Mature Province Research Articles

The Impact on Oil and Gas Activity in a Mature Province of Limiting Global Warming to 1.5 ºC

The Impact on Oil and Gas Activity in a Mature Province of Limiting Global Warming to 1.5 ºC

The History, Features, and Prospects of the Chinese Style Teaching Research System

The Chinese teaching research system was created, improved, and developed in response to the ongoing process of addressing issues and needs in teaching in China's primary and secondary education system. The teaching research system is an important and integral part of the Chinese approach to managing teaching. Its 70-year course of development can be divided into six periods: initial creation period (1949–1956)–starting from nothing; development period (1957–1965)–gradual improvement; setback period (1966-1976)–at a low ebb; restoration period (1977–1984)–regrouping; standardization period (1985–1999)–great prosperity; improvement period (2000–)–transformation and innovation. The teaching research system developed alongside the changes in China's basic education and the ongoing development of primary and secondary education curricula, teaching materials, and teaching, becoming the core supporting mechanism ensuring reforms to curricula, teaching materials, and teaching, and improving the quality of teaching education, and the professionalization of teachers. The teaching research system has formed a set of relatively mature, improved, and effective multi-level province, city (district, county), and school, teaching research systems, and has formed teaching research groups that have accumulated rich teaching experience, substantial academic achievement, and strong management and leadership capabilities. The teaching research work emerges out of the practical needs of teachers, and its objective is to resolve teachers’ day to day problems encountered in the classroom and in the implementation of the curriculum. The Chinese teaching research system faces new challenges as curriculum reform deepens, the education level and level of professional development of primary and secondary teachers improves, and multimedia technology advances. These changes require a deepening of the work of the teaching research system, demanding greater professionalization, standardization, and scientific backing.

Seismic reservoir characterization of Bentheimer sandstone, Emlichheim oil field, Lower Saxony, Germany

Even in mature oil and gas provinces, unexpected subsurface complexity may challenge budgeted seismic reservoir characterization workflows to become adapted to a higher degree of customization during data preconditioning. In the process of providing a trend cube of sandstone porosity and automatic fault extraction to populate the property distribution and structural framework of a static model over the mature Emlichheim oil field, northwest Germany, many unforeseen data quality issues are encountered that necessitate rigorous well log and seismic data conditioning prior to analysis and interpretation. Specifically, insufficient noise suppression, ambiguous wireline log responses, missing curve log data, noncompliant amplitude-versus-angle gathers, and inadequate compensation of velocity anisotropy need to be addressed. These topics pose serious challenges to automatic fault extraction, seismic attribute analysis, machine learning, artificial neural network technology, the selected inversion method, Bayesian lithology prediction, and fuzzy math to transform elastic impedances into reservoir porosity. Application of multiple inversion methods generates the individual components of new earth models (sand geobodies, alternative elasticity-to-porosity transforms, etc.) that are used for advanced porosity modeling. This new information allows to update the existing static models of a mature oil field.

Application of Zipf’s law to estimate undiscovered Gold endowment in the Quadrilátero Ferrífero Province, Brazil

Ore-forming processes act as self-organizing critical systems. These systems exist in an unbalanced nature, such that energy-release can occur as a scale-invariant power-law behavior when a certain threshold is exceeded. In ore-forming systems, the energy released from multiple transient pulses of over-pressured fluid appears to follow a power-law, since the distribution of mineral deposits in mature provinces have been shown to obey Zipf's law. Zipf's law represents a statistical relationship between the size and rank of a discrete phenomenon. In this work, we present the application of Zipf's law in estimating the undiscovered gold endowment of the Quadrilatero Ferrifero Province in Brazil. In addition, we conducted several statistical tests to validate the application of Zipf's law and discussed its limitations regarding smaller deposits. The Kolmogorov-Smirnov's minimum distance was presented as an alternative to defining the lower boundary of the Zipf's law's domain, rather than using an economic cut-off. Our results estimate the maturity of the Quadrilatero Ferrifero Province to be 65%, with potential for the discovery of at least 749 t of gold, comprising 28 deposits larger than 8 t (totaling 519 t), and 2 deposits larger than 40 t (totaling 122 t).

Probabilistic inversion of airborne electromagnetic data for basement conductors

Probabilistic inversion of airborne electromagnetic data is often approximated by a layered earth using a computationally efficient 1D kernel. If the underlying framework accounts for prior beliefs on spatial correlation, the inversion will be able to recover spatially coherent interfaces and associated uncertainties. Greenfield exploration using airborne electromagnetic data, however, often seeks to identify discrete economical targets. In mature exploration provinces, such bodies are frequently obscured by thick, conductive regolith, and the response of such economic basement conductors presents a challenge to any layered earth inversion. A well-known computationally efficient way to approximate the response of a basement conductor is to use a thin plate. Here we have extended a Bayesian parametric bootstrap approach, so that the basement of a spatially varying layered earth can contain a thin plate. The resulting Bayesian framework allowed for the inversion of basement conductors and associated uncertainties, but more importantly, the use of model selection concepts to determine if the data supports a basement conductor model or not. Recovered maps of basement conductor probabilities show the expected patterns in uncertainty; for example, a decrease in target probability with increasing depth. Such maps of target probabilities generated using the thin plate approximation are a potentially valuable source of information for the planning of exploration activity, such as the targeting of drillholes to confirm the existence of a discrete conductor in a greenfield exploration scenario. We have used a field data set from northwest Queensland, Australia, to illustrate how the approach allowed inversion for a basement conductor and related uncertainties in a spatially variable layered earth, using the information from multiple survey lines and prior beliefs of geology.

What are the Implications for the Governments of Petroleum Rich Countries on Allocation of Offshore Decommissioning Costs? What Best Practices Can the Emerging Petroleum Rich Countries Adopt from the Mature Provinces to Control Costs?

What are the Implications for the Governments of Petroleum Rich Countries on Allocation of Offshore Decommissioning Costs? What Best Practices Can the Emerging Petroleum Rich Countries Adopt from the Mature Provinces to Control Costs?

7th Cambridge Diagenesis Conference 2011: an introduction

The Cambridge Diagenesis Conferences (1981–1998) were set up to act as a conduit for the interchange of clay mineral expertise between universities and research institutes on one hand, and the hydrocarbon industry on the other. At the time, oil companies were dealing with the development of the North Sea Oil Province which was turning out to be a natural laboratory for the fundamental study of authigenic clay minerals and their relationship to lithofacies, burial, overpressure, reservoir quality and hydrocarbon emplacement. This symbiosis between industry and academia flourished for nearly two decades. Each conference was followed by a special issue of Clay Minerals dealing with topics relevant to, or discussed at the particular meeting. By the late 1990s the North Sea had become a mature province and the major oil companies were looking to other parts of the world to replenish their reserves.

Decommissioning liability for offshore oil and gas installations: planning for a happy ending

This extended abstract outlines the draconian statutory decommissioning liability regime for offshore installations in the UK Continental Shelf (UKCS), drawing comparisons with the other jurisdictions. The impact of the regime on regulatory and contractual requirements for decommissioning security that creates barriers for new entrants into the UKCS is highlighted. One such barrier is the calculation of decommissioning security by reference to the pre-tax cost of decommissioning (i.e. without considering tax relief on decommissioning expenditure at the time it is incurred). This extended abstract comments on recent novel proposals from the government to limit the amount of capital tied up in decommissioning security by adopting measures that will facilitate calculation of decommissioning security on a post-tax basis. The UKCS is a mature province and the government is seeking to balance its desire to maximise economic recovery from the UKCS with its policy objective of ensuring that taxpayers are not responsible for decommissioning costs. The proposals envisage that the government will enter decommissioning relief deeds with owners of offshore installations. This will provide certainty about the rate of relief they will achieve in relation to their own share of decommissioning expenditure; it also ensures relief is available where they incur such costs due to the default of other parties. In essence, the government is contemplating entering a form of stabilisation agreement that will provide redress in the event that future changes in law reduce the tax relief available for decommissioning expenditure. The proposals show a bold attempt to promote investment by addressing political risk in a highly developed jurisdiction.

Interest Grows In Asia Pacific Offshore Projects

The vast horizon of the Asia Pacific offshore region is a diverse and dynamic arena for oil and gas development, one of contrasts, complexities, and challenges. While there is no overriding theme such as the tremendous reserves of the Middle East, or bold new story as in the Brazilian pre-salt or North American tight shale, Asia Pacific offshore is one of the world’s most active hydrocarbon provinces. More than 55% of the global oil and gas heavy lift vessel fleet* operated in the region at some point during 2010, according to IHS’ ODS-Petrodata unit. Asia Pacific offshore has the resources, commitment of its resource owners, and economic drivers to remain a major factor in global petroleum development for decades. It is tempting to view the Asia Pacific offshore as one large emerging market. Yet it is more than that. Countries such as China and Vietnam, which once were closed to most outside capital investment, are clearly open for business. Future oil and gas growth opportunities—though not necessarily the same for both countries—appear to have few limits. But then there is Indonesia, which certainly ranks as a mature province. A longtime oil exporter, it withdrew from OPEC in 2008 after becoming a net importer. Yet Indonesia is anything but a fading star. Projects such as Gendalo-Gehem and Abadi have technologically sophisticated development plans to meet major technical and commercial challenges, and the East Natuna project targets gigantic natural gas reserves—although accompanied by massive levels of CO2. Success in these and other projects could help Indonesia move closer to self-sufficiency in petroleum supply. Challenges of many types face offshore projects throughout the Asia Pacific region. Industry interest in the area is “quite strong,” according to Dylan Mair, director of Far East information and insight at IHS. “Historically, the big companies moved out of Asia and into exciting places like Brazil,” he said. “What we will probably see in the near future is these IOCs (international oil companies) moving back in. You’ve seen some movement already with the independents. The supermajors have also gotten involved in unconventional hydrocarbon plays where there is a need for external expertise to assist the efforts of the NOCs (national oil companies).” Not all of the challenging projects are large. The critical need for petroleum to fuel regional growth adds an incentive to unlocking ways of commercializing smaller, often remote accumulations of gas. Angus Rodger, Southeast Asia upstream analyst at Wood Mackenzie, described the region’s project environment thusly: “The low-hanging fruit is gone, and newer developments are located in more remote, frontier areas, deeper waters or require tackling more challenging geology. Usually, all of these challenges come together.”

Swift Acceptance of Innovative Technologies Will Reap Rewards

Guest editorial It is a hard fact that it is tougher to bring new technology to market in the oil and gas industry than any other, excluding only space exploration. It can take on average up to 16 years from concept to full field deployment, which is almost twice as long as most other sectors. Greater collaboration is a key to breaking down some of the barriers that will help address the many challenges our industry faces. The common drivers of how to find new resources, maximize recovery of existing reserves, operate fields safely, and ultimately, do it cost effectively will never change, but the mechanisms to propel us forward as an industry will need to. This will require a much bigger investment in research and development to enable ground-breaking technologies. New technology can make mature fields more cost effective and allow small field developments to become economically viable. The importance of innovation cannot be stressed enough in helping organizations deal more efficiently with a volatile economy. That is why the rate of implementation of proven new technologies needs to be increased. Full-scale tests must, of course, be completed before a technology can gain market acceptance. Commercializing technology in the oil and gas market place can be costly and time intensive. With many technologies destined for hostile and sometimes remote environments, such as deep waters or high-pressure/high-temperature wells, new developments need to undergo extensive testing and field trials to prove their capability. Over the past few decades there has been a definite shift in the source of new technology. In the 1980s major oil and gas companies began to decrease their research and development (R&D) spending driven in the main by a decision to “buy versus build.” As a result, service companies stepped in to partially fill the gap by increasing their R&D spend. Nevertheless, it was only a few years ago that the oil and gas industry was at the top of the league for increased R&D spend, but the recession in the global economy put a dramatic dampener on that position. The UK Continental Shelf is recognized globally for its excellence in mature province value realization through the accelerated development and use of new technology and innovative practice. There is a strong need to maintain that position through knowledge and skills retention, and stimulation of the innovative community to maintain a creative environment. Also, there exists in the UK an opportunity to transfer some of these skills to other energy industries that should be realized to ensure that the industry capture the ambition of becoming an energy hub now and beyond oil and gas.

Reserve Growth in Oil Pools of Alberta: Model and Forecast

Abstract Reserve growth is recognized as a major component of additions to reserves in most oil provinces around the world, particularly in mature provinces. It takes place as a result of the discovery of new pools/reservoirs and extensions of known pools within existing fields, improved knowledge of reservoirs over time leading to a change in estimates of original oil-in-place, and improvement in recovery factor through the application of new technology, such as enhanced oil recovery methods, horizontal/multilateral drilling, and 4D seismic. A reserve growth study was conducted on oil pools in Alberta, Canada, with the following objectives: 1) evaluate historical oil reserve data in order to assess the potential for future reserve growth; 2) develop reserve growth models/functions to help forecast hydrocarbon volumes; 3) study reserve growth sensitivity to various parameters (for example, pool size, porosity, and oil gravity); and 4) compare reserve growth in oil pools and fields in Alberta with those from other large petroleum provinces around the world. The reported known recoverable oil exclusive of Athabasca oil sands in Alberta increased from 4.5 billion barrels of oil (BBO) in 1960 to 17 BBO in 2005. Some of the pools that were included in the existing database were excluded from the present study for lack of adequate data. Therefore, the known recoverable oil increased from 4.2 to 13.9 BBO over the period from 1960 through 2005, with new discoveries contributing 3.7 BBO and reserve growth adding 6 BBO. This reserve growth took place mostly in pools with more than 125,000 barrels of known recoverable oil. Pools with light oil accounted for most of the total known oil volume, therefore reflecting the overall pool growth. Smaller pools, in contrast, shrank in their total recoverable volumes over the years. Pools with heavy oil (gravity less than 20° API) make up only a small share (3.8 percent) of the total recoverable oil; they showed a 23-fold growth compared to about 3.5-fold growth in pools with medium oil and 2.2-fold growth in pools with light oil over a fifty-year period. The analysis indicates that pools with high porosity reservoirs (greater than 30 percent porosity) grew more than pools with lower porosity reservoirs which could possibly be attributed to permeability differences between the two types. Reserve growth models for Alberta, Canada, show the growth at field level is almost twice as much as at pool level, possibly because the analysis has evaluated fields with two or more pools with different discovery years. Based on the models, the growth in oil volumes in Alberta pools over the next five-year period (2006–2010) is expected to be about 454 million barrels of oil. Over a twenty-five year period, the cumulative reserve growth in Alberta oil pools has been only 2-fold compared to a 4- to- 5-fold increase in other petroleum producing areas such as Saskatchewan, Volga-Ural, U.S. onshore fields, and U.S. Gulf of Mexico. However, the growth at the field level compares well with that of U.S. onshore fields. In other petroleum provinces, the reserves are reported at field levels rather than at pool levels, the latter basically being the equivalent of individual reservoirs.

Kicks in Offshore UK Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119942, ’Kicks in Offshore UK Wells - Where Are They Happening and Why?,’ by J.D. Dobson, SPE, Health and Safety Executive, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. The first well on the UK continental shelf (UKCS) was spudded 44 years ago, and the area long has been considered a mature province. Despite this, kicks are still a frequent occurrence. Kicks occur in high-pressure/high-temperature (HP/HT) condensate exploration wells and in production wells in depleted subnormally pressured oil reservoirs. They occur during drilling operations and during workover operations. Analysis of data on well incidents has identified where, geographically, kicks occur most frequently. Introduction The Health and Safety Executive (HSE) is the regulator for oil and gas drilling on land in UK and on the UKCS. UK health and safety regulations specify which well incidents must be reported by well operators. These reportable incidents are kicks, blowouts both underground and at surface, the unanticipated presence of hydrogen sulfide (H2S), unplanned intersections and near misses, and serious failure of a safety-critical element including the primary pressure-containment envelope of the well. The purpose of the regulation is not merely to inform HSE of the incident, but also to allow the regulator to spot trends in the industry that may not be noticeable to individual well operators and drilling contractors. The full-length paper focuses on kicks and their consequences, rather than on other incidents, but with the intention of sharing the overview more widely. Exploration on the UKCS began in the mid-1960s, with the first major discovery in December 1965. In a mature oil and gas province such as the North Sea, it might be assumed that the frequency of kicks during drilling or workover operations would be decreasing. This study indicates otherwise. Approach The study is based on a review of all kicks and blowouts reported for the area in the 10 years since 1999. The intent in reviewing the data is to consider which areas of the UKCS, and which type of operation, carry the greatest risk of kicks. A second, more detailed, review was carried out for incidents in the 3-year period 2006 to 2008, which examined each reported incident in more detail, reviewing the circumstances under which the kick occurred and, where possible, identifying the underlying cause. Areas of the UKCS Over the last 44 years, wells have been drilled in each of a variety of discrete geographical and geological areas off the coast of the UK (Fig. 1). Although wells have been drilled in all the basins shown, the vast majority of the drilling activity on the UKCS has been limited to six discrete geological areas—southern North Sea, central North Sea, Moray Firth, northern North Sea, West of Shetland, and Irish Sea. It is in these areas that the reported incidents considered in this study have occurred.

Reality Checks for Well Time and Cost Forecasts

Management Much has been written to explain the origins of the credit crisis that has engulfed the international financial system. At the heart of each explanation is the failure to quantify commercial risks. The companies at the centre of the crisis were often long-established, considered profitable, and were endowed with great resources to make mathematical models of their activities. Despite this, it is safe to conclude that many of their models were wrong. Risk is a feature of financial transactions and drilling wells that no amount of engineering will completely remove. From the crisis in banking it is obvious that the skills required to build a credible model of activities inclusive of risk are in short supply. It would be convenient to assume that because the energy industry employs lots of numerate people it is good at quantifying uncertainty; unfortunately, many of the time and cost models used for well planning can be easily disproven. The reasons for this go beyond the tools available to the human bias toward optimism. There is a tendency to treat each well project as unique and disregard the fact that past performances will not only inform us about averages but also about uncertainty. A Suitable Benchmark The budget for new well projects will often first be defined with little detailed engineering information. There are perfectly valid reasons for this; out of a basket of many prospects an operator is unlikely to develop every one. Early budgetary estimates play a part in the selection of the best prospects to drill. Irrespective of the method used to define a budget figure, and irrespective of the maturity of the estimate, some guidance on confidence should accompany the result. In common with any other forecasting discipline, well cost estimation never is and never will be an exact science. The very best that can be done is to describe the probability of a particular scenario and to use the results from similar previous wells to back this up. If a model of well project duration cannot be substantiated with empirical evidence it must be treated with extreme caution. The inputs to the model matter much less in this respect than the output; it is surprisingly easy to make a poor probabilistic model from good information. In many mature drilling provinces such as the UK, public data can be used to provide the justification necessary for models of project duration which in turn can be used to model cost.

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.

Techbits: Technology Strategies Highlighted at Norway Conference

Techbits From 15 to 16 October, more than 120 oil and gas professionals converged in Bergen, Norway for the fourth SPE Norwegian Petroleum Technology Conference (PTC). The conference, which was held in conjunction with Norway's Offshore Technology Days Exhibition, allowed managers, engineers, and business development planners to discuss how Norway plans to maintain its status as a global energy technology leader and incorporate innovations from companies big and small, far and wide. "The conference was really focused around StatoilHydro's dominant role in the Norwegian oil and gas industry and how they plan to ensure continual development of new technologies and put them to use," said Jan Roar Drechsler, Chairperson of the PTC Program Committee and the SPE Stavanger section, as well as a Principal Engineer and Technical Representative for Completions with StatoilHydro. "In the past [prior to the merger of Statoil and Norsk Hydro], there was a sort of competition between Statoil and Hydro to be first in the development of a new technology. There is concern that now some development programs, either within the company or with different partners, might be put aside or altered. People wanted to know how these would go on in the future." The first two presenters elaborated on this concern by outlining the role of technology in developing the reserves on the Norwegian Continental Shelf (NCS) and the dangers of scaling back future technology development programs. Roy Ruså, Vice President of Technology for Petoro, discussed upcoming technology challenges for operators and service providers in his talk "Technology Critical—Do We Act Accordingly?" Ruså pointed out that the mature NCS province still has many significant business opportunities, but they are linked to even greater technical challenges, such as realizing remaining reserves from smaller prospects, reducing nonrecoverable reserves, and finding and developing new recoverable resources. He acknowledged StatoilHydro as the major driver of technology development on the NCS, but added that the company must continue making significant investments in R&D and increasingly diversify its portfolio of production solutions by pulling in more technologies from other industries and geographic regions.

Can the North Sea still save Europe?

AbstractIn the 1980s and 1990s the North Sea emerged as a key non‐Organization of the Petroleum Exporting Countries oil‐producing province. Yet today overall production is declining, in both the British and Norwegian sectors, and the big oil companies and investors are losing interest in what they now see as a mature province. But apparent maturity is not a bar to new prospects and new possibilities. This paper analyses not merely the still significant potential of the North Sea, but also the wider and increasingly attractive prospects offered by the opening up of the High North, the Barents Sea and part of the Arctic region—all areas of rapidly growing interest that are on Europe's doorstep. Success will depend heavily on key questions such as the world oil price trend, technological advance and the structure of fiscal regimes for oil and gas extraction. But the opportunities are there and they could be to Europe's great advantage.

Step Change in Performance: Upgraded Bit Technology Improves Drilling Economics

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 103074, "Step Change in Performance: Upgraded Bit Technology Significantly Improves Drilling Economics in GOM Motor Applications," by B. Grimes, SPE, and B. Kirkpatrick, Hughes Christensen, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. Operators in the Gulf of Mexico (GOM) are constantly looking for ways to reduce the costs of drilling development wells. A new steel-tooth (ST) roller-cone bit with an advanced metal-seal bearing has achieved this goal and is having a significant effect on drilling economics. Improvements in bearing life, seal reliability, and cutting-structure durability have resulted in more time on bottom, giving the operator the confidence to use the new roller-cone bits in long directional hole sections. Introduction With large regions of the GOM rapidly becoming mature provinces, operators are looking for ways to reduce the costs of drilling development wells. Most of the wells drilled are directional, and heavy water-based drilling fluids often are required in the intermediate hole sections. Relatively high bottomhole temperatures combine with high bottomhole pressures and balling shales to present a challenging drilling environment. Operators strive to increase rate of penetration (ROP), maximize hours on bottom for each bit, reduce risk, and complete the section with fewer bits to reduce the number of trips. Improved roller-cone bits with an innovative single-energizer metal-seal (SEMS) bearing were introduced in 1998 (Fig. 1). A step change in bit life was realized, yet it took a year or two for operators in the GOM to gain sufficient confidence in the new ST bits to run them harder and leave them in the hole longer. By 2000, operators routinely were achieving runs as much as twice as long as was typical with the predecessor elastomer-sealed ST bits, particularly at higher rotary speeds (e.g., 175 to 275 rev/min). In 2000, enhanced ST cutting structures were introduced to complement the SEMS bearing (Fig. 2). The new ST cutting structure provided longer tooth life by improved tooth wear resistance and reduced tooth breakage. GOM Drilling Environment The GOM drilling environment is one of the most diverse in the world. With exploration and development programs taking wells to ever greater depths, the demands placed on ST roller-cone bits and their sealed-bearing systems become increasingly severe. The increased service life and reliability of rotary-steerable systems and top-of-the-line motor assemblies allow them to successfully drill long, complex well paths, which increases the directional challenges for roller-cone bits. Both concentric and eccentric hole-opening technologies place unique loading conditions on roller-cone bits when they are used as pilot bits.

Comments: The Rise of INOCs

The value of transactions in the oil and gas industry last year more than doubled from 2004, the most activity since the corporate megamergers of 1998–99. And some of the most active players were the formerly stodgy national oil companies (NOCs). Gazprom's U.S. $13 billion takeover of Sibneft and China Natl. Petroleum Corp.'s $3.9 billion buyout of PetroKazakhstan were two of the largest deals that took place last year, according to consultancy John S. Herold, and China Natl. Offshore Oil Corp.'s unsuccessful $18.5 billion bid for Unocal also made headlines. There was a threefold increase in NOC international merger and acquisition activity last year, according to Herold. Times have changed for state-owned enterprises. Most were founded to ensure national energy independence for their countries and have been major employers as well as major funders of government coffers. Now, it is just as likely to see NOCs competing head to head against the majors for prized acreage or for other companies. Some analysts have begun calling these more aggressive state-owned firms international national oil companies (INOCs). The industry is more internationalized, and state companies have become more adept at using technology. States are also concerned about security of supply. The shift of technology ownership from operators to service companies over the past decade and firmer oil prices—which has lessened the need for external financing of some big projects—also have played a role, according to the Accenture consulting firm. Accenture interviewed the senior leaders of 10 NOCs about their objectives. All were interested in growth opportunities, but each had their own distinct priorities, often reflective of their government's policies. All indicated a desire to investigate deals beyond the typical production-sharing or joint-venture contract that, up to now, has been a mainstay of NOC business partnerships. The consequences for the private international oil companies (IOCs)—and the future global energy market—are huge. This new competition is driving up bid prices and pinching returns for private companies' international projects. And the majors are increasingly looking for oil outside mature provinces in places where state enterprises dominate the landscape. Relationships between NOCs are becoming more strategic and longer term as dealings between IOCs and NOCs are becoming more transactional, the Accenture report concluded. NOCs working together make a formidable bidder for projects. China Natl. Petroleum Corp., Lukoil, Uzbekneftegaz, Petronas, and Korea Natl. Oil Corp., for instance, recently joined forces to develop gas fields in Uzbekistan. Often, an NOC and its host government would prefer to work with another NOC, particularly if the countries have similar geopolitical interests. In a recent speech in Singapore, BP Chief Executive Officer (CEO) John Browne pointed out that eight of the 10 largest oil companies in the world are state-owned. "Those state companies control huge resources, far more in total than all the private-sector companies put together," he said. Since 2003, more than half of all reserves sales have been to state companies, he said. To participate in this new competitive climate, private companies will have to bring value to the table, Browne said—namely, "the ability to access and apply knowledge very rapidly on a global scale." That means technology and the skill to apply it. His contemporary, Jeroen van der Veer, Chief Executive of Royal Dutch Shell, agrees. "National and international companies have complementary strengths, and our relationship will be vital for the future," he said at a recent Houston energy gathering. Several NOC leaders in the Accenture study mentioned that they are envious of IOCs' downstream assets and technology. While NOCs may appear to have an advantage over their private counterparts, they also have the burden of satisfying their government's financial needs. In the future, IOCs and NOCs may pursue mergers with each other, particularly if the size and scope of energy projects become burdensome. IOCs and NOCs certainly should consider pursuing joint ventures outside the host country and looking at ways of developing partnerships across the value chain, Marathon CEO Clarence Cazalot said recently. The bottom line is that IOCs need the resources the NOCs control, and NOCs need the technological expertise of private companies, he said.

Offshore Europe Conference Assesses Hydrocarbon Demand Challenges

How to manage mature production provinces, both globally and in the North Sea, while meeting rising hydrocarbon demand framed discussion at the 2005 Offshore Europe Oil and Gas Exhibition and Conference in Aberdeen. Attendance at the biennial event, held 6–9 September, surpassed 30,000, breaking the previous attendance record of 26,337 in 2003. The conference offered a strong plenary and technical program, evident in the opening general session—titled “Reserves Recovery and Decline: A Global Perspective”—that featured a global who’s who in the oil and gas industry. Leading off the session was Andrew Gould, Chairman and Chief Executive Officer of Schlumberger, who also chaired this year’s Offshore Europe conference. Gould con-tends that the world has enjoyed a false sense of energy security because of the excess oil production in the late 1980s and the 1990s. “Today, rapid demand growth due to the emergence of China and India and a lack of investment in an aging production base and refining system have led to very little security of supply of crude oil, natural gas, and refined products,” he said. A New Era Gould agreed with other panelists in the opening plenary that hydrocarbons will be the fuel of choice for perhaps decades to come, but that development and production have entered a new phase. “Reserves are large but finite, operations in new areas are becoming even more technically complex, and nonconventional hydrocarbons will form a larger part of the production base” in the future, he said. Principally, production decline rates in mature basins are growing in significance. “We are moving into a period where the bulk of new developments will either be in deep water or harsh Arctic conditions, or in the hands of national oil companies,” he said. “Technology will continue to emerge for finding and development; however, we will also see a huge increase in technology developed to increase production from mature fields and, therefore, prolong the production plateau or slow the rate of decline.” Mahmoud Abdul-Baqi, Vice President of Exploration for Saudi Aramco, outlined the challenges facing the industry as it strives to develop additional reserves to meet global consumption. “The main challenge is to commit the capital to develop reserves,” he said, and that investment needs to be made now. Regarding technology, greater emphasis should be placed on tools that expand the reserves base and drive down the cost of development. Producers need technology that promotes more accurate imaging of reservoirs, enhances automated field surveillance, and allows for faster drilling, Abdul-Baqi said. “There is no real physical shortage of oil,” Abdul-Baqi said, contradicting proponents of the “peak oil” argument. In particular, he said, large areas of Saudi Arabia are unexplored, and the country’s exploration program is expanding. In addition, the kingdom will continue to maintain spare production capacity of 1–2 million BOPD. The robust outlook for oil and gas will create numerous opportunities for young professionals, who should be recruited by the industry aggressively, he said.

Exploration histories and future potential: overview

The ‘exploration histories and future potential’ section of the Proceedings is designed to provide new insights for future exploration through leveraging learnings from past experiences. In this regard, the exploration histories of selected plays and fields from the Tertiary through the Palaeozoic of NW Europe are used to illustrate these learnings and to provide a guide to determining future potential. It is well recognized that, from a global perspective, NW Europe possesses world class petroleum systems. However, it is commonly perceived as a mature province for exploration and its future potential depends largely on our ability to understand better the known plays and our creativity to generate new plays. The North Sea region, in this context, benefits from the presence of two super source rocks, in the Kimmeridgian and Westphalian, and a diverse stratigraphy resulting in more than twenty plays from the Tertiary to the Palaeozoic. Historically, on a world-wide basis, the majority of stratigraphic traps have been discovered by serendipity. The wealth of high quality datasets in the North Sea and NW Europe, in combination with new advances in technology, provide an excellent natural laboratory to determine if untested plays and trapping concepts still remain.