ABSTRACT Study of giant oil and gas fields is useful not only to understand oil and gas habitat but also because statistical analysis of these data sheds light on future energy supplies. In such statistical studies, the definitions of both “giant” and “field” are important. The development of giant accumulations that are not fields increases the resource supply but can simultaneously decrease the accuracy of resource estimates and production forecasts unless care is taken with definitional issues.

ABSTRACT Estimated recoverable oil and gas from giant field discoveries from 2000 through 2009 was 383 billion barrels of oil equivalent (BBOE)—a 92% increase from the prior decade and the largest addition from giant fields since the 1970s. This dramatic increase in giant field resources was driven by the emergence of shale gas and tight oil discoveries in North America. These so-called unconventional or continuous resource plays added almost 177 BBOE of new resources—mostly from super-giant plays like the Marcellus, Bakken-Three Forks, Eagle Ford, and Montney formations. In harmony with recent trends, giant natural gas discovery volumes greatly exceeded those of oil and contributed about 260 BBOE (1558 trillion cubic feet) of new resources. Traditional conventional giant discoveries added 198 BBOE of new resource—slightly less than in the prior decade and almost 55% of the total. Super-giant fields such as Galyknysh (Yoloten) with 67 BBOE gas and condensate in Turkmenistan, Kashagan in Kazakhstan; Lula in Brazil; and Kish 2 in Iran accounted for almost 60% of the giant conventional resources. The share of deepwater discoveries increased and contributed 23% of the conventional giant field volumes. The Santos Basin mega presalt and the Levantine Basin were the most important deepwater play openers.

ABSTRACT Exploration for oil in the Norphlet reservoir in the deep-water Gulf of Mexico began in 2003 at prospect Shiloh (DC269). The well found oil but not an economic volume. The second prospect, Vicksburg (DC353), was drilled in 2007. This well found a larger in-place volume of oil, but with an immovable solid hydrocarbon component within pore spaces, there was great uncertainty as to the potential producible volumes. Two subsequent wells (Fredericksburg [DC486] and Antietam [DC268]) were dry and had a very small amount of oil, respectively. Finally, in late 2009, the fifth well (Appomattox [MC392]) was a significant discovery of high-quality oil in a thick aeolian Norphlet sandstone.

ABSTRACT The Middle Devonian Marcellus shale play has emerged as a major world-class hydrocarbon accumulation. It has rapidly evolved into a major shale gas target in North America and represents one of the largest and most prolific shale plays in the world with a prospective area of approximately 114,000 km 2 (44,000 mi 2 ). Two major core areas have emerged, each with a unique combination of controlling geologic factors. Production from the Marcellus play reached 16 billion cubic feet of gas equivalent per day (BCFepd) in 2015, and it has been recognized as the largest producing gas field in the United States since 2012. The organic-rich black shales comprising the Marcellus shale were deposited in a foreland basin that roughly parallels the present-day Allegheny structural front. The Marcellus shale accumulated within an environment favorable to the production, deposition, and preservation of organic-rich sediments. The key geologic and technical factors that regionally define the Marcellus play core areas include organic richness, thermal maturity, degree of overpressure, pay thickness, porosity, permeability, gas in place, degree of natural fracturing, mineralogy, depth, structural style, lateral target selection, completion design, and important rock mechanics issues such as the ability to be fractured, rock brittleness versus ductility, and the ability to generate complex fractures. Structural setting and deformation styles are critical to address natural fracture trends, potential geologic hazards such as faulting and fracturing in structurally complex areas, and fracture stimulation containment issues. Since the Marcellus shale unconventional shale gas reservoir discovery in 2004 until May 2015, more than 8600 horizontal Marcellus shale wells had been drilled in Pennsylvania, West Virginia, and limited portions of eastern Ohio. Many decades of future drilling potential remain due to the enormous extent of the Marcellus shale play. Horizontal Marcellus wells report initial production rates ranging from less than 1 MMCFe/day to over 47.6 MMCFe/day. Despite the large number of wells drilled and completed to date and production of 16 BCFepd in 2015, the play is still in its infancy due to its vast geographic extent and production potential. The Marcellus shale represents a continuous-type gas accumulation and when fully developed will comprise a large continuous field or series of fields. Over its productive trend, the Marcellus shale play has significant additional reserve potential in the overlying organic shales in the Devonian Age Rhinestreet, Geneseo, and Burket units as well as deeper potential in the Ordovician Age Utica/Point Pleasant units. Estimates of recoverable reserves from the world’s largest gas fields combine their reserve estimates for all key productive units in the field/play trend. Likewise, estimates of in-place gas resources for the Marcellus play range from 2322 tcf for the Marcellus (Hamilton Group) to over 3698 tcf for the combined Devonian Age Marcellus-Geneseo-Rhinestreet system. This represents the largest technically accessible in-place gas resources in the world.

ABSTRACT The Williston Basin Bakken petroleum system is a giant continuous accumulation. The petroleum system is characterized by low-porosity and -permeability reservoirs, organic-rich source rocks, and regional hydrocarbon charge. Total Bakken and Three Forks production to December 2014 was 1.289 billion barrels (bbl) of oil and 1.3 trillion cubic feet of gas (TCFG) from 12,051 wells. U. S. Geological Survey (USGS) ( Gaswirth et al., 2013 ) mean technologically recoverable resource estimates for the Bakken petroleum system are 7.375 billion barrels of oil, 6.7 tcf of gas, and 527 million barrels of natural gas liquids. The Bakken Formation regionally in the Williston Basin consists of four members: upper and lower organic-rich black shale, a middle member (silty dolostone or limestone to sandstone lithology), and a basal member recently named the Pronghorn. The Bakken Formation ranges in thickness from a wedge edge to over 140 ft (43 m) with the thickest area in the Bakken located in northwest North Dakota, east of the Nesson anticline. The Three Forks is a silty dolostone throughout much of its stratigraphic interval. The Three Forks ranges in thickness from less than 25 ft (8 m) to over 250 ft (76 m) in the mapped area. Thickness patterns are controlled by paleostructural features such as the Poplar Dome, Nesson, Antelope, Cedar Creek, and Bottineau anticlines. Thinning and/or truncation occurs over the crest of the highs, and thickening of strata occurs on the flanks of the highs. The Three Forks can be subdivided into three units (up to six by some authors; e.g., Webster, 1984 ; Gutierrez, 2014 ; Gantyno, 2011 ). Most of the development activity in the Three Forks targets the upper Three Forks. The upper Three Forks is dominated by silt-sized quartz and dolomite and some very fine-grained sandstones and has low permeabilities and porosities. The upper Three Forks ranges in thickness from a wedge edge to over 40 ft (12 m) in areas east of the Nesson anticline. The unit thins toward the margins of the depositional basin because of erosional truncation. The upper and lower shale members are potential source rocks and are lithologically similar throughout much of the basin. The shales are regarded as dominantly type II kerogens. The shales average 11 wt.% total organic carbon. Measured core porosity and permeability are very low in the Bakken, Sanish, and Three Forks reservoirs (<10% porosity and <0.1 md permeability) in the Williston Basin, so productivity is assumed to be due to natural and artificial fracturing. The reservoirs generally require advanced technology to get them to produce (fracture stimulation and horizontal stimulation). For this reason, they should be considered to be technology reservoirs. Natural fractures in some areas (e.g., Billings Nose area and Antelope field) are sufficient for vertical well production. Reservoir pressure in the Bakken is regarded as overpressured with pressure gradients exceeding 0.5 psi/ft. A new pressure map for the Bakken petroleum system was generated. The map is based on 92 BHP (bottom-hole pressure) and DFIT (diagnostic fracture injection test) data points, including six additional hydrostatic points at the eastern margin as well as six data points for the Sanish–Parshall area. High overpressures are found in large parts of the central basin and the Parshall area in the east, where gradients exceed 0.7 psi/ft. Elm Coulee has a pressure gradient around 0.55 psi/ft. Parshall is reported to have a gradient of 0.74 psi/ft. The area west of the Nesson anticline has pressure gradients of 0.6 to 0.7 psi/ft. Pressure gradients in Montana are generally in the 0.51 psi/ft range.

ABSTRACT The Eagle Ford shale Formation (Upper Cretaceous) in the Gulf Coast basin of south Texas was first commercially produced in 2008 and has since achieved production and reserve growth that is virtually unprecedented in the history of onshore North American oil and gas development. Through December 2014, the field had cumulative production of approximately 1.1 billion bbl of oil and condensate and 4.8 trillion cubic ft of natural gas (TCFG). Average daily production during 2014 was approximately 1.3 million bbl of oil and condensate per day and 4.9 billion cubic ft per day of natural gas (BCFGD). The horizontal rig count in October 2014 was approximately 200, resulting in approximately 300 wells drilled per month (RigData). While the entire resource potential of the Eagle Ford is still quite subjective, it has been estimated to be as high 25 to 30 billion bbl of oil equivalent (BBOE). The Eagle Ford shale covers a vast area that spans approximately 7 million ac (2,832,799 ha) of continuous prospective reservoir and therefore should be considered as one oil and gas accumulation, or field. As a result of the aerial extent of the field occurring at depths ranging from approximately 5000 ft (1524 m) to the north to approximately 13,000 ft (3962 m) to the south, the product mix covers the entire spectrum from low gravity–low gas oil-ratio oil to dry gas, and everything in between. The Eagle Ford Formation lies above the Buda limestone and beneath the Austin chalk over the entire field area. The formation varies in thickness from approximately 250 ft (76 m) to as much as 600 ft (183 m) and is composed of a variety of facies. The primary reservoir facies, herein referred to as the Hawkville facies, is the primary reservoir and is located near the base of the formation. The Hawkville facies, named for the field area located in LaSalle and McMullen Counties where the net reservoir thickness is found to be in excess of 300 ft (91 m), is a calcareous mudstone that was deposited in an anoxic environment as part of the Cretaceous seaway that traversed north to south through west-central United States and Canada. Long known as a source for oil and gas production from other Cretaceous reservoirs such as the Buda, Austin chalk, Olmos, and others, the Eagle Ford has moderate to high total organic content (TOC) ranging from 3 to 5% and thermal maturities based on vitronite reflectance ranging from approximately 0.7 to 1.3. Operationally, the field has proven to be one that has been relatively benign from a drilling perspective. The Tertiary is at the surface and is a sand-dominated section extending to as deep as approximately 8000 ft (2438 m) near the down dip limits of the field and results in excellent rates of penetration. The Cretaceous Midway, Taylor, and Austin formations also provide consistent drilling conditions. Wells in the field that are in the measured depth range of 15,000 to 18,000 ft (4572 to 5486 m) are commonly drilled from spud to total depth in 8 to 12 days or less. Completion operations are similarly advantaged. The reservoir is extremely brittle and is very receptive to the high-rate hydraulic fracturing processes that are necessary to establish commercial production, with a very low percentage of screened out fracture stimulation stages. Production operations vary widely based on product type, gas-to-oil ratio, and the volatility of the liquid. However, to date, there have not been material changes in the gas-to-oil ratio of the producing wells that would suggest degradation of ultimate recoveries based on bubble point or dew point effects. The regulatory and community effects have also been relatively benign in terms of impediments to the development of the field. The state of Texas and the oil and gas industry have a long history of working in a collaborative manner. Very early in the field’s history, the Eagle Task Force, led by railroad commissioner David Porter, was organized with members from the state bureaucracy, industry, and community with the intent of promoting economic activity, establishing best practices across the play, and reacting to issues that affected the constituencies within the group. One of the most significant issues is water usage, which is a common issue in all unconventional development that utilizes isolated multistage hydraulic fracturing. One of the benefits to the field is the presence of the Carrizo aquifer, which underlies a vast majority of the field. The Carrizo is a fresh-water aquifer that has proven to be an excellent source of water without experiencing material depletion, primarily because of its extremely large amount of available water and because it is actively replenished except in times of severe drought.

ABSTRACT Perla gas field is a world-class giant and one of the most significant in Latin America in the last decade. The field was discovered in August 2009. It is the largest gas field in Latin America with approximately 17 trillion cubic feet (tcf) of gas in place, or 3.1 BBOE. The field, located in the shallow waters of the Gulf of Venezuela, was discovered, and is operated by Cardon IV S.A., a 50/50 joint operating company formed by Repsol and Eni. The Perla discovery is important because it is a Play opener for the southern Caribbean domain, triggering a new exploration cycle in the region and proving a previously unknown Tertiary thermogenic petroleum system. The discovery well encountered a thick carbonate section (240 m [787 ft] thick) with excellent primary reservoir properties. The trap is a combination structural and stratigraphic, defined by a northwest–southeast trending asymmetric faulted structure and pinch-out of the carbonate reservoir rock to the north. The proven hydrocarbon column exceeds 350 m (1148 ft) and is in complete hydraulic continuity, and the structural-stratigraphic closure exceeds 100 km 2 (39 mi 2 ).

ABSTRACT This chapter will address the innovative and bold exploration approach that has led the French company Total and its Argentinean partner Tecpetrol to achieve what is one of the largest gas discoveries of the south Bolivian sub-Andean basin of the 2000–2010 decade. This discovery, named Incahuasi, is the result of multidisciplinary teamwork covering a period of 4 years from the initial geological concept definition to the drilling and testing of the discovery well Incahuasi-X1. The overall approach can be summarized as a combination of controlled risk decision making based on a regional geological knowledge and the development of new techniques such as the definition of dedicated biostratigraphy charts. This approach enabled the multidisciplinary team to manage most of the uncertainties attached to this specific foothills context and define a workflow that led to success. The successful testing of the Incahuasi-X1 exploration well in 2004 led to a multi-tcf discovery currently under development. Located more than 120 km (75 mi) north of the existing Devonian gas fields, it opened a new exploration domain. It also highlights the benefit of a multidisciplinary and innovative approach in challenging areas such as the fold belts from prospect generation to discovery in a time constraint domain.

ABSTRACT As the operator of several exploratory blocks in ultradeep waters, Petrobras was responsible for many presalt oil discoveries in Santos Basin such as Tupi, Carioca, Guará, and Iara. In partnership with the National Petroleum, Natural Gas and Biofuels Agency (ANP), Petrobras drilled well 2-ANP-2A, which resulted in the Libra discovery. In 2013, Libra was offered in the first bidding round executed by the Brazilian government under the new Production Sharing Contract for presalt areas. The winning consortium is comprised of Petrobras (operator), Shell, Total, CNOOC (China National Offshore Oil Corporation), CNPC (China National Petroleum Corporation), and PPSA (Pré-Sal Petróleo S.A.). The Libra discovery is sitting over a structural trap of about 550 km 2 (212 mi 2 ) closure at the Aptian top reservoirs level presenting a maximum oil column that can reach up to 900 m (2953 ft). The main reservoirs are lacustrine carbonates, deposited from the Neobarremian until the Aptian. Preliminary estimates indicate a volume of oil in place between 8 and 12 billion BOE. The development proposed for Libra started with Phase 0, in 2014, and is focused on information gathering, including appraisal wells, extended well tests (EWT), early production systems (EPS), and a pilot project. Phase 1 encompasses the definitive production systems and is expected to start in 2022 and finish in 2030.

ABSTRACT Pão de Açúcar is certainly one of the most impressive and challenging hydrocarbon accumulations found in the prolific Campos Basin, offshore Brazil. This discovery opened a new frontier for exploration in Brazil’s ultradeep waters, in depths ranging from 2500 to 2900 m (8202 to 9514 ft). Pão de Açúcar is the third discovery made by a consortium integrated by Repsol Sinopec Brasil (operator), Statoil do Brasil, and Petrobras in the Concession BM-C-33, with estimated resources of 700 million bbl of light oil and 3 tcf of gas. This discovery is the result of the integrated work of a multidisciplinary international team using some of the most advanced technologies available today in the oil exploration industry in seismic imaging, drilling, formation evaluation, and fluid-rock sampling analysis. This discovery consists of a significant hydrocarbon column hosted within a unique reservoir made up of a variety of basic volcanic rocks overlain by pervasively silicified microbial carbonate platform/ramps, grading toward profundal lake facies. This chapter summarizes the main results of the exploration and ongoing appraisal work regarding this unique hydrocarbon accumulation, highlighting both the complexity of the discovered reservoirs and the operational and technical challenges faced, and still to overcome, before beginning production.

ABSTRACT The giant Johan Sverdrup field was discovered in 2010 by well 16/2-6 drilled on the Utsira high, in the central part of the Norwegian North Sea. This area was considered exhausted after more than 40 years of disappointing on-and-off exploration drilling. The discovery of the significant Edvard Grieg field by well 16/1-8 in 2007 converted the Johan Sverdrup prospect to a high probability prospect. The predrill hypothesis was that the two prospects could be part of one large deposit with a 40 to 50 m (131 to 164 ft) saturated oil leg beneath a gas cap and a common oil–water contact (OWC) shallower than 1950 m (6398 ft) mean sea level (MSL). The exploration wells unfolded two normal pressured discoveries with undersaturated nonbiodegraded oil on the flank of a saturated system with biodegraded oil and 6 bar overpressure. The Edvard Grieg discovery well proved a 40 m (131 ft) oil column above 1939 m (6362 ft) MSL on the west side of the high. The reserves in the plan for development and operations (PDO) were estimated to be 186 million BOE. This number has later been adjusted upward. The predrill estimate was 250 BOE. The reservoir sand was potassium rich and was indicated as shale and water bearing on the wireline logs. Without coring, the reservoir could have been overlooked. The reservoir is proximal Jurassic–Triassic deposits consisting of aeolian, braided river, and alluvial facies. Reservoir quality is also documented in Valanginian bioclastic sandstone and weathered basement. The Johan Sverdrup discovery well was located to obtain maximum sequence stratigraphic information above the potential OWC at 1939 m (6362 ft) MSL on the east side of the high. The well proved an oil–water contact at 1922.5 m (6307 ft) MSL and showed that the discovery extended into the neighboring license to the west. The main reservoir in Johan Sverdrup is locally derived shallow marine transgressive Volgian sand, overlying reservoir rocks from Zechstein carbonates, lower and upper Jurassic continental to shallow marine sandstones separated by several unconformities. The PDO for the unitized field was issued in February 2015 with a reserve range of 1.7 to 3.0 billion bbl. The main reserve uncertainties are related to recovery factor, oil saturation, time–depth conversion variations, reservoir thickness estimation, and sequence resolution. The oil is nonbiodegraded and heavily undersaturated, and has low varying gas–oil ratio (GOR) and OWC varying from 1922 to 1935 m (6306 to 6348 ft) MSL with a substantial residual oil zone below the current free water level (FWL). This reflects the glacial-induced isostasy effects on FWL during Pleistocene. The Edvard Grieg and Johan Sverdrup fields are situated on the southern part of the Utsira high referred to as the Haugaland High. This high is situated where the northwest extension of the Paleozoic to recent Tornquist wrench zone meets the Caledonian front between Scotland and Norway. In early mid-Jurassic the Haugaland High was part of a regional thermal inversion doming in the central North Sea. Several significant erosional and transgressive events determined the distribution of high-quality condensed Jurassic reservoir sequences from early to late Jurassic. Late Pliocene and Pleistocene subsidence, including tilting toward the southwest and uplift in the northeast, brought the Johan Sverdrup field into its current structural position. The late structural formation implies late and ongoing migration into the reservoirs. Regional mapping of the shallow Miocene sands in the Utsira Formation showed seismic hydrocarbon indicators of petroleum migration from east to west, sourced by vertical leakage from the Johan Sverdrup field at Jurassic level. The westward migration ends in a glacial tunnel valley that cut into the Miocene sand. Gas flares at sea bottom consisting of gas derived from biodegraded oil have been sampled. This gas leakage has resulted in the formation of patchy carbonate crusts, a process that has been ongoing since the last glaciation. Coring and production testing have been instrumental for the unfolding of the Edvard Grieg and Johan Sverdrup fields. Improved wireline logging procedures have been used in formation evaluation. The acquisition of 3-D ocean bottom seismic (OBS) and broadband seismic surveys in 2009 and 2012 has also been a catalyst for the unfolding process.

ABSTRACT The Tamar gas field, discovered in 2009 by Noble Energy, Delek, and partners, paved the way for a series of presalt discoveries that expanded our understanding of the petroleum systems in the east Mediterranean and the region’s hydrocarbon prospectivity. Approximately 40 tcf of natural gas has been discovered in the Oligocene–Miocene so-called Tamar sands play offshore Israel and Cyprus, which includes some of the largest deep-sea gas discoveries in the world over the last decade. The Tamar field development was expedited such that first gas occurred by March 2013, a mere 51 months following drilling of the wildcat well. Deep-water presalt exploration offshore Israel began in 2003 with the Hannah-1 dry hole. Following a 5-year hiatus, a new subsalt exploration and drilling program began in earnest in 2008, resulting in gas discoveries at Tamar, Dalit, Leviathan, Dolphin, Tanin, Aphrodite, Karish, and Tamar Southwest. The main presalt play area likely extends nearly 30,000 km 2 (11,583 mi 2 ) in water depths of approximately 1300 to 1700 m (4265 to 5577 ft), in the exclusive economic zones of Egypt, Israel, Cyprus, Lebanon, and Syria. The Tamar sands reservoir section is comprised of deep-sea floor fan sandstones punctuated by relatively thin beds of silts and mudstones. The accumulations are characterized by thick deposits, over 250 m (820 ft) of gross pay at Tamar, of high-quality reservoir with >20% porosity and >500 mD permeability. The lean gas (over 98% methane) is thought to be biogenic and sourced from the interbedded shaley units, whereas the seal is the regionally extensive early Miocene silty-shaley unit termed the Ng10 shale. Traps are faulted, four-way closures reaching over 100 km 2 (39 mi 2 ) at Tamar and approximately 330 km 2 (127 mi 2 ) at Leviathan, the largest discovery to date. Over 140 m (459 ft) of conventional core has been collected from one appraisal and two development wells at Tamar, and an extensive suite of side-wall cores were taken in the other wells. Core calibration has proven critical to petrophysical evaluation, resource assessment, and completion design. The Tamar field was developed in under 51 months from discovery to first gas for $3.25 billion in gross development capital. Current production at Tamar is accomplished from five subsea wells, each capable of producing over 250 MMSCF/day and tied back through a subsea manifold to a fixed-leg processing platform located some 150 km (93 mi) south of the field. At the time of development, this was the longest deep-sea tieback in the world. From there, the treated gas is flowed to an onshore terminal in the coastal city of Ashdod. Tamar is currently the only significant provider of natural gas to Israel and has supplied nearly 1.0 tcf of gas as of year end 2016, which fuels over 50% of the local market’s power generation needs. The discovery and development of Tamar opened a new chapter for the eastern Mediterranean oil and natural gas industry.

ABSTRACT The discovery of the Jubilee field in the Tano Basin of Ghana opened a new play in the deep water of the Atlantic transform margins. The field is a late Cretaceous combination structural-stratigraphic trap associated with topography created by the transform tectonics during the opening of the Atlantic. Prior to the drilling of the discovery well, the African transform margin had seen very little deep-water exploration with only nine wells drilled over a margin more than 2000 km (1243 mi) long. The field was discovered in June 2007 with the Mahogany 1 well, which encountered 98 m (322 ft) of high-quality oil pay in a Turonian-aged fan sequence trapped in a combination structural-stratigraphic trap. Subsequent to the discovery, accelerated appraisal and phased development resulted in first production in November 2010. The field is currently producing more than 100,000 BOPD and has a planned peak production of 120,000 BOPD. The discovery has resulted in an industry-wide exploration campaign of over 50 wells in the last 8 years. These have resulted in a number of additional discoveries and to date at least one additional development. This chapter describes the exploration play concept and the geology of the field.

ABSTRACT The Windjammer prospect spud in late 2009, leading to the discovery of 190 trillion cubic feet (tcf) in the offshore region of the Rovuma Basin in northern Mozambique. The key reservoirs are composed of stacked submarine fan complexes from the Oligocene, Eocene, and Paleocene epochs of the lower Tertiary. The submarine fans form traps truncating against the leading edge of the Palma fold and thrust belt. The high-permeability reservoirs are thick, widespread, and very well connected, making them ideally suited for long-term natural gas production and liquid natural gas (LNG) exports. The massive amount of gas found offshore Rovuma has the potential to elevate Mozambique to the world’s third-largest exporter of natural gas.

ABSTRACT The Jansz-Io gas field is located in production licenses WA-36-L, WA-39-L, and WA-40-L within the Carnarvon Basin, northwest shelf, Australia. It is 70 km (43 mi) northwest of the Gorgon gas field, 140 km (87 mi) northwest of Barrow Island, and 250 km (155 mi) from Dampier on the northwest coast of Western Australia. Water depths vary from 1200 to 1400 m (3937 to 4593 ft) across the field. The Jansz-Io gas field was discovered in 2000 by the Jansz-1 exploration well. A three-dimensional (3-D) seismic survey was acquired in 2004, and a further five wells were drilled between 2000 and 2009 to further delineate the field extent and size and characterize the resource to facilitate progress toward development. The Jansz-Io hydrocarbon trap extends over 2000 km 2 (772 mi 2 ) with both structural (faulted anticline) and stratigraphic (reservoir pinch-out) components. The stratigraphic component of the trap is defined by the reservoir extent, which is limited by depositional downlap to the northwest, and erosional truncation by Upper Jurassic and Lower Cretaceous unconformities to the southeast. The reservoir comprises muddy, bioturbated, predominantly very fine- to fine-grained sandstones deposited in a shallow-marine environment and is divided into two units. The upper wedge reservoir has 25 to 35% total porosity with 10 to 1000 md permeability, and the lower wedge reservoir has 15 to 25% porosity with 0.01 to 10 md permeability. Both reservoir units are expected to contribute gas during production. The original gas in place (OGIP) for the Jansz-Io Oxfordian reservoir has a probabilistic range from 320 to 946 Gm 3 (11 to 33 tcf), with a P50 value of 632 Gm 3 (22 tcf). The ultimate recovered gas for the field will depend on both the development plan and the reservoir performance over field life. For the current 15-well development plan, the resource estimates range from 201 to 442 Gm 3 (7 to 16 tcf). The Jansz-Io gas field is a key part of the greater Gorgon liquified natural gas (LNG) project and will supply gas to the LNG plant that is being constructed on Barrow Island. The development concept includes subsea completions from three drill centers placed on the seafloor connected to a subsea production pipeline to carry gas to the LNG processing plant. For the first stage of field development, 10 development wells were successfully drilled and completed during 2012 and 2014. The second drilling campaign is planned to commence after field start-up with the timing dependant on field performance.