with a prograding clinoform hosting up to eight landing zones, and all types of fluid segments (from black oil to dry gas). The current play concept consists in landing the horizontal wells in the proximal bottomsets and lower foresets of the clinoform, sectors with higher hydrocarbon potential and easier fracture growth. The rocks in these sectors show the best reservoir characteristics (averages: TOC 5%; porosity 12%; clay 10%–20%; water saturation 20%), the most adequate geomechanical properties (homogeneous rock with Young’s Modulus <4 Mpsi, low Poisson Ratio ~0.25, and interfaces with weak geomechanical contrasts), and a thick vertical stack (30–40 m) of lithofacies with the aforementioned characteristics. With this concept in mind, at least two landing zones have been fully de-risked, and other six have been confirmed. The Vaca Muerta play has continued to progress lowering the breakeven to US$40/bbl for oil and US$2.0 MMBtu for wet gas. As activity ramps up, these values will continue to fall. The operators in the development phase believe that the combination of costs, well performance, and product prices are earning a return in their investments. In other words, the combination of below ground factors (geology) and above ground factors (contract terms, regulations, supply chain, security, market access, etc.) are allowing the development to be profitable.

ABSTRACT The Greater Tortue/Ahmeyim gas field discovered by Kosmos Energy in 2015 in the deep-water Mauritania–Senegal Basin opened a new giant gas province in Northwest Africa. The discovery well, Tortue-1, was drilled in Mauritania by Kosmos and the Mauritania National Oil Company (SMHPM) and discovered dry gas in Cenomanian reservoirs within a stratigraphic–structural trap of approximately 90 km 2 (34.7 miles 2 ). Two additional wells, Guembeul-1A in Senegal (drilled by Kosmos and PETROSEN) and Ahmeyim-2 in Mauritania (drilled by Kosmos and SMHPM), support a field resource estimate of approximately 25 tcf (0.71 tcm) GIIP. Additional drilling outside the Ahmeyim Field proves this gas province extends from northern Senegal to central Mauritania and may contain up to 50–100 tcf (1.42–2.84 tcm) GIIP. The Mauritania–Senegal Basin saw several exploration campaigns throughout approximately 60 years. However, the deep-water petroleum system had not been recognized as it was assumed; (1) the Cenomanian-Turonian (C-T) mudstones were the only viable source rocks, and these would be immature in the deep water; (2) the basin outside of the salt province was undeformed—thus lacking trapping geometries; and (3) a sufficient volume of high-quality reservoir was not likely to be found in the lower slope. The Greater Tortue/Ahmeyim Field discovery dispelled these paradigms while giving new insights into deep-water exploration. The African margin has been described as a passive margin; however, a clear deformation event occurred in the Late Cretaceous to Early Tertiary on faults linked to hyperextended crust. This deformation event likely coincides with the heat event, which is evidenced today by elevated heat flow across the outer basin. This heat event matured an Early Cretaceous source or sources producing high-maturity dry gas. The lower slope to basin floor depositional systems contain very thick, stacked packages of sand, which have high-quality reservoir properties because of rework by multiple current processes. The Greater Tortue/Ahmeyim Field reached final investment decision (FID) in December 2018 with partners BP Exploration and national oil companies SMHPM (Société Mauritanienne des Hydrocarbures et de Patrimoine minier) and PETROSEN (Senegal). The field will be developed with a floating liquefied natural gas (FLNG) design.

ABSTRACT The Zafarani and Tangawizi giant discoveries are two of the most significant natural gas accumulations offshore Tanzania. Discovered by Statoil (now Equinor) with partner ExxonMobil in 2012 and 2013, Zafarani contains approximately 5.2 and Tangawizi 4.8 trillion ft 3 (TCF; 147 and 136 billion m 3 , respectively) of gas in place and are located in Block 2, approximately 100 km (62 mi) from shore. The partnership drilled 15 wells and made 9 discoveries. In total, more than 20 TCF of gas in place have been discovered in Block 2 from eight reservoirs dating from Early Cretaceous–Albian to Miocene in age. The Zafarani and Tangawizi discoveries are important play openers in the region, representing clastic reservoirs charged by the same nondrilled source rock but with very different trap styles and depositional settings. Although the Zafarani reservoir is interpreted as deep marine slope channels and channelized lobes trapped in a four-way closure along the Seagap fault system, the Tangawizi reservoir is a shallow buried Miocene stratigraphic trap interpreted to be remobilized deep marine sand-rich deposits associated with a major mass transport complex (MTC).

ABSTRACT In April 2011, Statoil (Equinor from 2018), with partners Eni Norge and Petoro, discovered oil in the Skrugard prospect in the Barents Sea. An 83 m (272 ft) column of 32 API oil with a minor gas cap was proven in 350 m (1150 ft) thick sandstones with excellent reservoir properties. Skrugard was the second and by far the largest commercial oil discovery in the Barents Sea at that time. Ten months later, the adjacent Havis prospect proved a 127 m (417 ft) column of 35 API oil and similar volume of recoverable oil as Skrugard. Together they make up the main pools of the Johan Castberg Field. The tested traps were rotated fault blocks with Early to Middle Jurassic shallow marine and fluvial sandstone reservoirs, capped by Late Jurassic and Early Cretaceous shales and sourced from Late Jurassic marine source rocks. In the early exploration efforts in the western Barents Sea from 1987 to 1992, five exploration wells had tested similar prospects. All of them were dry, most with oil shows, and were interpreted to have leaked during Late Cenozoic uplift and erosion. Multiple episodes of glaciations during the last 2 million years with substantial erosion, associated tectonic tilting, and oscillations in reservoir pressure conditions have traditionally been regarded as the main cause of the failures. For many years, the leakage problems riddled Barents Sea exploration, reducing exploration activity substantially. This part of the Barents Sea was abandoned by oil companies because of the disappointing results. In addition, a stop in new area license awards in the Barents Sea was imposed by the authorities from 1997 to 2006, pending results of an environmental impact study. This, in combination with the general downturn of the industry, left the area without new exploration wells for 20 years. Following the lift of the moratorium in 2006, new evaluation based on 2-D seismic in the area identified that several prospects had seismic flat spots, but the volume potential was assessed to be limited. In 2008, WesternGeco acquired the first 3-D seismic survey of the area. Numerous prospects were mapped showing strong seismic hydrocarbon indicators, high volume potential, and high probabilities for discoveries. This resulted in Statoil and Eni Norge applying for a license in the 20th exploration round in 2008. Continued exploration in the license has been supported by the extensive use of integrated geophysical studies using 3-D seismic, Ocean Bottom Seismic, and 3-D Controlled Source Electromagnetic data. The Skrugard and Havis discoveries have been followed by an exploration program of eight additional wells so far, all of which are discoveries. The Johan Castberg field reserves are 556 MMbbl (88.7 MSm3) of recoverable light oil with an estimated plateau production at 190,000 barrels (30.000 Sm3) per day.

ABSTRACT Technologies and oil field practices have continued advancing since Sneider and Sneider (2001) documented “new” oil additions in mature fields. A literature review of giant fields shows reserve additions from shallower and deeper pools, lateral extensions, infill drilling of compartmentalized reservoirs, and accessing poorly swept or bypassed zones. Giant oil fields with low reservoir energy saw increased enhanced oil recovery (EOR). Through early deployment of EOR methods, giant oil fields exemplify a trend of timeline compression in field development. New giant oil fields have reinforced the finding that elements essential to adding reserves are (1) improved reservoir characterization, (2) application of new technologies, and (3) innovative thinking. In the North Sea at Beryl Field, new 3-D seismic data revealed complex geology but with insufficient resolution. Geological models still required extensive revision to match drilling results. At Forties Field, model revisions increased reserves and significantly prolonged production. Oman demonstrates using EOR to add new reserves in giant oil fields like Fahud, Marmul, and Qarn Alam. Despite differences in the geology, fluid properties, and reservoir quality, these projects found success through common themes of detailed reservoir characterization, innovative thinking, and applying new technologies, such as gas- or thermal-assisted gravity drainage, polymer floods, high-resolution stratigraphic studies, and probabilistic reservoir characterization. Lessons from analogous fields promoted success and compressed the development timeline of a miscible flood at Harweel Field. At Mukhaizna and Khazzan fields, new practices, detailed reservoir characterization, and advancing technologies aided in the successful development of giant accumulations, previously considered too complex to exploit.

ABSTRACT Exploration, discovery, and economic development of hydrocarbons in unconventional resource reservoirs in the West Texas Super Basin occurred gradually for decades. Knowledge about the basin and potential of unconventional resources and reservoirs are based on research, data, and information obtained during a century of fieldwork on the basin margins. In the basin, economic activity including drilling, subsurface data collection, completions, and production first targeting water, then minerals, and finally hydrocarbons stored in conventional reservoirs more directly contributed to the knowledge of the hydrocarbon potential for unconventional resource reservoirs. Unconventional resource reservoirs were discovered and developed in the Spraberry 70 years ago, 50 years before unconventional oil and gas resource reservoirs were defined. The Wolfcamp Shale (Wolfberry, combined Spraberry and Wolfcamp in the Midland Basin) discovery occurred over a decade (late 1990s to late 2000s) by a network of individuals across time, several different companies, and outside events. Similar to the Spraberry decades earlier, the Avalon (Bone Spring) play in the northern Delaware Basin developed from a traditional siltstone play near the basin center to an unconventional resource reservoir as reservoir grain size decreased toward the basin margins. Still, hydrocarbon saturation remained high on the conventional reservoir margins. In the southern Delaware Basin, the necessity for economic success in failing conventional plays lead an independent to change exploration strategy based on observations from a team evaluating subsurface data and information and knowledge of discoveries and development of unconventional resource plays throughout the United States, including the neighboring Midland Basin unconventional resource reservoir plays. These combined northern and southern Delaware Basin unconventional resource plays (Bone Spring and Wolfcamp) also became known as the Wolfbone. The Delaware Basin movement into unconventional resources also gradually occurred over a decade, 2000–2010, a few years behind the Midland Basin unconventional discoveries and early development. However, the majority of the industry did not have significant involvement, investment, drilling, and subsequent production did not show significant results in either the Midland or Delaware Basins until the middle and second half of the 2010–2019 decade and after early development and production acceleration in other oil-rich, unconventional resources, first in the Bakken, then in the Eagle Ford. The oil price drop from 2014 to 2016 resulted in a decrease of investment and the number of drilling rigs throughout the United States but less in the West Texas Basin. The percentage of total investment and unconventional oil rigs in the West Texas Basin rose to more than 50% of total domestic industry investment and drilling activity, accounted for 35% of domestic oil production, and was the controlling supply-side factor of world oil price. During the first century (1920–2020) of exploration and production, the West Texas Super Basin has produced 63 BBOE. The United States Geological Society (USGS) and Bureau of Economic Geology estimates are that the discovery of the unconventional resource reservoirs (2000–2019) and future development in the West Texas Super Basin could technically produce twice those reserves during the next half-century.

Abstract Egypt has a statistical yet-to-find in excess of 37 BBOE (218 TCF). At least 12 major tectonostratigraphic events control a multitude of trapping styles and petroleum systems. Source rocks span Paleozoic through Miocene ages, and reservoirs are productive from Basement to Pleistocene. Future significant conventional resource additions will largely come from either semi-isolated basins in Upper Egypt or the Red Sea, or from deeper pools in the Western Desert and Nile Delta. Substantial unconventional resources may come primarily from the Abu Roash Formation in the Abu Gharadig Basin, and perhaps the Gulf of Suez Thebes and Brown Limestones. In this paper, we explore the geological setting of these new plays with an emphasis on the deeper petroleum systems and insights from new regional mapping, geochemical, and seismic data.