Modeling lost production from destroyed platforms in the 2004–2005 Gulf of Mexico hurricane seasons

Hurricanes Ivan, Katrina, and Rita passed through the Gulf of Mexico during 2004 and 2005 and resulted in the largest number of destroyed and damaged offshore oil and gas structures in the history of Gulf operations. In the final official government assessment, a total of 126 platforms were destroyed and over 183 structures were identified as having extensive damage. Production associated with wells and structures that are not redeveloped are classified as lost. The purpose of this paper is to derive functional relations that describe the likely contribution the collection of destroyed assets would have made to future production in the Gulf of Mexico. We estimate that the total remaining reserves from the set of destroyed structures range in value between $1.3 and $4.5 billion depending on the assumptions employed. We summarize the impact of the storms on the Gulf of Mexico oil and gas infrastructure and discuss the main issues involved in redevelopment decision making. A meta-model analytic framework is applied to perform sensitivity analysis and to explore the interactions of assumptions on model output. A discussion of the limitations of the analysis is presented.     

Economic limit of Outer Continental Shelf Gulf of Mexico structure production

The economic limit of an oil and gas asset occurs when income from production is less than the direct cost of operation. Economic limits determine the threshold for profitable operations and are often considered from a conceptual perspective rather than as an object for empirical assessment. The purpose of this paper is to derive empirical estimates of the economic limit of offshore structures in the Outer Continental Shelf Gulf of Mexico. We classify 1962 decommissioned structures between 1986–2009 by structure type, primary production, water depth and year of removal, and compute end-of-life production, adjusted gross revenue, and water cut thresholds according to various levels of categorization. During the last year of production, historic gross revenues averaged $539,000 for oil structures, $955,000 for gas structures, and $1.1 million for dry gas structures. Daily end-of-life production ranged from 50 BOEPD for oil structures to 647 MCFEPD for gas structures and 788 MCFEPD for dry gas structures. The economic limits for oil and gas structures increased to $1 million and $1.7 million over the period 2005–2009.     

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.     

Competitiveness of shallow water hydrocarbon development projects in Mexico after 2015 actualization of fiscal reforms: Economic benchmark of new production sharing agreement versus typical U.S. federal lease terms

Development of Mexican hydrocarbon reservoirs by foreign operators has become possible under Mexico's new Hydrocarbon Law, effective as per January 2015. Our study compares the economic returns of shallow water fields in the Gulf of Mexico applying the royalty and taxes due under the fiscal regimes of the U.S. and Mexico. The net present value (NPV) of the base case scenario is US$1.4 billion, assuming standard development and production cost (opex, capex), 10% discount rate accounting for the cost of capital and revenues computed using a reference oil price of $75/bbl. The impact on NPV of oil price volatility is accounted for in a sensitivity analysis. The split of the NPV of shallow water hydrocarbon assets between the two contractual parties, contractor and government, in Mexico and the U.S. is hugely different. Our base case shows that for similar field assets, Mexico's production sharing agreement allocates about $1,150 million to the government and $191 million to the contractor, while under U.S. license conditions the government take is about $700 million and contractor take is $553 million. The current production sharing agreement leaves some marginal shallow water fields in Mexico undeveloped for reasons detailed and quantified in our study.     

The impact of weather and ocean forecasting on hydrocarbon production and pollution management in the Gulf of Mexico

Over the past 2 years, the vulnerability of offshore production in the Gulf of Mexico (GOM) has been brought to light by extensive damage to oil and gas facilities and pipelines resulting from Hurricanes Ivan, Katrina, and Rita. The occurrences of extreme weather regularly force operators to shut-down production, cease drilling and construction activities, and evacuate personnel. Loop currents and eddies can also impact offshore operations and delay installation and drilling activities and reduce the effectiveness of oil spill response strategies. The purpose of this paper is to describe how weather and ocean forecasting impact production activities and pollution management in the GOM. Physical outcome and decision models in support of production and development activities and oil spill response management are presented, and the expected economic benefits that may result from the implementation of an integrated ocean observation network in the region are summarized. Improved ocean observation systems are expected to reduce the uncertainty of forecasting and to enhance the value of ocean/weather information throughout the Gulf region. The source of benefits and the size of activity from which improved ocean observation benefits may be derived are estimated for energy development and production activities and oil spill response management.     

全球深水油气资源勘探开发现状及面临的挑战

全球海洋油气资源非常丰富,其中大陆架占据主要部分,约为60%左右;深水、超深水的资源量也不容小觑,约占全部海洋资源量的30%。但分布十分不均,主要分布在巴西、墨西哥湾、西非三大热点地区。截至2007年,海上油气探明储量约1526×108t,占全部探明储量的27%左右,深水已成为未来油气生产的重要基地。21世纪以来,各大石油公司纷纷加快进军深水区域的步伐,不断加强勘探开发投资力度,海上油气产量稳步上升。西非、北美和拉丁美洲依然是未来深水油气生产的重要区域,亚洲也将成为一个十分重要的深水油气生产基地。但深水油气勘探开发也面临着两个挑战:一是深水油气勘探开发难度不断增加;二是深水油气勘探开发投资回报率不断下降。如果未来不能很好地解决深水技术难题,将会降低深水油气资源项目的吸引力。     

Assessment of oil and natural gas resources in the Gulf Cooperation Council countries

This paper deals with the assessment of oil and natural gas resources in the Gulf Cooperation Council. Currently, the reserves of oil and natural gas are estimated at 461.70 × 10⁹ barrels and 615.58 × 10¹² SCF, respectively. Data are given and analyzed on reserves and production for the period 1978–1989.     

我国主要盆地油气资源勘探开发现状和发展前景

截至2007年底,全国累计探明原油地质储量中的72％、经济可采储量中的87．4％以及累计探明气层气地质储量中的37．4％、经济可采储量中的42．3％已投入开发。全国原油剩余经济可采储量205809．83×10^4t。有15个盆地累计探明原油地质储量超过1×10^8t,它们的合计剩余经济可采储量为203968．00×10^4t,平均储采比11．67．而地质资源量和可采资源量分别占全国总量的82．0％和84．8％。平均探明程度分别为43．5％和42．1％;待发现常规石油地质资源量和可采资源量分别占全国总量的72．3％和76,6％。全国气层气剩余经济可采储量24372．60×10^8m^3．在12个累计探明气层气地质储量超过300×10^8m^3的盆地中,剩余经济可采储量24326．11×10^8m^3,平均储采比40．3;地质资源量和可采资源量分别占全国总量的87．7％和88．7％．平均探明程度分别为19．0％和18．2％：待发现常规天然气地质资源量和可采资源量分别占全国总量的85.3％和86．5％。我国油气储产量集中于大中型盆地,而且也是待发现资源主要阵地。     

Lifecycle analysis of different urban transport options for Bangladesh

Once again, sustained high oil prices are forcing policy makers in oil importing countries to consider alternatives to oil products as transportation fuels. Unlike in the past, advancements in technology, relative success of some experiments and increased familiarity among and acceptance by the public of some alternatives indicate a higher likelihood of success. In particular, natural gas offers a couple of the best options as compressed natural gas (CNG) and chemical conversion of natural gas into diesel (gas-to-liquids, GTL). These options are likely to be most attractive in countries that have cheap access to natural gas. We compare lifetime costs of several individual transportation options for Bangladesh, an oil importer with natural gas reserves. The results are then used to inform the natural gas policy debate in the country. Assuming a natural gas price of $1.5 per million Btu, both the CNG and GTL options are competitive with conventional gasoline/diesel cars if the oil price stays higher than $35–40 per barrel. If natural gas price increases after new upstream developments, CNG becomes less attractive while GTL remains competitive up to $2.5 if capital costs of GTL facilities decline as expected. Under a government policy push (lower discounting), the breakeven price of oil falls to $30–35 per barrel.     

US military expenditures to protect the use of Persian Gulf oil for motor vehicles

Analyses of the full social cost of motor vehicle use in the US often estimate an “oil import premium” that includes the military cost of defending oil supplies from the Persian Gulf. Estimates of this cost have ranged from essentially zero to upwards of a $1 per gallon (about Analyses of the full social cost of motor vehicle use in the US often estimate an “oil import premium” that includes the military cost of defending oil supplies from the Persian Gulf. Estimates of this cost have ranged from essentially zero to upwards of a $1 per gallon (about $0.25 per liter). In this paper, we attempt to narrow this range, by carefully answering the question: “If the US highway transportation sector did not use oil, how much would the US federal government reduce its military commitment in the Persian Gulf?” We work towards our answer in five steps, accounting for interests not related to oil, the interests of other oil-consuming countries, the interests of producers apart from the interests of consumers, and the interests of non-highway users of oil. We estimate that were there no oil in the Persian Gulf, then US combined peacetime and wartime defense expenditures might be reduced in the long run by roughly $27–$73 billion per year (in 2004 dollars), of which roughly $6–$25 billion annually ($0.03–$0.15 per gallon or $0.01–$0.04 per liter) is attributable to motor-vehicle use.     

Energy demand analysis of Port-Harcourt refinery,Nigeria and its policy implications

This paper analyses energy demand of Port-Harcourt refinery, Nigeria, based on information obtained from its annual publications, backed-up by spot interviews. The analytical approach adopted for the study involves the calculation of energy intensities to determine the refinery's annual energy demand for various energy types considered from 1989 to 2004. The results showed that the actual energy demand per year for processing crude oil into refined products, exceeded, in varying degrees the stipulated refinery standard of 4 barrels of oil equivalent (BOE) per 100 BOE. It varied from 4.28–8.58 BOE per 100 BOE. In terms of energy demand efficiency, this implies very poor performance of the refinery during the 16-year period under investigation. The excess demand which translates to an average daily wastage of about 2005 BOE is estimated to be $56,196 (US Dollars) based on the 2003 OPEC basket price of $28.0213 per barrel. Lack of optimal fuel utilization-mix and non-compliance with the Turn-Around-Maintenance schedules were attributed to the refinery's inefficient energy demand pattern.     

Break-even price for upstream activities in Brazil: Evaluation of the opportunity cost of oil production delay in a non-mature sedimentary production region

Some Latin American policy-makers and analysts state that it would be better to hold oil reserves in place than to produce and cash it now, given the recent oil prices spikes and the fear related to future oil supply disruptions. This article evaluates the strategy of delaying the start-up of oil production in a discovered field with proved reserves. A Reference Discounted Cash Flow (FCD-R) for a typical 350 million barrel Brazilian oil field was simulated. The study estimated which future oil price may render the project insensitive to a delay of 5, 10, 15 or 20 years in its production beginning. Additionally, the value of the in situ oil stock was calculated, providing the opportunity cost for delaying oil production in a frontier area, such as Brazil. It is an application of the Hotelling Principle. Findings indicate that progressive delays of 5 years in the start-up of operation of a typical oil field reduce its revenues by a factor of 2. A delay of 10 years would be justifiable at international oil prices higher than US $15/bbl. Delays higher than 10 years lead this break-even price to values between US $200 and 350/bbl.     

Forecast of oil reserves and production in Daqing oilfield of China

As China’ largest oilfield, Daqing is of great importance to China, this paper analyzes the status of the Daqing oilfield and forecasts its ultimate recoverable reserves by use of the URR model. The forecast results are presented for three scenarios which show that the ultimate recoverable reserves in Daqing oilfield are 3574.0 million tons in the optimistic scenario, 3169.3 million in the base case scenario and 3033.3 million in the pessimistic scenario, respectively. A system dynamics model is established and the quantitative relationships between variables in the model are determined. Total oil production, remaining recoverable reserves, annual newly discovered reserves, and the degree of reserves recovery before 2060 are simulated under the three scenarios by use of the system dynamics model. The forecast results show that the future oil production in Daqing oilfield will continue declining, under the base case scenario, from 41.6 million tons in 2007 to 8.0 million tons in 2060. For Chinese policy-makers, it is worth paying attention to the problem of whether oil production in new oilfields can effectively make up for the decline in production of the large, old oilfields.     

Progressive mobilization of oil resources a factor in ensuring moderate price rises part 1

The first part of this paper aims to establish the regional distribution of ultimate resources of conventional oil and to assess the size of future discoveries and their share in the renewal of world oil resources. The authors use a synthesis of seven recent studies as their starting point. This analysis suggests that in the long run it will be difficult to bring about a significant and durable reduction in the importance of the Arabo-Persian Gulf on the international petroleum scene. The study also presents a tentative breakdown of ultimate oil resources in terms of production costs, proven reserves, future discoveries and additional quantities, directly arising from technical and cost progress in enhanced oil recovery methods. The authors conclude that the Middle East and planned economy countries account for nearly 60% of ultimate oil resources exploitable at a cost of less than $20/bbl and that more than half of the resources available in the rest of the world are exploitable at more than $12/bbl.     

Offshore hydrocarbon production and potential of Thailand

Four commercial gas/condensate fields have been delineated in the Gulf of Thailand with total gas reserves of at least 7 trillion ft³. Efforts are being made to bring up from 500–700 MMCFD of gas ashore by 1983/84. The completion of the first phase of the pipeline system will enable production from Union Oil Co. of Thailand's Erawan gas field from mid-September 1981, at a flow rate of from 200 to 250 MMCFD. Also, 6000–7500 b/d of condensate will be recovered as a by-product. Small amounts of crude oil were also encountered in some wells. The remnants suggest a wide variation of organic sources from continental woody material as a primary source to minor components from marine algae. Hydrocarbon accumulations in deep Tertiary sedimentary basins in the Gulf are well developed at depths ranging from 1009 to 2691 m where mature source beds are closely associated with reservoir deltaic sands within growth-fault structures. Other prospective productive anomalies in the Gulf appear to have a large potential.Deep water drilling beyond 200 m water depth in the Andaman Sea revealed that the Tertiary source beds are mainly immature. Tertiary sediments in the Andaman Sea, therefore, have a low potential for hydrocarbon accumulations.The pre-Tertiary sedimentary basins that lie undisturbed within the “Cold Basin” region beneath the offshore areas of the Andaman Sea and the Gulf of Thailand have more favorable conditions for hydrocarbon potential. Study of source beds and reconstruction of the paleogeography of pre-Tertiary rocks, especially the carbonate facies along the coastal plains of Thailand, will provide important information on pre-Tertiary hydrocarbon potential.     

Technological change and petroleum exploration in the Gulf of Mexico

We examine the impact of technological change on oil and gas exploration in the Gulf of Mexico from 1947 to 1998, using a unique micro-data set. An index variable for technological change is constructed to capture both the number and significance of technological innovations in the offshore industry over the study period. Empirical models of exploration-discovery and of drilling cost are used to assess the effect of technological change at both the field level and the regional level. Our results indicate that technological change played a very significant role in the offshore industry over the past 50 years, increasing reserves and lowering cost. Although depletion effect was dominant over the first two decades, the effect of technological change was able to offset that of resource depletion over the entire 50-year study period.