Tcf Of Gas Research Articles

Tectonic and stratigraphic evolution of the Cambrian basin of northern Northwest Territories

Abstract The Cambrian basin of the mainland Northwest Territories has been of considerable economic interest since gas was first discovered in Mount Clark Formation sandstones in 1974. A recently completed assessment by the Geological Survey of Canada has estimated that the Cambrian Clastics play contains almost a billion barrels of oil and 10.7 TCF of gas. The play’s reservoirs, seals and source rocks are all of Cambrian age, making the understanding of the basin’s evolution and contents critical to any exploration effort. The basin is a semi-enclosed, epicontinental marine basin, bordered by positive elements and open to a subsiding continental shelf and margin, and represents the eastern portion of a much larger deposystem that developed after the breakup of Laurentia. A multi-disciplinary study of a large regional reflection seismic grid, supported by borehole and potential field data, shows the basin to have evolved in three stages: 1) Early Cambrian pre-rift regional subsidence of the area lying inland of the Mahony and Bulmer arches, and a newly identified high that pre-dated the Mackenzie Trough. It was during this period that the Mount Clark Formation was deposited; 2) A middle Cambrian rift phase during which a graben system, about 50 km wide and over 400 km long, developed in the basin’s core. The grabens are deepest in south Mackenzie Trough where rifting began, and are progressively shallower and younger to the north and northeast. Mount Cap was deposited during this phase and it is expected that the grabens received finer-grained clastics than did the shallower areas on their flanks; 3) A post-rift subsidence phase that began with deposition of the Saline River Formation during the Late Cambrian and continued, with interruptions, until the middle of the Devonian. Throughout Cambrian time, sediment onlapped the basin’s flanks and its internal arches, each layer advancing further than its predecessor. It was not until the latest Cambrian that the internal arches were completely covered by beds of the lower Franklin Mountain Formation. A previously undocumented Cambrian age graben (herein named McConnell Graben) lies in the hanging wall of the unnamed Laramide thrust fault that emerges from the east flank of the McConnell Range. The fault began as a Cambrian normal fault that separated the Bulmer and Mahony arches on the east from McConnell Graben on the west. The present day ‘St. Charles’ range developed in a similar manner. A preliminary exploration risk analysis, based on the predicted distribution of reservoir, seal and source rocks, reveals two attractive areas for exploration. The larger one, centred on Lac des Bois, is about 150 km wide and extends on a NW-SE trend for about 300 km across the Aubry and Good Hope depocentres. The smaller area (less than 50 × 100 km in extent) lies within Mackenzie Plain depocentre.

A New Automated MPD System Used in an Onshore Depleted Gas Field

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130319, ’Experience and Results with a New Automated MPD System while Drilling and Cementing Liner in an Onshore Depleted Gas Field,’ by Paul Fredericks, SPE, and Ossama Sehsah, SPE, At Balance, and Julio Montilva, SPE, and Phil Vogelsberg, SPE, Shell E&P Company, originally prepared for the 2010 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Kuala Lumpur, 24-25 February. The paper has not been peer reviewed. An automated and modular managed-pressure-drilling (MPD) system recently was used in two wells to hold constant bottomhole pressure (BHP) in a very narrow pressure window without a backpressure pump. In the first well, the system was used to drill in 740 ft of 75/8-in. liner in an 8½-in. hole with 15.0-lbm/gal mud statically underbalanced relative to wellbore stability. Introduction The McAllen and Pharr fields are in Hidalgo County in south Texas. Those fields were acquired by the opera-tor in 2006, and over the 7 decades since discovery, nearly 1.4 Tcf of gas has been produced from reservoirs in the Frio formations. Initial production was from shallow zones, many of which now are depleted by as much as 5,000 psi. The fields have an extended history of commingled production and complex patterns of difficult-to-map faults that make pore pressure and depletion difficult to predict. Isolating the severely depleted zones with liners is impractical because often they are found between overpressured virgin sands. Compared with nearby fields in the Vicksburg formations, those in the Frio have higher permeability and require heavier mud weight to avoid influx. Another limiting factor in the McAllen/Pharr fields is the ease with which losses occur in many of the reservoir sands as a result of the lower minimum horizontal stress caused by depletion. The resulting narrow pressure profile and the inaccurate pore-pressure predictions complicated early drilling efforts with excessive lost circulation and well-control events.

Exploration in Australia 2000–2010: reviewing a decade of growth

Oil and gas exploration in Australia, both on and offshore, has been centred on a small number of proven petroleum provinces and—given the extent of prospective basinal area that exists—it remains relatively under-explored to this day. Since the 1970s, companies have progressively spent a smaller proportion of their exploration budgets on onshore and shallow water targets, where discoveries have been regular yet unspectacular, in favour of the deeper waters, where higher risks are involved but the potential exists for significantly higher returns. This activity has led to the discovery of more than of 150 Tcf of gas in the North Carnarvon, Browse and Bonaparte basins, the majority of which sits in deepwater areas. An absence of infrastructure and a lack of an adequate market meant that these huge discoveries lay undeveloped; however, with developments in technology and demand for gas in Asia set to surge into the next decade, these previously stranded fields are set to move into development, underpinning economic growth in Australia and ensuring that the country moves to the forefront of the LNG industry worldwide. This paper will examine upstream activity, both on and offshore, in Australia since 2000, a decade in which the country has become one of the most prominent destinations for exploration expenditure in the world. Following the exploration cycle from acreage release through to discovery, it will look at how trends and activity have changed over time and examine how successful the industry has actually been. It will explore the factors driving activity and the effects external forces such as regulatory changes, oil price and prevailing economic conditions have had on activity levels. No post-Conference paper is available for this presentation. No post-conference paper is available for this presentation.

Marginal production in the Gulf of Mexico – II. Model results

In the second part of this two-part article on marginal production in the Gulf of Mexico, we estimate the number of committed assets in water depth less than 1000 ft that are expected to be marginal over a 60-year time horizon. We compute the expected quantity and value of the production and gross revenue streams of the gulf’s committed asset inventory circa. January 2007 using a probabilistic model framework. Cumulative hydrocarbon production from the producing inventory is estimated to be 1056 MMbbl oil and 13.3 Tcf gas. Marginal production from the committed asset inventory is expected to contribute 4.1% of total oil production and 5.4% of gas production. A meta-evaluation procedure is adapted to present the results of sensitivity analysis. Model results are discussed along with a description of the model framework and limitations of the analysis.

Industry Perspectives on Barriers, Hurdles, and Irritants Preventing Development of Frontier Energy in Canada's Arctic Islands

The Canadian Arctic Islands and intervening channels are known to be rich in hydrocarbon resources. The combined Hecla and Drake Point discoveries of Sabine Peninsula on Melville Island have recoverable and marketable natural gas reserves estimated at almost 9 trillion cubic feet (Tcf). Proven reserves for the western Sverdrup Basin, drilled and delineated by industry exploration between 1969 and the early 1980s, are 17.5 Tcf gas and 1.9 billion barrels (bbl) of oil while total resources for Sabine Peninsula and western Sverdrup basin are estimated at 44 to 50 Tcf gas and 3.5 to 5.5 billion bbl oil (Chen et al., 2000). The Canadian Energy Research Institute (CERI) has recently released a report (Chan et al., 2005) which indicates that transportation of proven Melville Island gas is economically viable for development scenarios involving either liquefied natural gas (LNG) tanker shipments to the eastern seaboard of North America or compressed natural gas (CNG) vessels to a Mackenzie Valley pipeline. In spite of these findings, however, there is still significant industry reluctance to develop the gas resources of the Arctic Islands. This paper describes specific industry concerns with the development of Arctic Islands resources. Data were gathered during telephone interviews with exploration and development managers representing six medium-to-large domestic and multinational energy companies operating on the Arctic frontiers of North America. The issues discussed were identified in a Natural Resources Canada study entitled “Reducing the Geoscientific, Environmental and Regulatory Barriers to Exploration, Transportation and Development of Energy in the Arctic Islands.” The approach taken for each interview was to provide some historical background on the topic, explain the purpose of the interview, and then ask respondents’ opinions on which issues are most significant in accounting for the failure to renew exploration in Canada’s Far North and the lack of progress on developing existing proven reserves. It became apparent with the first interview that some issues, such as the lack of development infrastructure and certain regulatory problems, could be considered true barriers to energy development in the Arctic Islands, but other issues were viewed as either hurdles or mere irritants. It also became very clear that the potential solutions available to government scientists and regulatory agencies cover a broad spectrum. The paper concludes with specific recommendations for future work.

Australia Outback Could Be Next World-Class Unconventional Play

A small Colorado independent believes the 7 million acres it has under license in the heart of the Australian Outback could very well be the world's next gargantuan unconventional oil and gas play. "This is a huge resource," consultant Chris Moyes said of the Falcon Oil & Gas holdings in the vast Beetaloo Basin of the Northern Territory. "It is the biggest unconventional resource we know outside of North America. It certainly is of the same class as Gorgon and potentially bigger." That, indeed, is saying something considering the Chevron Gorgon liquefied-natural-gas (LNG) project at Barrow Island on the Northwest Shelf is widely touted as one of the world's largest-ever production ventures. When combined with existing developments and some 11 proposed greenfield projects, Gorgon will play a key role in Australia's objective of overtaking Qatar as the world's top LNG exporter and possibly help reverse its declining oil production. As Gorgon dominates most of the news coming out of Australia of late, Falcon is quietly going about seeking strategic partners for a prospect that Moyes said will be a "100-year project." "It will take a long time to fully exploit a resource of this size and type," he said. Falcon is very optimistic about the project's potential, particularly because it may hold almost 20 billion bbl of oil and 64 Tcf of recoverable gas and is located within a ready-made infrastructure and on the doorstep of one of the world's biggest markets (Fig. 1). "We are very excited about the activity that is going on in the Beetaloo Basin," said Falcon board member Steve Shultz. "We think it has the potential to be a very big part of the Falcon portfolio." Reservoir evaluation consultancy Ryder Scott conducted an independent analysis of the Falcon Beetaloo holdings and determined the prospect could contain 19.1 billion bbl of oil and 63.9 Tcf of gas. Those estimates were classified as "unrisked prospective resource best estimates," which for undrilled prospects typically is generated by integrating seismic interpretation with regional geologic data and taking into account a number of geological risk factors. Those include the trap risk, source risk, and reservoir risk, which Ryder Scott defines as "the probability that a lithology exists with sufficient porosity, permeability, and continuity to contain moveable hydrocarbons." Moyes said as much as 80% of the Beetaloo resource base is unconventional tight gas and oil. More Seismic Needed The Beetaloo, however, has not been entirely undrilled. Between 1989 and 1998, Pacific Oil and Gas drilled 11 wells, all of which showed the presence of oil and gas. Most of those earlier wells were drilled as part of a mining program. "They were looking for minerals, but of course, they got oil and gas shows and began to think of it as an oil and gas play," said Moyes, president of Moyes and Company, upstream technical and transaction advisers assisting Falcon in securing prospective partners.

Hydrocarbon production forecast for committed assets in the shallow water Outer Continental Shelf of the Gulf of Mexico

In 2007, the federal waters of the Gulf of Mexico averaged daily production of 1.3 million barrels of oil and 7.6 billion cubic feet of natural gas. The majority of oil is produced from deepwater fields in water depth greater than 1000 ft, while most gas production is extracted from the shelf. The Outer Continental Shelf is a mature province with over 3800 fixed structures and 6500 producing wells connected into an integrated pipeline network more than 30,000 miles in length. The purpose of this paper is to develop a methodology to forecast oil and gas production in the shallow water Gulf of Mexico. Structures are categorized according to age and production characteristics, and forecast procedures for each asset class are described and illustrated. The methodology is implemented using the inventory of committed assets circa December 2006. The expected amount of hydrocarbon production arising from the inventory of committed assets under stable reservoir and investment conditions is estimated to be 1056 MMbbl oil and 13.3 Tcf gas valued between $85 and 150 billion. The results of generalized regression models are presented with a discussion of the limitations of analysis.

Perforating Techniques and Use of Cesium Formate Kill Pills To Maximize Productivity in HP/HT Gas Wells and Minimize HSE Risks

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19242, "An Evaluation of Perforating Techniques and Use of Cesium Formate Kill Pills To Maximize Productivity in HP/HT Gas Wells and Minimize HSE Risks," by Alistair Roy, SPE, Allan Twynam and Jeff Parke, BP; Angus Morrison, Schlumberger; and John Downs, Cabot, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. The BP-operated Rhum field is a North Sea high-pressure/high-temperature (HP/HT) lean-gas field. A key design requirement was to evaluate overbalance- and dynamic-underbalance-perforating techniques to optimize productivity while reducing the risk of producing hydrocarbons to surface during downhole operations. This case history focuses on available perforation techniques with the aim of matching or exceeding the flow performance achieved on the appraisal-well drillstem test (DST). Introduction The Rhum field is 45 km north of the Bruce field (Fig. 1). It has three subsea development wells tied back to the host Bruce production platform. The water depth is approximately 108 m. The field has several challenges. Bottomhole temperature and pressure (BHP) were 300°F and 12,500 psi, respectively. The lean-gas reservoir fluid leads to high surface pressures (>10,000 psi). The rock strength varies from 8,000 to 30,000 psi unconfined compressive strength (UCS). Middle sour environment is expected with H2S levels of 10 to 20 ppm and CO2 levels between 4 and 8%. Appraisal Well 3/29a-4 was spudded in August 2000, and testing was completed in February 2001. This well confirmed that the field was an HP (12,418 psia at 4745 m true vertical depth subsea), lean-gas discovery with approximately 1 Tcf of gas initially in place. Completion Objectives From the start of the project, a desired objective for the Rhum completions was to maintain at least one mechanical barrier and one fluid barrier while running the completion. This combination was essential risk mitigation for running completions in a subsea environment. Only two clear fluids were capable of delivering the required 1.9- to 2.2-specific-gravity (SG) brine weight: cesium formate and zinc bromide. The environmental risks of working with zinc bromide were deemed unacceptable; therefore, cesium formate was selected. It was decided to evaluate whether cesium formate could be used during perforation to avoid the complicated rig ups and multiple runs required for deploying the required number of perforations by use of coiled tubing (CT) or electric line (E line).

Global Infracambrian petroleum systems: a review

Abstract This review covers global uppermost Neoproterozoic–Cambrian petroleum systems using published information and the results of studies undertaken by the Geological Survey of Western Australia (GSWA) on the Neoproterozoic Officer Basin. Both production and hydrocarbon (HC) shows sourced from, and reservoired in, uppermost Neoproterozoic–Cambrian successions occur worldwide, and these provide ample incentive for continuing exploration for these older petroleum systems. However, the risks of charge volume, timing of generation–migration v. trap formation and preservation of accumulation are significantly higher than in conventional Phanerozoic petroleum systems. Therefore, the location and assessment of preserved HC accumulations in such old petroleum systems presents a significant exploration challenge. Organic-rich metamorphosed Proterozoic successions of SE Greenland, the Ukrainian Krivoy Roy Series, the Canadian Upper Huronian Series and the oil shales of the Russian Onega Basin are known as the world's oldest overmature petroleum source rocks. The oldest live oil has been recovered from the McArthur Basin of Australia ( c . 1.4 Ga; Ga is 10 9 years), followed by the Nonesuch oil of Michigan. Numerous other petroleum shows have been reported from Australia, Canada, China, India, Morocco, Mauritania, Mali, Oman, Pakistan, Venezuela and the USA. These demonstrate that generation and migration of Proterozoic petroleum has occurred worldwide. The Siberian Lena–Tunguska province, the Russian Volga–Ural region and the Middle Eastern south Oman petroleum fields exemplify the productive potential of uppermost Neoproterozoic–Cambrian successions, where petroleum generation, migration and trapping were either late in the geological history (Palaeozoic–Mesozoic, Oman) or where accumulations have been preserved beneath highly effective super-seals (Lena–Tunguska). The total resource potential of the Lena–Tunguska petroleum province is estimated to be 2000 Mbbl (million barrels) oil and 83 Tcf (trillion cubic feet) gas. The equivalent proven and probable reserves derived from Neoproterozoic–Early Cambrian source rocks and trapped in Late Neoproterozoic (Ediacaran), Palaeozoic and Mesozoic reservoirs in Oman are at least 12 bbbl (billion barrels) of oil and an undetermined volume of gas. The recovery of 12 Mcf (million cubic feet) of Precambrian gas from the Ooraminna-1 well in the Amadeus Basin in 1963, together with the occurrence of numerous HC shows within the Australian Centralian Superbasin, triggered the initial exploration for Proterozoic hydrocarbons in Australia. This included exploration in the Neoproterozoic Officer Basin, which is reviewed in this paper as a case study. Minor oil shows and numerous bitumen occurrences have been reported from the 24 petroleum exploration wells drilled in the Officer Basin to date, indicating the existence of a Neoproterozoic petroleum system. However, the potential of the Neoproterozoic petroleum system in the vast underexplored Officer Basin, with its sparse well control, remains unverified, but may be significant, as may that of many other ‘Infracambrian’ basins around the world.

Evidence for deep anaerobic biodegradation associated with rapid sedimentation and burial in the Beaufort–Mackenzie basin, Canada

Abstract Formation waters of the 14 km thick late Cretaceous–Cenozoic Beaufort–Mackenzie basin were examined as part of a larger project to better understand the petroleum potential of the region, where early exploration defined petroleum reserves of 744 × 109 bbls recoverable crude oil and 11.74 tcf gas. Historical water analyses (2583 samples from 250 wells drilled up to 5 km depth) were compiled and culled to remove incomplete and poor quality samples. The resultant database shows a broad range of salinity and water chemistry that has no systematic relationship with depth. Three main water types are defined, paleo seawater, and freshwaters related to a Miocene age gravity-driven flow system, and low TDS–high alkalinity waters. High alkalinity waters are isolated in overpressured fault blocks that were rapidly buried by post-Miocene Iperk shale deposition. The high alkalinities (up to 9000 mg/L) are interpreted to be related to in situ CO2 generation through anaerobic methanogenesis in response to freshwater invasion. The dominant control on biogenic gas generation appears to be maximum burial temperature rather than the modern temperature distribution. This is consistent with the paleopasteurization model that suggests once critical burial temperatures are reached, sterilized rocks are inhibited from further biodegradation, even when temperatures subsequently drop back into the habitable zone.

<b>Fossil fuel energy resources of Ethiopia</b>

Inter-Trappean coal and oil shale-bearing sediments are widely distributed in the Delbi-Moye, Lalo-Sapo, Yayu, Sola, Chida, Chilga, Mush Valley, Wuchale and Nejo Basins. Coal and oil shale-bearing sediments were deposited in fluvio-lacustrine and paludal depositional environments. The Ethiopian oil shales reach a maximum thickness of 60 m, and contain mixtures of algal, herbaceous and higher plant taxa. Type II and I kerogen dominated the studied oil shales. Pyrolysis data revealed that the Ethiopian oil shales are good to excellent source rocks types up to 34.5 % TOC values and up to 130 HC g/kg S2. A total of about 653,000,000 - 1,000,000,000 tones of oil shale reserve registered in the country. The coal and coal-bearing sediments attain a maximum thickness of 4 m and 278 m, respectively. Proximate analysis and calorific value data show that the Ethiopian coals fall under the soft coal series (lignite to bituminous coal), and genetically classified under humic, sapropelic and mixed coals. A total of about 297,000,000 tones of coal reserve registered in the country. The Permian Bokh Shale, Oxfordian-Bathonian Hamanlei Limestones, Kimmeridgian Urandab Shale are potential organic-rich source rocks. The Permian Calub sandstone, Triassic-Liassic Adigrat sandstone and Oxfordian-Bathonian Hamanlei carbonates are reservoirs in the Ogaden and Blue Nile Basins. 2.7 TCF (76 x 109 m3) sulfur-free gas and 1817 x 106 tons condensate reserves are estimated in the Calub field. About 1.3 TCF gas deposit is also encountered in Hilala field. The Blue Nile Basin is one of the potential basins for hydrocarbon exploration. The presence of mature source rocks and oil seepage in the Blue Nile Basin is clue for the generation of hydrocarbon in the basin. The Gambella Basin is the southern extension of the petroliferous Sudan Interior Basins, and could be one of the potential basins for oil and gas deposits. KEY WORDS: Coal, Energy, Ethiopia, Fossil fuel, Oil shale, Oil and gas Bull. Chem. Soc. Ethiop. 2008, 22(1), 67-84.

Characterizing the shale gas resource potential of Devonian–Mississippian strata in the Western Canada sedimentary basin: Application of an integrated formation evaluation

Devonian–Mississippian strata in the northwestern region of the Western Canada sedimentary basin (WCSB) were investigated for shale gas potential. In the subsurface, thermally mature strata of the Besa River, Horn River, Muskwa, and Fort Simpson formations attain thicknesses of more than 1 km (0.6 mi), encompassing an area of approximately 125,000 km2 (48,300 mi2) and represent an enormous potential gas resource. Total gas capacity estimates range between 60 and 600 bcf/section. Of particular exploration interest are shales and mudrocks of the Horn River Formation (including the laterally equivalent lower Besa River mudrocks), Muskwa Formation, and upper Besa River Formation, which yield total organic carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom have TOC contents above 1 wt.%. Horn River and Muskwa formations have excellent shale gas potential in a region between longitudes 122W and 123W and latitudes 59N and 60N (National Topographic System [NTS] 94O08 to 94O15). In this area, which covers an areal extent of 6250 km2 (2404 mi2), average TOC contents are higher (3 wt.% as determined by wire-line-log calibrations), and have a stratal thickness of more than 200 m (656 ft). Gas capacities are estimated to be between 100 and 240 bcf/section and possibly greater than 400 tcf gas in place. A substantial percentage of the gas capacity is free gas caused by high reservoir temperatures and pressures. Muskwa shales have adsorbed gas capacities ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir temperatures of 60–80C (140–176F), whereas Besa River mudrocks and shales have low adsorbed gas capacities of less than 0.01 cm3/g (0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130C (266F). Potential free gas capacities range from 1.2 to 9.5 cm3/g (38.4 to 304 scf/t) when total pore volumes (0.4–6.9%) are saturated with gas. The mineralogy has a major influence on total gas capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower gas capacity (1% TOC and 1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal gas capacity, and a balance between favorable reservoir characteristics needs to be sought.

Deepwater Taranaki: the basin with no structure north of that big field in New Zealand

Deepwater Taranaki is investigated for its petroleum potential using using all available seismic data tied to shallow water wells. It contains up to 10 km of sediment. An early rift sequence is overlain by a large Late Cretaceous delta which culminates with Rakopi Formation coal measures. This sequence marks the break-up unconformity following the start of Tasman Sea spreading. A passive margin succession follows as the New Zealand mini-continent gradually subsided, with sediments becoming gradually finer grained until carbonates dominate during the Oligocene. Initiation of the present plate boundary about the start of the Miocene caused uplift and renewed clastic deposition in the form of spectacular channel and turbidite complexes. The present reconnaissance seismic grid indicates at least six subtle structures that are large enough to contain a billion barrels of oil or several TCF of gas, suggesting that the first drilling targets may be Late Cretaceous fluvial and marine sands draped across gentle basement structures. Cretaceous structures are commonly overlain by Miocene channel and turbidite sands that are also draped across underlying highs. The similar, but much smaller structures of Tui, Amokura and Pateke, below the Taranaki shelf, are currently being developed by AWE. Future drilling will take discoveries closer to the shelf edge and ultimately the larger prizes will be sought in deeper water.

Leaves in turbidite sands: The main source of oil and gas in the deep-water Kutei Basin, Indonesia

More than 6 tcf of gas and 200 million bbl of oil and condensate have been discovered in upper Miocene sandstones in the deep-water Kutei Basin, offshore East Kalimantan, Indonesia. Chemical analyses of oil, gas, and condensate indicate derivation from land-plant source material. Conventional cores and cuttings of deep-water strata show that the best source rocks are sandstones, not shales. Organic material in deep-water sandstones includes laminar coaly fragments, pieces of wood, resinite, and other coaly debris. Laminar coaly fragments are dominant, and their size, shape, and cuticle structure indicate that they were leaf fragments. Fossil leaf fragments occur in all deep-water sandstone packages from the upper slope to the basin floor. Fossil leaf fragments were apparently carried into deep water by turbidity currents during lowstands of sea level. Within turbidite sandstones, fossil leaf fragments are concentrated in layers with up to 50 wt.% total organic carbon (TOC). Kerogen that was separated from these layers has hydrogen index values of 200–500 mg hydrocarbon/g TOC. Kutei Basin deep-water shales contain mainly silt-size vitrinite grains with poor generative qualities. Microscale sealed vessel pyrolysis and kinetic and generation modeling indicate that land-plant kerogens occurring in quantities similar to the upper Miocene sandstones are capable of generating the gas and oil found in deep-water fields. Hence, leaf fragments in turbidite sandstones are interpreted as the main source for deep-water oil and gas. Liquids derived from leaves have caused production problems that include high pour points because of high wax contents and emulsions formed when fatty acids combined with water.

DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.

A Resourceful Industry Lands the Serpent

In 1997, Norsk Hydro cast a line with wildcat well No. 6305/ 5-1 and hooked a big fish even for the North Sea. In 2000, the industry stepped back and gave pause to the enormity of the undertaking. It had become clear that the Norwegian serpent, Ormen Lange, would be a heavyweight in all respects. The project takes its name from the ship of Viking King Olav Tryggvasson. Charting the course to landfall is a group of star licensee/operators—Hydro, Shell, Petoro, Statoil, Dong, and ExxonMobil. The giant serpent, stretching across four North Sea blocks, is destined to become a major European gas source, covering 20% of U.K. gas requirements for 40 years. The U.K. gas market is the largest in Europe, with annual consumption of 3.9 Tcf. From geologic and climatic perspectives, main subsea installations and pipelines will be subjected not only to mountainous terrain created in the scar area of the Storegga avalanche slide, but also to cold polar currents driven by the Gulf Stream, generating some of nature’s most brutal forces. Water temperatures on the seabed are below freezing for most of the year—perfect conditions for hydrate development. The ocean surface is thrashed by fierce winds and waves. Beyond these challenges, Ormen Lange is seen from Hydro’s vantage point as three concurrent projects—development of the reservoir with templates and pipelines to shore, design/construction of the Langeled pipelines (one with 42-in.-diameter and another with 44-in.-diameter pipe), and construction and operation of a processing plant. This intensely faulted reservoir (one study reports that more than 1,000 faults have been interpreted and included in simulations) is the second-largest gas discovery on the Norwegian shelf (the Troll field is the largest) and will be Europe’s deepest subsea development. Ormen Lange will contribute to a doubling of Hydro’s gas exports by the year 2010, making Norway the world’s second-largest gas exporter. The project is the largest in Norway’s history. With main gas reserves located in the Vale formation, drilling has already confirmed resources of 11 Tcf of gas; production is planned at 2.5 Bcf/D of gas and 53,463 B/D of condensate will be stored. The climatic and oceanographic conditions in the region of the find present severely challenging conditions, and forces created by wind and waves are as challenging as any other deepwater project. Some long-time veterans of the North Sea development call Ormen Lange the most challenging offshore project ever. In cooperation with internationally recognized Norwegian expertise, extensive studies have been conducted regarding the stability of seabed masses and slide safety along with future natural conditions, including potential tsunamis, and conditions resulting from project activities. The associated subsea-export-pipeline project is one of the largest undertaken by the industry. Gas will be transported more than 1200 km from Nyhamna via the Sleipner platform in the North Sea (Fig. 1). Total investment cost is estimated at U.S. $10.2 billion, including $7.2 billion for development and $3 billion for the transport system. A hotel built for workers at Nyhamna, where the gas-processing plant is being built, is larger than any other hotel in Norway (three times larger than the Oslo Plaza Hotel).

Assessment Methodology and Results From the Canadian Gas Potential Committee 2001 Report

Since 1991 volunteers from the Canadian Gas Potential Committee (CGPC) have conducted assessments of undiscovered gas potential in Canada. Reports were published in 1997 and 2001. The 2001 CGPC report assessed all established and some conceptual exploration plays in Canada and incorporated data from about 29,000 discovered gas pools and gas fields. Mainly year-end 1998 data were used in the analysis of 107 established exploration plays. The CGPC assessed gas in place without using economic cut offs. Estimates of nominal marketable gas were made, based on the ratio between gas in place and marketable gas in discovered pools. Only part of the estimated nominal marketable gas actually will be available, primarily because of restrictions on access to exploration and the small size of many accumulations. Most plays were assessed using the Petrimes program where it could be applied. Arps-Roberts assessments were made on plays where too many discovered pools were present to use the Petrimes program. Arps-Roberts assessments were corrected for economic truncation of the discovered pool sample. Several methods for making such corrections were tried and examples of the results are shown and compared with results from Petrimes. In addition to assessments of established plays, 12 conceptual plays, where no discoveries have been made, were assessed using Petrimes subjective methodology. An additional 65 conceptual plays were recognized, discussed, and ranked without making a quantitative assessment. No nominal marketable gas was attributed to conceptual plays because of the high risk of failure in such plays. Nonconventional gas in the form of coalbed methane, gas hydrates, tight gas, and shale gas are discussed, but no nominal marketable gas is attributed to those sources pending successful completion of pilot study projects designed to demonstrate commercially viable production. Conventional gas resources in Canada include 340 Tcf of gas in place in discovered pools and fields and 252 Tcf of undiscovered gas in place. Remaining nominal marketable gas includes 96 Tcf in discovered pools and fields and 138 Tcf of undiscovered nominal marketable gas. The Western Canada Sedimentary Basin holds 61% of the remaining nominal marketable gas. Future discoveries from that area will be mainly in pools smaller than 2.5 Bcf of marketable gas and increasing levels of exploratory drilling will be required to harvest this undiscovered resource. A pragmatic, geologically focussed approach to the assessment of undiscovered gas potential by the CGPC provides a sound basis for future exploration and development planning. Peer reviewed assessment on a play-by-play basis for entire basins provides both detailed play information and the ability to evaluate new exploration results and their impact on overall potential.

Coalbed Methane Development: Practices and Progress in Canada

Abstract As conventional gas supplies decline, unconventional sources of gas, like coalbed methane (CBM), will become increasingly important in Canada. Canada has over 700 Tcf of CBM gas resource in place, comparable to the U.S. resource. Canada now has the world's largest "dry" coal play and it is estimated (as shown below) that CBM will grow to 2 - 3 Bcf/d in production over the next 10 – 20 years and lead to recovery of up to 75 Tcf of gas. Since 2000, increased drilling activity has led to over 3,000 CBM wells and 150 MMcf/d of CBM production in Canada today, with both estimated to grow substantially in 2005 and beyond. CBM will become an increasingly important part of Canada's gas supply. Introduction Coalbed methane (CBM) is simply the natural gas that is generated by coal seams during the coalification process. It is "sweet gas" (not sour), is largely comprised of methane (>90%), and is similar to the natural gas that is burned in homes. In Alberta, the Department of Energy (DOE) refers to CBM as natural gas from coal, or NGC, to associate it with existing regulations which govern the production of natural gas. In British Columbia (BC), it is referred to by the Ministry of Energy and Mines (MEM) as coalbed gas, or CBG. Regardless of the name used, it is the same gas. CBM reservoirs are classified as "unconventional" and have gas storage and production mechanisms that distinguish them from conventional reservoirs. Most of the gas in coal is stored in a sorbed state within the coal matrix, physically attached to the complex internal surfaces of the coal as a function of pressure, characterized by sorption isotherms(1, 2). Coals which are suitable for CBM production are naturally fractured, with closely spaced natural fractures, or "cleats," which provide pathways for gas flow from the coal matrix. In many cases, but not all, these cleats are initially full of water, which must be produced to reduce the pressure around the coal matrix allowing the sorbed gas to desorb and become free gas which can then be produced. The gas storage and production mechanisms of coals are comprehensively covered in References (1) and (2) and elsewhere in the oil and gas literature. In Canada, commercial production of CBM has only recently begun. The objective of this paper is to provide a summary of the major coal groups being targeted for development in Canada and an update on the recent evaluation and development. Predictions of future performance will also be presented. CBM History in the U.S. Commercial development of CBM began in the U.S. in the 1980s. Initial efforts to remove the gas from coals were funded by the U.S. Bureau of Mines primarily to improve mine safety. As natural gas value increased, the research began to focus on capturing the CBM for commercial use, and hundreds of millions of dollars were dedicated to research and development projects by the U.S. DOE, the Gas Research Institute (GRI), and the industry(3–7).

Reservoir geology of Nicholas and Liverpool Cemetery fields (lower Pennsylvanian), Stanton County, Kansas, and their significance to the regional interpretation of the Morrow Formation incised-valley-fill systems in eastern Colorado and western Kansas

Reservoirs in the lower Pennsylvanian Morrow Formation of eastern Colorado, southwestern Kansas, and northwestern Oklahoma have produced greater than 8 tcf of gas and 200 million bbl of oil. This prolific depositional system produces from reservoirs representing a range of depositional environments from updip, fluvial-dominated, incised-valley fills to deep-water basin-floor systems. The valley fills of the Morrow Formation are of particular significance because they can be mapped in great detail from subsurface control over very long distances. Facies distributions in the valleys change systematically downdip. As a result, reservoir characteristics and trapping mechanisms vary with these changes in internal valley stratigraphy.This paper focuses on the reservoir geology of Nicholas and Liverpool Cemetery fields. These fields produce gas from the extreme downdip region of an incised-valley-fill system in the lower Morrow Formation. The valley systems in this downdip region are deeper and wider and demonstrate greater marine influence than the updip regions of the valley systems farther north and into the hinterland.Compartmentalization in these downdip reservoirs differs significantly from updip valley-fill reservoirs. The reservoirs in this downdip region are more highly compartmentalized because the dominant reservoir facies in these fields is a series of bayfill delta deposits. These deposits are isolated by shale deposits in the valley. This depositional setting contrasts markedly with predominantly fluvial reservoirs in updip regions of the valleys. Understanding the scale, geometry, and internal complexity of this depositional system is important because the associated sandstones are important gas reservoirs in southwest Kansas. Cores, wire-line logs, pressure data, and production data collected from the Morrow Formation at Nicholas and Liverpool Cemetery fields provide valuable information from which to describe and interpret this downdip valley fill. This paper describes the downdip incised-valley-fill reservoirs in this producing complex and documents the trapping relationships of these reservoirs and their production characteristics.

Petroleum system and production characteristics of the Muddy (J) Sandstone (Lower Cretaceous) Wattenberg continuous gas field, Denver basin, Colorado

Wattenberg field is a continuous-type gas accumulation. Estimated ultimate recovery from current wells is 1.27 tcf of gas from the Lower Cretaceous Muddy (J) Sandstone. Mean gas resources that have the potential to be added to these reserves in the next 30 yr are 1.09 tcf; this will be primarily through infill drilling to recover a greater percentage of gas in place and to drain areas that are isolated because of geologic compartmentalization. Greatest gas production from the Muddy (J) Sandstone in Wattenberg field occurs (1) from within the most permeable and thickest intervals of Fort Collins Member delta-front and nearshore-marine sandstones, (2) to a lesser extent from the Horsetooth Member valley-fill channel sandstones, (3) in association with a large thermal anomaly that is delineated by measured temperatures in wells and by vitrinite reflectance contours of 0.9% and greater, (4) in proximity to the bounding Mowry, Graneros, and Skull Creek shales that are the hydrocarbon source rocks and reservoir seals, and (5) between the Lafayette and Longmont right-lateral wrench fault zones (WFZs) with secondary faults that act as conduits in areas of the field. The axis of greatest gas production is north 25 to 35 degrees northeast, which parallels the basin axis. Recurrent movement along five right-lateral WFZs that crosscut Wattenberg field shifted the Denver basin axis to the northeast and influenced depositional and erosional patterns of the reservoir and seal intervals. Levels of thermal maturity within the Wattenberg field are anomalously high compared to other areas of the Denver basin. The Wattenberg field thermal anomaly may be due to upward movement of fluids along faults associated with probable igneous intrusions. Areas of anomalous high heat flow within the field correlate with an increased and variable gas-oil ratio.