Alberta has vast oil sands resources that are undergoing rapid commercial development. Expansion of existing plants and construction of new plants are expected to increase production of synthetic crude and diluted bitumen from about 1 million barrels per day in 2003 to over 2 million barrels per day by 2012 and to about 5 million barrels per day by 2030. These oil sands products and by products offer abundant sources of petrochemical feedstocks, potentially capable of supporting new world-scale plants producing ethylene, propylene, benzene, para-xylene, and other high-value-added derivatives.
The paper describes the results of joint industry/government engineering studies that identify viable process schemes for olefin production from existing and future oil sands plants.
The first study evaluates the phased development of an integrated oil sands-petrochemical complex starting with extraction of olefins from existing oil sands process streams and progressing to full integration of oil sands upgrading, refining and petrochemical plants producing both high quality fuels and new world scale quantities of petrochemicals olefins and aromatics.
The second study examines the marketing logistics and economics of producing refined products and primary petrochemicals in Alberta relative to producing only synthetic crude oil. The advantages and challenges of integrating refining and petrochemicals production and the need for processes with improved performance with heavy feedstocks and product flexibility are discussed.
Alberta is a major North American energy hub, providing oil and gas to United States markets through extensive pipeline networks. In addition to conventional oil and gas, Alberta has large oils sands, coal and coal bed methane resources. Alberta is also a hub for future pipelines from northern gas fields in Alaska and the Canadian McKenzie Delta. Future expansion of pipelines from the oil sands regions to the Canadian West Coast is expected to connect oil sands products to California and Asian markets through ocean tanker transport. Oil sands are crude oil deposits that are essentially heavier (more viscous) than other crude oils. Oil sands consist of sand, bitumen, mineral-rich clays, and water. Bitumen is a product of the oil sands that requires upgrading to synthetic crude oil (SCO), or dilution with lighter hydrocarbons, to make it transportable by pipelines and usable by refineries.
Oil Sands Reserves
Alberta has huge deposits of oil sands that underlie 140,800 square kilometers of the province. The International Energy Agency estimates Alberta's bitumen in-place resources at 1,630 billion barrels, and the ultimate recoverable reserves at 310 billion barrels. Alberta's Energy Utilities Board estimates that 174 billion barrels are proven reserves that can be recovered using current technology, which puts Canada second (15% of world reserves) after Saudi Arabia ranks in terms of world oil reserves (see Figure 1).
(Figure in full paper)
Oil Sands Production - Current and Projected
Currently, there are 1,807 oil sands lease agreements with the province, totaling 32,000 square kilometers, leaving close to 80% of the possible oil sands areas still available for development. In 2003, oil sands marketable production of bitumen and SCO averaged 740,000 barrels per day (540,000 bpd of SCO and 360 bpd of bitumen).
Deep-water basins such as those found offshore West Africa, the Guld of Mexico and other locations offer great promise in satisfying the world's growing need for oil and gas reserves. At the same time, they pose special challenges in finding, developing and producing the reserves to realize this potential. Traditionally, 3-D seismic surveys have been a main factor in reducing risk and lowering costs in both exploration and production. Now, new-generation surveys involving Q-Technology are proving that higher resolution and improved control and fidelity significantly improve reservoir imaging over conventional seismic data. In particular, applications of Q-Technology promise to lower costs and reduce risk for offshore West Africa exploration and production.
Deep-water seismic data are often plagued by reverberations that can obscure the primary information. The sensitivity and fidelity of Q data allow these reverberations to be attenuated to reveal the underlying geological structure and rock properties. A second important challenge in deep-water plays involves seismic imaging around salt. In this regard, Q data provide better penetration and imaging in salt tectonic environments. Although current drilling targets in West Africa are not generally pre salt, nevertheless, imaging beneath salt is important in understanding the petroleum system since delineating source rocks and migration paths can be critical for field development. Moreover as West Africa matures, sub salt plays likely will become important. Finally, the high resolution of Q data is proving seminal in early field development by identifying potential permeability barriers. Indeed, the results obtained in such early stages of field development promise that the value of Q data can be realized even earlier in the process. By using Q technology in the exploration phase, Q information can be used in locating first targets and in the planning of facilities, _
Deep-water basins offer great promise in satisfying the world's growing need for oil and gas reserves. However, although the rewards can be great, the financial and safety risks are enormous. Traditionally, 3-D surveys had been the main factor for reducing those risks, but new-generation 3-D and 4-D surveys utilizing Q-Technology* are now making further strides. There are many features that distinguish this new technology. The four most prominent ones are the Calibrated Marine Source (for determining the far-field wavelet at each shotpoint), the acoustic positioning system (for accurately measuring the locations of the hydrophones), the streamer steering system (for mitigating feather and maintaining constant streamer. separation), and single-sensor recording (for finely sampling the signal and noise wavefields).
This paper discusses how these aspects of Q-Technology favorably influence the reduction of risk in deep-water surveys. High-resolution surveys.
High-resolution surveys In an empirical study, Kallweit and Wood (1982) observed that when at least two octaves of bandwidth are present in a white, zero-phase, noise-free wavelet, the temporal resolution is determined solely by the maximum frequency component in the wavelet. In towed streamer surveys, that maximum frequency value is largely dictated by ghost filters associated with the depths of the sources and receivers. Shallow tow depths allow high frequencies to be passed.
The unlicensed northern part of the Orange Basin covers almost 21000 km2 and falls between the median line dividing Namibian and South African territory, and the 30 deg south latitude line.
Sediments range in age from the late Jurassic to Hauterivian synrift graben fill, to drift sediments dating from the early Cretaceous to the present. The area is covered by over 8000 km of 2D seismic data, ranging in vintage from 1975 to 1999. Only 3 wells have been drilled in the area to date. One targeted possible lacustrine sandstones in the synrift, but intersected coarse, proximal sediments. A second, towards the south, targeted the western part of a structural play on either side of an extensional fault, but encountered only poor gas shows in mostly water-wet sandstones. The third intersected gas charged fluvial sandstones in the early to mid-Cretaceous.
Numerous play types are present in the area. Rift plays are represented by possible lacustrine sandstones, trapping oil from organic rich claystones as encountered in the A-J graben to the south. The other major play is represented by synrift sediments pinching out against basement to the west of the hinge line. Drift plays include the early Cretaceous Aeolian sandstone play, the Albian incised valley play, structural plays in younger shelf sediments and deeper water plays comprising roll-over anticlines in growth fault zones and turbiditic fans.
The Orange Basin, off the southwestern coast of Africa, is classified as a passive volcanic margin basin1,2. Clastic sediment, sourced from the continent to the east, has been deposited in the basin by the Orange and Oliphants River systems and their ancestral equivalents. The sediment pile reaches over 7km thick in places3,4. This poster discusses the northern most part of the Orange Basin within South African territory. The area shown in Figure 1 covers almost 21 000 km2 and falls between the median line dividing Namibia and South African, and the 30 deg south latitude line. Sediments range in age from synrift graben fill, tentatively dated from late Jurassic to Hauterivian, to drift sediments dating from early Cretaceous to the present5. The area is covered by over 8 000 km of 2D seismic data, ranging in vintage from 1975 to 1999, as shown in Figure 1. Water depths are less than 200m over most of the area, with only the far western section lying in water up to 600 m deep.
Exploration to date
Only 3 wells have been drilled in the area. Well positions are shown in the figure above.
1) Borehole A-O1 in the north, targeted prognosed lacustrine sandstones in the synrift graben sediments. Three distinct seismic packages occur within the graben. The well was drilled to a depth of 4 605 mbKB and intersected proximal fluvial sandstones, volcaniclastics, shales and silts of mostly fluvial origin, and dolerites. Thin, unoxidised lacustrine shales occur as interbeds only, indicating that the well intersected a relatively proximal facies in the graben.
Africa is facing many challenges in its social and economic development. Companies in all industries are increasingly evaluated in terms of how they contribute to this development. The concept of corporate governance has evolved beyond a company's responsibilities to its shareholders to include its responsibilities to a broader range of stakeholders. Issues of corporate governance and responsibility are of growing importance to oil companies operating in Africa. Government expectations of the industry's contribution to domestic economic development are expanding. Stakeholders are holding the industry to increasing standards of social responsibility.
These issues are exemplified in Angola, where the government asked ChevronTexaco, as the country's largest investor, to contribute to the reconstruction of the country after 27 years of civil war. The company recognized the importance of taking an active role in assisting Angola in such a critical juncture in the country's history. So in 2002, ChevronTexaco formed its Angola Partnership Initiative to work with international donors and non-government organizations to facilitate reconstruction and development throughout Angola. This initiative heralded a shift in the company's thinking about where and how it could contribute to the social and economic development of a country beyond its immediate area of operations.
The Angola Partnership Initiative helped ChevronTexaco to broaden its understanding of what it can achieve as an agent of positive social and economic change. The company has now linked this initiative with its existing programs to assist local communities and promote local content in its supply chain management. This maximizes the synergies between the efforts of the company and its partners and provides an overall framework in which it can plan, implement and report on its efforts to demonstrate corporate governance and responsibility in Angola.
It has been a long held belief by many people that corporations are only responsible to their shareholders as long as they operate within the limits of the law. All other sense of corporate responsibility has been seen as a reputation issue in which public perceptions could be shaped through carefully crafted communication strategies. Over the last several years however, society's expectations of how corporations should be governed and what role they should play in contributing to social welfare have increased to a stronger set of expectations as a result of high-profile corporate scandals, tightening regulatory environments and everincreasing advocacy efforts on the part of non-government organizations (NGOs).
These increased expectations vary amongst industries and across regions. The high profile of the petroleum industry and the widespread dependency on its products focuses considerable attention on petroleum companies and the impacts they have on society in general. In Africa, this attention tends to concentrate on the role each company plays in terms of the many development challenges faced within the continent. The concept that companies can successfully operate in the midst of widespread poverty and poor standards of public health and education promotes the expectation that companies should apply a portion of their profits to assist developing countries in Africa to meet these challenges.
This paper will present the findings of the natural gas industry on the current status and trends in world natural gas supply and demand, highlighting the main constraints and challenges it faces to match the balance in terms of technology, investments, transport options and regulation.
Ladies and Gentlemen, good morning,
I appreciate the opportunity and the honor I am given to speak during this 18th World Petroleum Congress.The topic I have been asked to address is: 'Natural gas supply and demand: getting the balance right'. An interesting theme indeed when you bear in mind the current context of rocketing natural gas prices in the US and in Europe, forward curves especially.
The stagnation of European and US domestic natural gas production combined with a steady anticipated demand growth leads to a spectacular number of gas import projects where competition will probably increase between pipe gas and LNG. Backed by decreasing technical costs and economies of scale on one side and by emerging inter-regional trade on the other, LNG supply will dramatically expand. New comers such as China or India and world economic growth driving the demand up, transportation possible congestion in continental Europe, Middle-East becoming the key to West and East of Suez markets balance, timely development of necessary infrastructures: these are some elements that will certainly add to modifying the current state of natural gas markets.
Ex-post, the balance is always right - that is the reality of things, even if hiding imbalances in some instances. Ex-ante, however, the question remains as to what sort of factors impact the most the flows leading to the right equilibrium.
Three main elements, I believe, pave the way to the right balance once demand needs and supply sources have been assessed:
- State of the gas chains infrastructure - including production facilities, gas-lines and LNG chain;
- Vision and perception of the different market players - market short-sightedness as it is called leading to imbalance situations;
- Long term price, which should be at a minimum level to allow projects to be launched on time, thus smoothing out supply troughs and spikes.
I will therefore start this presentation with the commonly accepted view that natural gas is plenty in a more and more open world. Thinking the balance right, as a pre-requisite, will then lead me to share our supply / demand foreseeable evolution vision with you. On the basis of what appears to me as two salient examples of potential imbalance, namely transportation in Europe and LNG fluidity between East and West of Suez markets, I will then elaborate on conditions required to keep potential bubbles or shortages out of the picture.
The equilibrium reference framework
Min-zhi, Zhang (Daqing Oil Field E&P Research Institute) | Cheng, Wang (Daqing Oil Field E&P Research Institute) | Hong-qi, Jiang (Daqing Oil Field E&P Research Institute) | Dan, Yao (Daqing Oil Field E&P Research Institute) | Xian-da, Sun (Daqing Oil Field E&P Research Institute) | Qing-yun, Mao (Daqing Oil Field E&P Research Institute) | Guang-zheng, Shen (Daqing Oil Field E&P Research Institute)
The large natural gas deposit in deep volcano and non-typical sedimentaty formations of upper Jurassic and Cretaceous series in Songlao basin in China discovered recently. We discovered there exists an affinitive correlation between the reservoir pore space of natural gas and the mineral alteration-metasomasis of volcano and non-typical sedimentaty rocks in the geology progress, the sodic alkaline metasomatism on behalf of the main line of systemic mineral alteration-metasomasis not only reform original pore, and the new secondary pore can provide beneficial storage space. The great significance is that the kind of alkali metasomatism is a result which affected by the rising mantle hydrocarbon alkali fluid, i.e. rising mantle ichor or HACONS fluid. The latter is a dynamical source of the area's natural gas generation, genesis of the gas has the characteristic of inorganic/organic hybrid functions.The author discusses this geology phenomenon in detail.
Songliao basin is located in the north part of China (the north latitude is 42°25΄~49°23΄, the east longitude is119°40΄~128°24΄), the main axis expands and distributes in NNE, and the whole area is 2.6Ч104 m2.In regional structure the main body of Songliao basin is located on the overgrowing fold belt at the southern edge of the western Siberia plate during the early and later Hercynian epochs to the Indo Chinese epoch. The southern part is located on the fold belt at the south edge of Huabei plate during the Caledonian epoch to Hercynian epoch. It has the property of final collision and forming a butt joint zone between the western Siberia plate and the Huabei plate. Mutil-tensile fractures of Moho surface which indicated by the seismic profile trace analysis show that the basin has the characteristics of the extended and faulted basin, it was formed during early Jurassic and late Cretaceous(Huoshiling epoch to Quantou epoch, 125~135Ma)(Zhang Xiaodong,2004), and it is the intracontinental rift basin.
Particularity of the basin is that: mantle in the extending area uplifts, asthenosphere also uplifts, extending Earth crust becomes thinner, Moho surface also becomes thinner, and average depth of Moho surface is 31.36 km. The lower Earth crust at the disconnected parts of Moho surface mostly is reticulate structure while the upper one is an imbricate arrangement zone, being the developed area of heat flow diapris. The overlap place of Moho surface should be the relic part of earth crust extruded early. Mantle uplift results in upwarping of the metamorphic core complexes with the metamorphic kernels on basement. In three confirmed metamorphic core complexes (the eastern uplift zone, the central palaeohigh one, and the western slope one) the central palaeohigh one upwarps most, the metamorphic core complexes in the middle earth crust upwarps to depth of 3 km along this zone. In the central palaeohigh area the uplift kernel consists of middle -deep- metamorphic gneiss and micacite from coring between 3100~3900 m, being amphibolite facies, in which there is invasion of thelate medium-acidic rock mass from deep source, and at the top there is a tenacious shearzone characterized by felsic mylonite.
Deep marine basin floor channel and basin floor fan (bff) complexes are well developed in the third order Barremian (9A) to Aptian (13B) sequences in the Bredasdorp Basin, offshore the Southern Cape of South Africa. The bff com-plexes contain stratigraphically and structurally trapped hydrocarbons, within moderate to good reservoir quality turbidite channel sandstones. The Sable oil and gas fields are reservoired within the upper part of this turbidite system.
The sequences fall within a stage of early drift history with a progressively enlarging basin that flooded and integrated the initial post-rift embayments with connections to the proto- Indian Ocean. Deposition of well-defined systems tracts together with associated type1 erosional unconformities developed. The third-order (onlap-fill) sequences reflect both thermal subsidence along the ba-sin axis and episodes of re-activated faulting. Generalized facies distributions, determined from log patterns, core data and maximum grain size data have assisted in generating geological models for the region. Poorer quality channel overbank and sheet sand (distal fan) deposits are not resolvable from seismic and geological models must take this into account so that allowances can be made for these 'invisible' volumes.
Ideally, bff systems should be radial in shape but because deposition occurred in the relatively confined Bredasdorp Basin their shape is controlled by the ba-sin topography and as such are predominantly elongated.
The provenance for these sandstones consisted of Table Mountain quartzites and Cape granites sourced from the mainland and the Agulhas Arch. The ba-sin maintained it's strong northwest - southeast elongation, inherited from the synrift sub-basins and was open to relatively free marine circulation to the southeast with the Southern Outeniqua Basin and the Indian Ocean. Sedimen-tation into the Bredasdorp Basin thus occurred predominantly down the axis of the basin with main input direction from the west.
The Bredasdorp Basin, located on the southern continental margin off the coast of South Africa is mostly filled by marine Aptian to Maastrichtian deposits, which were deposited on pre-existing Late Jurassic to Early Cretaceous fluvial and shallow marine synrift deposits.
Drilling for hydrocarbons in the Bredasdorp Basin commenced in 1973, leading to the discovery in 1980 of the F-A gas field in the Berriasian to Valanginian shallow marine synrift sandstones along the northern flank of the basin (Figure 1). Further discoveries led to the gas-to-liquids (GTL) project at Mossel Bay commissioned in 1992, which produces syn-fuels from gas and condensate production from the F-A and E-M fields. Most recently the South Coast Gas Project (SCG) has been ratified to make available several central basin Barremian (9A) to Aptian (13B) gas and condensate discoveries in order to sustain and extend production of syn-fuels at the GTL plant. The generally thin pre-Aptian central basin gas charged reservoirs, confined to narrow channels, have proven to be a challenge to model, both geologically and commercially and their contribution to the basin's success will soon be realised.