Wildcat Wells Research Articles

Evolution History of Overpressured and Normally Pressured Shale Gas Reservoirs in Wufeng Formation–Longmaxi Formation, Sichuan Basin, China: An Analysis from the Perspective of Source and Seal Coupling Mechanism

Among the shale gas fields in the Sichuan Basin, the Fuling, Changning, and Weiyuan fields with Wufeng Formation-Longmaxi Formation as the target formation have made significant contributions to the shale gas industry in China. However, several other areas in the basin which have witnessed gas flow from wildcat wells have not realized commercial development. In this study, we analyzed the Wufeng Formation–Longmaxi Formation shale gas reservoirs from the perspective of a coupling mechanism of source and seal, by considering three aspects, including the characteristics of source and cap rocks, evolution history of the source rock–reservoir caprock, and the differential enrichment of shale gas. The results indicate the following: (1) The occurrence of the regional caprock (Triassic gypsum-salt) determines the distribution of overpressured and normally pressured shale gas reservoirs. In addition, the erosion of the caprock and its integrity control the gas content and cost-efficiency of the normally pressured shale gas reservoirs. (2) For the overpressured reservoirs, the thickness of the siliceous and carbonate-bearing siliceous shales in the WF2-LM4 graptolite zone determines the gas content and producibility of the lower shale gas layer. In terms of the upper layers, the structural form plays a critical role. Generally, gas reservoirs in the upper layers that occupy the higher part of an anticline are more favorable, whereas those in a syncline or monocline exhibit poor productivity. (3) For the normally pressured shale gas reservoirs with poor caprock integrity, the enrichment and the commercial value of the gas depend mostly on the thickness of the WF2-LM4 graptolite zone. Therefore, we conclude that the areas near the core of synclines are more favorable and structurally stable, with relatively high formation pressure and moderate burial depths. Our findings can improve sweet spot prediction and offer valuable guidance for shale gas development in China and globally.

Delineation of Subsurface Structures Using Gravity Data of the Shallow Offshore, Lamu Basin, Kenya

Lamu Basin is located in South Eastern Kenya and covers about 170 000 km2 both onshore and offshore. Kenya’s Lamu Basin is hitherto underexplored even though there have been notable oil and gas discoveries along the margin of East Africa. This study focuses on the shallow section of the Lamu offshore bounded by 39°E to 43°E by 2°S to 6°S, whereby, unfortunately, some of the wildcat wells turned out to be dry although expensive. Gravity interpretation techniques such as spectral analysis and first horizontal derivative were applied to the reduced gravity data to delineate and model structures to minimize the high investment risks. The gravity data used in this study were sourced from the International Gravity Bureau (BGI) and National Oil Corporation of Kenya (NOCK) digital data courtesy of companies like Woodside Energy, Anadarko Kenya Limited, and Total Exploration and Production companies. The obtained reduced gravity data were gridded to produce the gravity anomaly grids (Free air, Bouguer, and Isostacy), which were consequently drawn into maps. From spectral analysis, depths to shallow sources and deep sources were estimated. These depths were used to set regional and residual separation filters using the Gaussian filter. The first horizontal derivative (FHD) applied to the regional Isostatic gravity anomaly map yielded features that were inferred as intrasediment fractures/faults trending in NW-SE and NE-SW directions. The features like the ridges, troughs, and faults mainly trending in the NW-SE direction are discernable from the regional anomaly map. The developed models show the basement highs and lows with a possibility of anticlinal and synclinal structures and thick sedimentary successions likely to represent good hydrocarbon source kitchens.

The Sureste Basin of Mexico: its framework, future oil exploration opportunities and key challenges ahead

Abstract The Sureste Basin of Mexico is a story of split exploration maturity, with more than 139 discoveries in the onshore and shallow-water area of the Sureste in a series of stacked prolific plays, but less than 12 exploration wildcat wells on the Campeche slope, in water depths greater than 500 m. Over 50% of the basin area lies in this under-explored deep-water Campeche slope, with future oil potential shown by the presence of wide seabed oil seepage indicating a regionally mature world-class source rock to be present. With the 2014 opening of Mexico's oil industry, basin-wide 3D seismic imaging of this under-explored deep-water extension to the Sureste Basin is now in the hands of international oil companies that hold substantial exploration well commitments over the next few years. This paper discusses the hydrocarbon play potential of both the classic Tertiary slope clastic reservoir systems as well as the significant Mesozoic carbonate reservoir potential for which there are fewer analogues outside of Mexico. Subsurface challenges originating from dry hole analysis relate to charge timing and deep charge focus, subsalt deep structural imaging, deep reservoir quality issues and uncertainty in column height prediction, given the high-relief nature of many undrilled salt related structures.

Shallow water 3D in South Gabon: a new generation of hydrocarbon prospects

Global exploration has seen a dramatic upturn in 2018, with close to 4 billion barrels of oil equivalent discovered in the first half of the year alone, and many exciting wildcat wells still to come. Although the oil price slide of 2014 changed the industry, with the focus now on commerciality and risk reduction, it is of interest that most of the new discoveries this year have been made in commercially challenging deep water. The reason for this is that our industry has been exploring shallow-water oil-prone basins since the invention of marine seismic methods in the 1950s, and they appear now to be ‘mature’ and depleted in material low-risk opportunities. Indeed the future of shallow-water exploration has been portrayed as binary: either mopping up around what we know or exploring new frontiers. However, in South Gabon we challenge the established idea that after 50 years of exploration the basin is mature, by revealing a new generation of prospectivity with modern 3D acquisition and processing (Figures 1 and 2). The play primarily chased so far has been the Gamba Sandstone play, the seismic imaging of which has always been a significant challenge, owing to the complex velocities in the post-salt geology, the heterogeneity and the halokinesis of the Ezanga Salt. Yet with the exception of the Muruba-2 discovery, few wells have deliberately targeted the syn-rift section below the Gamba, leaving the pre-salt section completely unexplored (Figure 1). Diligent planning and acquisition (Esestime et al., 2017, 2018) of 3D data in South Gabon covering an area eight times the size of Greater London (11,500 Km2), has enabled an imaging veil to be lifted. The intra-syn-rift is now visible and is revealing large-scale hydrocarbon prospects, capable of attracting interest from global exploration players (Figure 3).

Analysis on the causes of failed wildcat wells in the eastern Pearl River Mouth Basin and its enlightenment

Analysis on the causes of failed wildcat wells in the eastern Pearl River Mouth Basin and its enlightenment

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

Abstract The exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×10 9 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×10 9 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

Lower Paleozoic stratigraphy and petroleum potential of the Wallal Rift System, southwest Canning Basin, Western Australia

The Wallal Rift System (new name) extends north-northwest for more than 300 km along the southwestern margin of the Canning Basin. The rift contains the Wallal and the Waukarlycarly embayments and the Samphire Graben. The rift segments vary in depth to 4.5 km and are all under-explored. Seismic coverage is better in the north than in the south. Six shallow wildcat and stratigraphic wells in the north provide some control on the age of the pre-Permian section. Another well on the northeastern flank of the Samphire Graben terminated in Neoproterozoic granitic rocks beneath the Lower Ordovician Nambeet Formation. The well is tied to a seismic line that indicates a synrift Ordovician section in the graben. An equivalent section is inferred in the Wallal and the Waukarlycarly embayments, and Permian syn-rift sediments are recognised in all rifts. Transtension along a regional geosuture—the Camel-Tabletop Fault Zone—may have caused initial rifting during the waning of the Paterson Orogeny (c. 550 Ma), co-incident with extrusion in the Kalkarindji Large Igneous Province. Thus, Cambrian volcano-clastics deposits may be present at the base of the (2–3 km thick) pre-Permian section, which is considered to be primarily Early Paleozoic sediments and expected to contain potential source rocks. A relatively hot Proterozoic crust and eruption of continental flood basalts during the Cambrian may have facilitated source rock maturation. Reservoirs may be more common along rift-margins and intra-rift ridges, where fault-controlled traps are also present.

Comments: Offshore Resilience

Editor's column Twenty-five years ago next month, the oil and gas industry’s worst offshore disaster took place. The explosion and fire on the Piper Alpha North Sea oil production platform killed 167 men and left only 61 survivors. The anniversary will be commemorated with a 3-day safety conference in Aberdeen and the refurbishment of a memorial sculpture honoring the victims. The accident ushered in a new safety culture in the oil and gas industry as well as a new regulatory mandate. That sector of the industry recovered and has made steady improvements in safety since. Three years ago, the Macondo Gulf of Mexico accident rocked the industry, and its implications are still being felt. From all appearances at last month’s Offshore Technology Conference in Houston, the offshore sector is booming and even more mindful of the necessity of safe operations amid an exploration renaissance. Operators expect a tougher regulatory regime in the Gulf of Mexico going for-ward, one that could lead to some industry consolidation, according to a survey report released at OTC by GL Noble Denton. The survey of 100 senior oil and gas industry executives found that 85% of respondents expect the US regulatory regime to become much tougher over the next 2 years and 61% believe that regime will negatively affect their businesses. Speakers at OTC sessions echoed those sentiments. The industry should expect new rules about well control equipment, blowout preventers, and production systems, according to Randall Luthi, president of the National Ocean Industries Association. But he expects overall production from the Gulf of Mexico to continue to increase, and communication between regulators and the industry to continue to improve. E&P activity has rebounded in the Gulf since Macondo. New rigs are being delivered and wildcat wells are being drilled. The most recent deepwater activity report issued by the US government shows a total of 36 floating rigs operating in the Gulf compared with 30 at the time of the Macondo accident, and a total of 51 projects are under way in more than 1,000 ft of water. In a keynote speech at the recent SPE European HSE Conference and Exhibition in London, Phil Hemmens, managing director of Eni UK, said he believes high-profile accidents such as Macondo and Piper Alpha put a burden on the industry to prove that it can manage its operations safely. The industry has made great strides over the past 30 or so years in raising safety standards and measuring occupational safety performance in a way understandable to regulators and the public. But it does not have key performance indicators (KPIs) that might indicate the potential for a major accident such as Macondo, he said. Although the industry has some indicators—information gleaned from near-misses or types of hydrocarbon releases—the complexity of deepwater and other projects has made standardizing KPIs difficult. Developing those indicators, and then applying them industrywide, would help both the industry and regulators identify and manage risk at the operational level more efficiently.

A reassessment of the petroleum systems in the offshore northern Perth Basin

The discovery of commercial oil in the Cliff Head-1 well in 2001 set an important milestone in the exploration history of the offshore northern Perth Basin. The region had been less explored before then, partly due to the perception that the main source of onshore petroleum accumulations, the Late Permian-Early Triassic Hovea Member, had only marginal potential offshore. The typing of the Cliff Head oil to the Hovea Member provided evidence that the key onshore petroleum system extends offshore and has revitalised exploration with 13 new field wildcat wells drilled since 2002. A reassessment of the hydrocarbon generative potential in the offshore northern Perth Basin confirms the widespread occurrence of good to excellent oil-prone Hovea Member source rocks in the Beagle Ridge and Abrolhos Sub-basin. The Early Permian Irwin River Sequence and several Jurassic Sequences are also recognised as prime potential source rocks offshore, mostly for their gas-generative potential. The unique hydrocarbon assemblages exhibited by the Hovea Member extracts are shared by the oils recovered from Permian reservoirs in the offshore Cliff Head-3 and Dunsborough-1 wells, indicating the Hovea Member as the primary source charging these accumulations. Geochemical correlation of oil stains from Hadda-1 and as far north as Livet-1 provides evidence for a working Early Triassic petroleum system across much of the Abrolhos Sub-basin. In this area, the Hovea Member was shown to be both of limited quality and only marginally mature for oil generation, which suggests the occurrence of effective source kitchens in the adjacent Houtman Sub-basin.

2011 PESA industry review: exploration

A continuing high and stable oil price through the latter part of 2011, oscillating around US$120 in the case of Tapis Crude, underpinned a small increase in exploration in 2011 in Australia compared with 2010, although there were marked regional differences between the northwest and southeast parts of the country. Exploration continued to be focused on the northwest offshore seeking incremental reserve additions of conventional gas to support planned and proposed liquid natural gas (LNG) projects and although information is hard to confirm, in general this program appears to have been successful with a number of relatively smaller discoveries and at least one major find, Zola–1. In the Cooper Basin exploration activity resumed after almost being shut down by floods in 2010, although flooding continued to be a problem in 2011. In the South Australian part, 27 new field wildcat (NFW) wells were drilled in 2011 compared with 8 in 2010. The program was also marked by a high rate of success. The other current major area of activity, the Queensland coal seam gas (CSG) program was also affected by flooding early in 2011 with 524 coal seam gas (CSG) wells drilled this year, compared with 648 in 2010 and more than 900 in 2009. In many jurisdictions shale gas or shale oil wells are not reported separately and are included in conventional petroleum wells in this report. Exploration for geothermal resources continued at a relatively low level with only 10 wells drilled in Australia in 2011, the most active state was Victoria with five wells. Despite the increase in activity, preliminary indications are that total exploration expenditure in 2011 will be less than in 2010. It is interesting to note that while the exploration effort in terms of wells and seismic has not changed much in the last few years the total expenditure has steadily increased in part reflecting the movement into deeper water drilling.

2010 PESA industry review–exploration

An uncertain global economy, offset by strong commodity prices, provided the backdrop to a subdued yet solid level of exploration activity in 2010. The major loci of activity in the Australian oil and gas industry were the Exmouth Plateau, where exploration for conventional gas in support of LNG projects was the primary driver, and the Bowen/Surat Basin, where coal seam gas (CSG) for LNG was the main target. Onshore permit awards dominated new licensing in 2010, with 31 exploration permits awarded over an area of 190,000 km2. The majority of these permits are focused on unconventional gas exploration. Conversely only 14 exploration permits (30,000 km) were awarded offshore, all in northwest Australia. This historically low level can be related to an already extensive coverage of existing permits in the offshore petroleum provinces and delays in the announcement of acreage awards from the 2009(II) acreage release. Twenty-nine 2D seismic surveys were started in 2010, with three still active at the end of the year. Once completed, the 2010 surveys will total nearly 37,000 km of data, with 76% offshore. Twenty-one 3D seismic surveys commenced in 2010, with six still active at year end. The 2010 surveys will ultimately comprise approximately 29,000 km2 of data, with 95% offshore. Northwest Australia dominated seismic activities. Exploration drilling for conventional hydrocarbon resources was relatively subdued in 2010, with 63 wells spudded, compared to 92 wells in 2008 and 74 in 2009. Of the 49 wildcat wells where results are known, 51% reported hydrocarbon discoveries. This was a little less than the 57% in 2009 and up on the 39% in 2008. The discoveries were distributed across most of the traditional petroleum provinces. High levels of CSG drilling continued in 2010, exceeding 2008 activity but less than that of 2009. At least 648 CSG wells were spudded in 2010, mostly in the new heartland plays of the Bowen/Surat, Gunnedah and Clarence-Moreton basins. This compares with more than 600 CSG wells drilled in 2008 and more than 900 in 2009. The first dedicated Australian shale gas exploration drilling took place in 2010. Emerging shale plays in the Cooper and Perth basins were tested.

New exploration opportunities in the offshore northern Perth Basin

The petroleum prospectivity of the northern Perth Basin has been assessed by Geoscience Australia (GA) as part of the Australian Government’s Offshore Energy Security Program, in support of the 2011 offshore acreage release. This assessment includes the first published synthesis of data from fourteen new field wildcat wells drilled in this part of the basin since the Cliff Head 1 discovery (2001), and the interpretation of new regional 2D seismic data acquired during GA survey 310. Most petroleum accumulations in the northern Perth Basin are associated with Permian and Triassic source and reservoir intervals, and are found onshore and nearshore (ie. Cliff Head, Frankland, Dunsborough and Perseverance discoveries). In addition to the technical and commercial successes, numerous wells in the offshore part of the basin have intersected residual oil columns indicative of trap breach. New and legacy palynological data from Permian to Cretaceous strata in offshore wells have been used to provide age constraints for a sequence stratigraphic framework for this part of the basin. New seismic data show Permo-Triassic strata that are stratigraphic equivalents of the productive onshore and nearshore Perth Basin petroleum system, also occur within Permian half-graben in the outer Abrolhos and Houtman sub-basins. Source rock, oil stain and fluid inclusion sampling from this interval suggest that the proven onshore petroleum system is also effective in the offshore. A refined tectono-stratigraphic model for the offshore basin provides insights into basin evolution, prospectivity and contributing factors driving trap breach. Geochemical sampling in the context of the new detailed sequence framework, including from recently dredged rock samples from incised canyons, has also provided insight into the potential effectiveness of a Jurassic/Cretaceous petroleum system in the Houtman and Zeewyck sub-basins.

Infracambrian petroleum play elements of the NE Taoudenni Basin (Algeria)

Abstract The Taoudenni Basin, North Africa's largest sedimentary basin, is located in western Mauritania, northern Mali and southwestern Algeria. Of the four petroleum wildcat wells drilled to date, the Abolag-1 well, Mauritania, yielded gas shows in Infracambrian (Neoproterozoic) stromatolitic carbonates. We present details of the different plays of the basin from the Chenachène region in Algeria. The Infracambrian is generally composed of three sedimentary packages: a basal sandstone (a unit of the Douik Group), overlain by carbonates (the Hank Group), sandstones and shales (the Dar Echeikh Group). The play is sourced by Infracambrian organic-rich black shales. In neighbouring Mauritania these were penetrated by water wells and shallow boreholes, containing in places >20% TOC. In the Hank Group the best reservoirs are associated with fractured intervals. The Dar Echeikh Group includes several potential reservoir units with porosities of up to 26%. Potential petroleum trap types in the Algerian part of the Taoudenni Basin are associated with folds, the basal Palaeozoic unconformity, and Infracambrian and Triassic–Jurassic half-graben.

2008 Exploration review

The year 2008 saw a global financial crisis and a collapse in the price of oil from its earlier highs in the latter part of the year. Not surprisingly, there was an overall decline in exploration activity for conventional oil and gas, although this consisted of a substantial fall in onshore activity partially offset by a modest increase in offshore activity. Activity in the coal seam gas (CSG) sector, on the other hand, continued the rapid growth trend that has been evident in the preceding 2 – 3 years. This sector can now be regarded as having ‘come of age’, and is reported for the first time in this review. Discoveries of conventional oil and gas were concentrated on the North West Shelf and in the Cooper/Eromanga basins, consistent with previous trends. Success rates were highest in the Browse, Bonaparte, Carnarvon and Cooper/ Eromanga basins. A total of 27 discoveries were recorded. In the CSG arena, reserve additions of almost 9,000 PJ were made in Eastern Australia during 2008, primarily in the Surat and Bowen basins. These reserve additions are expected to underpin the development of an LNG export industry in Queensland. Offshore licencing activity was down on 2007, with the Bonaparte and Browse basins having most new permits awarded. There was a resurgence of interest in onshore Queensland and NSW acreage for CSG exploration. Despite the drilling of a number of wildcat wells in frontier basins including the Murray, Darling, Sorrell, Canning and Pedirka, regrettably none was successful.

Petroleum geoscience in Norden – exploration, production and organization

Offshore exploration in Norway and Denmark-in the North Sea, the Norwegian Sea and the Barents Sea-has involved drilling about 850 wildcat wells, resulting in about 300 oil and gas finds, of which 84 are fields with production. The recoverable resources of all these finds total about 65 billion barrels of oil equivalent. Almost all these hydrocarbons come from a Jurassic source and the main reservoirs and traps are Jurassic sandstones in fault blocks and Paleocene sandstones or Cretaceous chalks in gentle domes. The article describes four major fields-Ekofisk, Gullfaks, Ormen Lange and Snohvit- to illustrate some of the many challenges in developing and producing the hydrocarbons. Elsewhere in Norden, there has been much less exploration. Drilling results have mostly been negative in mainland Sweden, onshore Denmark, onshore Svalbard and on- and offshore West Greenland. Minor oil finds have been made in Palaeozoic rocks in the Baltic Sea. The first wells have recently been drilled off the Faroe Islands, resulting in one discovery. No drilling has taken place on- or offshore East Greenland. As a result of the hydrocarbon activities in Norway and Denmark, petroleum geoscience there has flourished, with 2000 geoscientists currently employed in the industry, many technical innovations made, a wealth of publically available information and a great increase in the understanding of the geology.

The Rise of New Bodacious Independents

Guest editorial As almost everyone knows, there has been a dramatic consolidation in the oil industry over the past 2 decades. However, many may not realize the extensive impact this shift has had on independent producers and how these companies have reinvented themselves in the face of change. Of 36 publicly traded independent producers in 1997, only 12 remained in 2007. Fig. 1 charts the growth of the remaining independents, mostly by acquisition, measured in enterprise value. A few have emerged as so-called "super independents," such as Anadarko and Devon, followed by Apache, Chesapeake, and XTO. To put these companies into perspective, Anadarko and Devon have grown individually to become the same size ChevronTexaco was 5 years ago and more than three times the size of Unocal when ChevronTexaco bought it 3 years ago. The chart also illustrates how the corporate landscape has changed since 1997. A decade ago, Unocal was the largest US-based independent. Today, Unocal and many other familiar names are gone. Some of these surviving independents have achieved stature on an international scale. If you were to combine Anadarko and Devon, you would create a company larger than the national oil companies of Spain (Repsol) or of Norway (StatoilHydro). The growth of these super independents is also evident in the size and complexity of the field developments they are willing to tackle. Consider the Chuck prospect in the U.S. Gulf of Mexico (GOM), a USD 100 million wildcat being drilled in 6,500 ft of water. Devon is operator of Chuck, with a 40% interest. The company and its partners, ExxonMobil, ConocoPhillips, and Maersk, are drilling through a substantial salt canopy, targeting a Lower Tertiary reservoir more than 33,000 ft deep, and the Chuck exploratory well is expected to reach total depth this quarter. The GOM's deep water is a frontier even for the super majors. Yet Devon runs second behind only Chevron in acreage within the trend. Despite the technological challenges that stretch the industry to the brink of its capability, Devon has flourished in the deepwater environment. So far, the company has been involved with seven wildcat wells in the Lower Tertiary. Four have been discoveries, two were unsuccessful, and completion of the Chuck well is expected later this year. Looking ahead, Devon has 18 additional Lower Tertiary prospects waiting to be explored. In July 2007, the enormous Independence Hub began producing natural gas from 10 separate deepwater fields in the eastern GOM. The hub's designers stretched the limits of conventional construction to build a platform capable of producing 1 Bcf/D of natural gas. The Independence Hub is more than a technological feat. As its name implies, the hub represents a new day, a new stature, and a new role for the nation's independent energy producers. It represents the collaboration of Anadarko, Hydro, Devon, and Dominion. The companies combined innovation and cooperation to achieve an objective they could not have accomplished individually.

Geology and evaluation of hydrocarbon prospects of Tethyan sediments in Spiti Valley, Spiti and Zanskar, Himanchal Pradesh

The Tethyan sediments in the Spiti Basin stretch from Pir Panjal in the south to the Zanskar Range in the north. The Tethyan sediments lie within the Higher Himalayan Physiographic Zone. Since such huge thicknesses of sediments are deposited in this area, it is anticipated by the geologists that favourable conditions might have prevailed for the generation and accumulation of hydrocarbon in the Tethyan sediments. It has been continuous endeavour of ONGC to explore and enhance hydrocarbon reserves from all Indian sedimentary basins including the category IV and frontier basins. Seismic data acquisition and geological modelling have been carried out for Lesser Himalayas and even parametric, structural, or wild cat wells have been drilled and one such well is under drilling at Sundernagar. The Tethyan part being inaccessible has not been subjected to detailed geological modelling. Mesozoic sequences from Kibber Gate Tashegang and Lidang Domal traverses have been subjected to sedimentological, Palaeontological, Palynological and source rock investigations to reconstruct microfacies, biochronostratigraphy, depositional environment, and organic matter maturation. The petrographic study of the Mesozoic Tethyan sediments exposed along the selected traverses shows occurrence of Kioto Limestone, Spiti Shale, Giumal Sandstone, Tashegang Limestone and Chikkim Limestone formations. The Kioto Limestone is highly sparitised and has poor porosity. The Giumal Sandstone consists of glauconitic sands which are well indurated and have very poor intergranular porosity. The porosity is further reduced by calcite cementation. Similarly, the Tashegang Limestone is also highly sparitised and has poor porosity. Spiti shale is dark grey, black, carbonaceous, occasionally oxidised in nature. Brachiopod fauna supportive of Lower Carboniferous age has been recorded from Lipak Formation and Ordovician Silurian fauna from Takche Formation. Cephalopods supportive of Oxfordian Callovian age have been recovered from Spiti Shale. Lilang Group has yielded rare Cephalopods of Triassic Jurassic age. On the basis of FAD of Riguadella filamentosa and Egmontodinium torynum Late Bathonian to Late Tithonian age has been suggested to Spiti Formation. On the basis of FAD of E. cinctum and Batioladinium micropodum, Late Tithonian to Early Valanginian age has been suggested to Tashegang Formation. On the basis of FAD of B. micropodum the base of Giumal Formation is dated as Early Valanginian. The absolute pollen frequency (APF) value of the palynofloral assemblage from Spiti Formation suggests inner neritic to marginal marine environment of deposition, while palynoflora from Tashegang Formation indicate marginal marine to lagoonal environment and Giumal Formation was laid under marginal marine conditions. The Organic matter recorded from the studied samples shows Humic-Wood (H-W) to Humic-Sapropelic-Wood (HS-W) to Humic-SapropelicCharcoal (HS-C) facies.

油田の生産プロファイルと発見関数に基づく世界原油生産推移の予測

World crude oil production forecast has been predicted based on several production scenarios of the Middle East oil producers and production profiles as well as discovery functions of known and yet to find oil fields in other regions. The global production forecast as well as the timing of peak oil substantially depends on the production scenario of the Middle East producers, so that the timing of the peak oil cannot be specified. On the other hand, it has also been found out that the rates of decrease in the production after peak oil varies more than double according to different production scenarios of the Middle East producers.Following three scenarios have been assumed for production forecast of Middle East producers, namely (i) keep their current production level; (ii) increase production level to cope with the growth of the global demand; (iii) adjust production rate to keep the current global production level; all these three until R/P ratio decreases down to 25 years, thereafter decreasing the production to keep the same level of the R/P ratio. The starting period of declining in the production as well as the rate of decrease in production after it largely depends on the above scenarios. The earliest decline in global production is elicited in case (i) as starting from year 2010, the second earliest in case (ii) as starting from year 2025, the latest in case (iii) as starting from 2033 (or 2034 in case of growing exploration activities). On the other hand, the rate of decrease in the production is most moderate in case (i), initially declining at less than 2% per year. Fatalistic rate of decrease in the production has been suggested in case (ii), initially declining at more than 4% per year.The intensity of exploration activities represented by the number of wild cat wells, outside Middle East and US except Alaska, in the range under consideration, does not largely affect the global production forecast. But it still has limited but certain effect to eliminate the rate of decrease in production once after peak oil has been emerged.

DEVELOPMENTS IN THE CENTRAL AND NORTHEASTERN EAST COAST BASIN, NORTH ISLAND, NEW ZEALAND

Oil production in the East Coast Basin began in the late 19th century from wildcat wells near oil seeps. By the mid-20th century, geology was being applied to oil exploration, but with little success. In the late 20th century, seismic techniques were added to the exploration arsenal and several gas discoveries were made. At each stage it was recognised that exploration in this difficult but tantalising basin required more information than was available. Continuing work by exploration companies, as well as by the Institute of Geological & Nuclear Sciences (GNS), has begun to reduce the risk of exploration. Source rocks have been identified and sophisticated thermal models show that petroleum is being generated and expelled from them as shown by numerous oil and gas seeps onshore. Many potential reservoir sequences have been recognised from outcrop studies and depositional models are being refined. All components of petroleum systems have been demonstrated to be present. The most important deficiency to date is the general lack of high-quality seismic data which would allow recognition of reservoir facies in the subsurface.During early 2005, Crown Minerals, the New Zealand government group charged with promoting and regulating oil and gas exploration, commissioned a high specification regional 2D survey intended to address some of the main data gaps in the offshore East Coast Basin. A broad grid was planned with several regional lines to be acquired with a 12,000 m streamer and infill lines to be acquired with a streamer 8,000 m long. It was expected that the long streamer would increase resolution of Paleogene and Cretaceous units. Several of the lines were actually acquired with a 4,000 m streamer due to unexpectedly high rates of unserviceability. The resulting 2,800 km data set consists of a series of northwest–southeast lines approximately orthogonal to the coast at a spacing of about 10 km as well as several long strike lines.GNS was contracted to produce a series of reports covering source rock distribution, a catalogue of reservoir rocks, a regional seismic interpretation, thermal models and structural reconstruction. The data package and reports are available free of charge to any interested exploration company to accompany the licensing round that was announced on 1 September 2005. The new data set has confirmed the existence of a large, little-deformed basin to the north of North Island and the Bay of Plenty; it has elucidated the complex structure of a large part of the East Coast Basin and has enabled generation of a general sequence stratigraphic model which assists in delineating reservoir targets. On 1 September 2005, the New Zealand government launched a licensing round covering about 43,000 km2 of the East Coast Basin, from the far offshore East Cape Ridge in the north to the northern Wairarapa coast in the south. Four blocks (I, J, K and L) were on offer for a competitive staged work programme bid, closing on 17 February 2006.

Exploration history on the Norwegian Continental Shelf, 1990–2002: expectations and results

The exploration activities on the Norwegian Continental Shelf during the period 1990–2002 were analysed; 300 wildcat wells were drilled and 134 discoveries made. A dataset consisting of 240 wildcat wells and 83 discoveries was studied. The volumetric in-place prognosis of the prospects were compared with the actual exploration results. The analysis indicates that exploration appears to have been determined by the chance of finding oil and that there is no obvious correlation between prospect volume, proximity to infrastructure and probability of discovery. Comparison of the prognosed and the discovered volumes shows that, in total, the prognosis is double the actual discovery volumes. This is mainly due to overestimation of oil prospects, as discovered gas tends to match the prognosis. The volume of discoveries smaller than 100 × 10 6 Sm 3 oil equivalents (OE) corresponds to the prognosis, whereas prospects larger than this are overestimated. The best match is found for prospects in the 50 – 100 × 10 6 Sm 3 OE size category. Exploration of prospects is undertaken with too great a risk and there is no relation between prospect size and probability of discovery, except for the very large prospects which have lower probability than the rest of the prospects. There is no evidence for better performance in mature areas and overestimation is characteristic for most companies. The match between prognosis and actual volume is good for fields (approved for development), whereas discoveries in the planning phase are significantly higher than prognosed. The disappointing discoveries are either still unclarified or unlikely to be recovered. Results of exploration activity constitute an important part of the QC of prospects reported to NPD when these data are used for the evaluation of the undiscovered resources. NPD uses modelled prospects for calculation of the undiscovered resources.