Estimation Of Oil Reserves Research Articles

Development and Identification of Petrophysical Rock Types for Effective Reservoir Characterization: Case Study of the Kristine Field, Offshore Sabah

Rock typing is an essential tool used to distribute rock and fluid properties in reservoir models. It provides estimates of oil reserves that are more accurate during field studies and prediction of reservoir performance. However, geomodelers are frequently faced with challenges of integrating geological facies with rock characteristics and fluid flow to predict petrophysical properties due to limited correlation between geological features and engineering concepts. Therefore, in this study, petrophysical rock types (PRTs) were defined using both core and log data, and the relationship between capillary properties, hydraulic flow units, permeability and porosity correlations was enhanced. The PRTs were determined through quantitative methods using mercury injection capillary pressure information and a probabilistic approach to distinguish convoluted pore systems. Subsequently, various pore structure characteristics were defined to detect petrophysical variation among pore systems to enhance petrophysical rank of rock types. Furthermore, for a reservoir, consistency in J-function curves for saturation height above free water level was determined. Finally, permeability generated from other empirical equations was compared with log-derived permeability to recommend a suitable approach for clastic formations in the Sabah Fields. By using capillary data to derive saturation height functions, the hydraulic units demonstrated consistent results of rock types, reduced the uncertainties in reservoir models and integrated geological description with engineering hydraulic features. The Winland R35 approach was found to be susceptible to pore throat radius, and traditional neutron–density rock typing approach was dependent on the shale cutoff used.

Probabilistic study of advanced methods in decline curve analysis (DCA) used for the estimation of oil reserves during the transient flow regime

Los reservorios del Noroeste Peruano han producido por más de un siglo principalmente areniscas silicoclásticas, de baja permeabilidad, a través de yacimientos en compartimentos o sub-bloques generados por un alto fallamiento. El mecanismo característico de impulsión es depletación por gas en solución y los pozos comúnmente son producidos con un sistema de levantamiento artificial por bombeo mecánico o gas lift; el factor de recobro promedio alcanzado en estos yacimientos está entre 8% y 15%. En los últimos años se ha observado un gran avance en las técnicas de estimación de reservas a través de análisis de curvas de declinación (DCA) en yacimientos no convencionales de muy baja permeabilidad.Estas técnicas también pueden ser utilizadas en reservorios convencionales apretados, aquellos típicamente encontrados en la Cuenca Talara de Perú, en los cuales la aplicación de la técnica tradicional de DCA suele sobreestimar los pronósticos de producción y el cálculo de reservas. Alternativamente, se ha propuesto evaluar los modelos de Declinación Estrecha Extendida (SEDM), Ley de Potencia, Duong y Declinación Exponencial Extendida, en los reservorios de esta cuenca (Duong, A. N., 2010). Durante el proceso de evaluación, se utilizó la información de 30 pozos productores de diferentes reservorios apretados de la Cuenca Talara: Manta, Mesa, Mogollón y Pariñas Inferior. Se probaron los citados métodos de análisis de declinación con la historia de producción de los primeros 6, 12 y 24 meses; cabe señalar que, de acuerdo a la observación realizada y debido a la baja productividad de estos reservorios, se determinó que su flujo aún se encontraba en estado transitorio durante el periodo de análisis. Los pronósticos se compararon con datos reales de producción y los modelos de declinación se clasificaron por orden de prioridad de acuerdo a la certeza de su grado de ajuste. Se eligió la técnica más idónea para generar, a través de un enfoque probabilístico, utilizando la simulación Monte Carlo, un conjunto de curvas tipo para la cuenca Talara; de esta manera, se obtuvieron los percentiles P90, P50 y P10. Los rangos de permeabilidad en los reservorios de los casos evaluados varían entre 0.01 y 1 mD. Se ha observado que la aplicación del modelo DCA de ARPs en pozos con poca historia de producción de reservorios de baja permeabilidad, resulta impreciso en las predicciones de estimados de reservas. Por otro lado, los nuevos métodos de DCA son más conservadores en sus pronósticos y, por ende, más precisos en este caso debido a que permiten incorporar información en estado transitorio. La aplicación de este nuevo enfoque ayudará a obtener pronósticos confiables en la evaluación de futuras estrategias de desarrollo y a predecir con mayor certeza la producción de futuros trabajos de workover y nuevos pozos de desarrollo.

АПРОБАЦИЯ МЕТОДИК ПРОГНОЗИРОВАНИЯ ТЕХНОЛОГИЧЕСКОЙ ЭФФЕКТИВНОСТИ ВЫРАБОТКИ И ОЦЕНКИ ЗАПАСОВ НЕФТИ ПРИ ПОДБОРЕ СКВАЖИН-КАНДИДАТОВ НА ПРОВЕДЕНИЕ МЕРОПРИЯТИЙ ПО ОБРАБОТКЕ ПРИЗАБОЙНОЙ ЗОНЫ СКВАЖИН НА ПРИМЕРЕ СЕВЕРО-ОРЕХОВСКОГО МЕСТОРОЖДЕНИЯ

Актуальность исследования вызвана необходимостью оценки текущего состояния качества запасов нефти призабойной зоны скважин и прогнозирования технологической эффективности существующей выработки нефтяных запасов при подборе скважин-кандидатов на проведение мероприятий по обработке призабойной зоны, что соответствует потребностям мировой практики в поиске наиболее результативных методик освоения нефтегазовых месторождений. Цель: определить величину изменения балансовых запасов нефти на примере Северо-Ореховского месторождения и произвести анализ методик, позволяющих осуществить прогнозирование технологической эффективности выработки и оценки запасов нефти при подборе скважин-кандидатов на проведение мероприятий по обработке призабойной зоны скважин, применяемых на территории Северо-Ореховского месторождения Объект: Северо-Ореховское месторождение как энергоресурсный комплекс, на базе которого осуществляется не только применение традиционных методик прогнозирования технологической эффективности выработки нефтяных запасов, но и апробируется качественно новая методика оценки запасов нефти при подборе скважин-кандидатов на проведение мероприятий по обработке призабойной зоны. Методы: прогнозирование, обусловившее понимание технологической эффективности выработки и оценки запасов нефти при подборе скважин-кандидатов на проведение мероприятий по обработке призабойной зоны скважин; определение величин удельных остаточных балансовых запасов обусловило обращение к сравнительному анализу возможностей скважин доноров и акцепторов; анализ и оценка величины выходящих из дренирования запасов; оценка значения текущей нефтенасыщенности. Результаты. Большинство нефтяных месторождений Западной Сибири находится на поздней стадии разработки. В связи с этим вопрос выработки остаточных запасов становится первоочередным. Для принятия проектных решений на прогнозный период разработки необходима оценка остаточных ресурсов углеводородов месторождения, что обусловливает актуальность исследования и адаптации методов оценки ресурсов месторождения. Произведен сравнительный анализ существующих методик прогнозирования технологической эффективности выработки и оценки запасов нефти, используемых при подборе скважин-кандидатов на проведение мероприятий по обработке призабойной зоны скважин. Предлагается измененный способ определения удельных балансовых запасов нефти, позволяющий для каждой добывающей скважины учесть запасы и отборы всего объекта, а также фильтрационно-емкостные свойства всего фонда скважин. Установлено, что метод определения величин удельных остаточных балансовых запасов предполагает выявление скважин доноров и акцепторов. Выявлено, что используемый подход в подборе скважин-кандидатов под обработку призабойной зоны является универсальным, так как позволяет выявлять скважины с недостаточной выработкой при существующем потенциале (водоограничивающие, гидрофобизирующие методы увеличения нефтеотдачи). Более того, данный методический подход предполагает принцип оценки относительной динамики отборов нефти и выявление несоотносимо высоких с остаточным потенциалом темпов падения добычи нефти. Методический подход, совмещающий свойства прогноза ожидаемой технологической эффективности и критериального обоснования, основывается на применении процедуры расчетов параметров множественного регрессионного анализа. В его основе лежит предположение, что технологическая эффективность мероприятий (исключая успешность, случайный фактор) тесно связана с геолого-технологическими параметрами, характеризующими потенциал скважин – остаточные извлекаемые запасы, эффективная нефтенасыщенная мощность, площадь зоны дренирования, проницаемость и т. д. Доказывается, что данный метод подходит не только для подбора скважин-кандидатов под обработку призабойной зоны, но и для групп технологий увеличения нефтеотдачи различной специфики (по механизму вовлечения незадействованных запасов нефти); искомой функцией является технологическая эффективность от мероприятий (за год или за месяц), а аргументами – набор геолого-технологических показателей фонда скважин на дату проведения мероприятия. Предложена методика оценки остаточных балансовых запасов фонда скважин, что способствует определению качества нефтяных запасов для отдельной добывающей скважины и позволяет учесть запасы и отборы всего объекта, а также фильтрационно-емкостные свойства всего фонда скважин. Выводы. Установлено, что выявленные в ходе анализа особенности существующих методик позволяют решить ряд нефтепромысловых задач: определить объем выходящих из дренирования запасов (подбор водоограничивающих методов увеличения нефтеотдачи, ремонтно-изоляционные работы, коррекция режимов работы скважин, остановки); определить величину незадействованных запасов нефти, не участвующих в дренировании (гидровлический разрыв пласта, уплотнение); проанализировать достижимость выработки извлекаемых запасов, оцениваемых по общепринятым характеристикам вытеснения, по добывающим скважинам, то есть произвести их коррекцию.

Типизация карбонатных коллекторов для дифференцированного подсчета запасов нефти

Типизация карбонатных коллекторов для дифференцированного подсчета запасов нефти

Petrophysical Analysis of Well Logs for the Estimation of Oil Reserves in Southern Niger Delta

Gamma Ray log, Resistivity log, Density log, Micro-spherical focus log (MSFL), Deep Induction log (ILD) , Medium Induction log(ILM) and Spontaneous Potential (SP) log were collected for 2 wells in onshore Niger Delta. These insitu well logs were analyzed and interpreted. Porosity, permeability, water saturation, reservoir thickness and Shale volume were estimated for each hydrocarbon bearing zone delineated for each well. The parameters obtained were further analyzed and interpreted quantitatively to estimate the hydrocarbon potentials of each well. Twelve reservoir zones of interest (sand bodies) were delineated, correlated across the field and were ranked using average results of petrophysical parameters. In well one, Reservoirs E and F were identified as the thickest with 41ft each while reservoir A is the smallest in thickness (30ft). Petrophysical properties of hydrocarbon bearing zones delineated in well one ranged from 17.81% to 23.20% for porosity, 1292.09mD to 2018.17mD for permeability and 56.40% to 68.40% for hydrocarbon saturation compared to well 2 with 14.67% to 19.52% for porosity, 1211.61mD to1843.11mD for permeability and 51.80% to 66.40% for hydrocarbon saturation. The estimated averages of petrophysical properties for well one are 20.14% porosity, 1643.65mD permeability, 63.20% hydrocarbon saturation compared to well 2 with 15.55% porosity, 1582.58mD permeability and 61.93% hydrocarbon saturation. Results show 148.45MMBB and 145.91MMBB as oil reserve (Recoverable) for the field. From the results obtained, well one is likely to be more productive than well [2] and the field has exploitable oil in place.

Reconsidering the scarcity factor in the dynamics of oil markets: An empirical investigation of the (mis)measurement of oil reserves

This paper sheds light on the importance of the (mis)measurement of oil reserves in the market dynamics. Using proven oil reserves from three different institutional data sources and for two groups of oil-exporting countries (OPEC members and OECD major oil-exporting countries), we demonstrate that estimates of oil reserves from different institutions are likely to be driven by some common factors for the OPEC panel, which is not the case for the non-OPEC panel. The implications of these results from panel cointegration analysis can be seen in two ways. First, any discussion of the sources of reserves data seems not to be relevant since OPEC has an influence on the measure of its reserves whatever the energy agency that assesses them. Second, the literature dealing with the oil curse and the associated policy responses should consider oil reserves as an endogenous variable for the resource abundance.

Reservoir characterization and seal integrity of Jemir field in Niger Delta, Nigeria

Ignoring fault seal and depending solely on reservoir parameters and estimated hydrocarbon contacts can lead to extremely unequal division of reserves especially in oil fields dominated by structural traps where faults play an important role in trapping of hydrocarbons. These faults may be sealing or as conduit to fluid flow. In this study; three-dimensional seismic and well log data has been used to characterize the reservoirs and investigate the seal integrity of fault plane trending NW-SE and dip towards south in Jemir field, Niger-Delta for enhanced oil recovery. The petrophysical and volumetric analysis of the six reservoirs that were mapped as well as structural interpretation of the faults were done both qualitatively and quantitatively. In order to know the sealing potential of individual hydrocarbon bearing sand, horizon–fault intersection was done, volume of shale was determined, thickness of individual bed was estimated, and quality control involving throw analysis was done. Shale Gouge Ratio (SGR) and Hydrocarbon Column Height (HCH) (supportable and structure-supported) were also determined to assess the seal integrity of the faults in Jemir field.The petrophysical analysis indicated the porosity of traps on Jemir field ranged from 0.20 to 0.29 and the volumetric analyses showed that the Stock Tank Original Oil in Place varied between 5.5 and 173.4 Mbbl. The SGR ranged from leaking (<20%) to sealing (>60%) fault plane suggesting poor to moderate sealing. The supportable HCH of Jemir field ranged from 98.3 to 446.2 m while its Structure-supported HCH ranged from 12.1 to 101.7 m.The porosities of Jemir field are good enough for hydrocarbon production as exemplified by its oil reserve estimates. However, improper sealing of the fault plane might enhance hydrocarbon leakage.

The Iraq War, Turkey, and Renewed Caspian Energy Prospects

Many have linked US-led invasion of Iraq to its oil resources, leading some observers to question Caspian energy prospects. This article analyzes how Iraqi occupation and Caspian oil prospects have been inter-linked, via evolution of American and Turkish assessments of Iraq and Caspian region. It shows that, contrary to initial expectations, occupation of Iraq bolstered Baku-Tbilisi-Ceyhan project as well as a number of other increasingly significant natural gas export pipelines. The March 2003 invasion of Iraq has been inextricably linked with that country's oil reserves, estimated to be world's third largest after those of neighboring Saudi Arabia and Iran.1 It has been suggested, for example, that Iraq, under influence of US-led occupation, would actively undermine OPEC's collective market power, serve growing US consumer demand for imported petroleum as well as corporate need for new investment opportunities, and even manipulate flow of oil to China.2 American officials did little to dispel suspicions about US motives. As Baghdad fell, Vice President Dick Cheney claimed that Iraqi oil production could reach 3 million barrels per day by year's end, while Deputy Defense Secretary Paul Wolfowitz told US House Appropriations Committee that [t]he oil revenues of that country could bring between $50 billion and $100 billion over course of next two or three years.3 Given these assumptions of Iraq's oil prowess, doubts about Caspian energy resurfaced. More specifically, would Iraqi oil obviate need to transport higher-cost sources from landlocked Azerbaijan (and possibly Kazakhstan) to world markets via Baku-Tbilisi-Ceyhan (BTC) pipeline reaching Turkey's Mediterranean coast? Indeed, as participants at a post-invasion conference on Caspian oil and gas in Istanbul expressed, the prospect of expanded access to Iraqi energy reserves could cause investors to reconsider relatively expensive Caspian off-shore projects and construction of lengthy BTC route.4 In reality, just opposite has transpired. Great expectations for Iraqi oil remain slow to materialize, while BTC pipeline is operational, providing both a valuable alternative outlet for Azerbaijan's crude oil and a small but significant addition to global supplies.5 Although BTC had registered some progress before invasion of Iraq, prolonged damage to Iraq's oil infrastructure under occupation and effects of disrepair and sabotage, albeit marginal, on world energy markets virtually guaranteed economic viability not only of BTC pipeline, but also of its twin Baku-Tbilisi-Erzurum (BTE) or South Caucasus gas pipeline, which also conveys Azerbaijan's gas to Turkey. The seller's market has even brought Nabucco pipeline, a vastly more complex undertaking to transport Caspian and Middle Eastern natural gas supplies to Europe through Turkey, into realm of feasible. These accomplishments seem remarkable in light of fact that seminal BTC pipeline was nearly shelved after price collapse in 1998 and downgrading of Azerbaijan's offshore oil-reserve estimates. Initial US support for BTC was primarily political rather than financial. Despite favorable rhetoric from members of Clinton Administration, American government remained largely noncommittal towards funding BTC, even as a means of breaking Russian control over Caucasus transport corridor. Rather, Washington did more to back project by maintaining its ban on building of new pipelines from and through Iran. The occupation of Iraq inadvertently imparted a new momentum to Caspian projects like BTC and BTE by helping to ratchet up world energy prices. The aforementioned conditions also fed Turkey's interest in completing these projects. Prolonged constraints on Iraqi oil production and exports through Iraq-Turkey (IT) crude oil pipeline, combined with elevated world oil demand, not only improved commercial rationale of BTC and BTE pipelines, but also dampened Ankara's initial expectations that Turkey might obtain higher oil transit revenues and other economic benefits from restored trade with Iraq. …

Book Review - Hubbert's Peak: The Impending World Oil Shortage

This book provides a thorough explanation of the origin, exploration, production, and marketing of oil. The author’s goal is to increase awareness (if not an attempt to raise the alarm) that an unprecedented energy crisis is just over the horizon. Kenneth Deffeyes predicted an impending oil crisis by 2004 which will manifest itself by a dramatic increase in oil prices. Does this sound familiar? The few years since this book has been published seem only to provide additional proof that Deffeyes’ prophecies might be correct. The author goes beyond Hubbert’s model; not only does he model current oil production and reserves to forecast an impending peak, but he also geographically and experimentally explains why oil reserves and oil recovery will peak soon and why even generous oil reserve estimates will lead only to a few years’ variation in the expected production peak.

Análise de impactos da metodologia de estimativa da porosidade em reservas de petróleo por meio de simulação de Monte Carlo

Nos trabalhos de estimativa de reservas de petróleo, geralmente, assume-se que a variável aleatória porosidade do reservatório se distribui de acordo com o modelo Gaussiano. Desse modo, assume-se que o valor esperado da distribuição pode ser estimado por meio da média aritmética dos valores de porosidade obtidos a partir de análises de perfilagens e plugs em nível de poço. Isso implica que a distribuição Gaussiana é a melhor escolha para a modelagem dos dados dessa variável, mas nem sempre essa premissa é verdadeira. Nesse trabalho, ao se utilizarem dados reais de porosidade de uma camada de rocha reservatório do poço 3-NA-002-RJS da bacia de Campos, mostra-se que a distribuição logística é a que melhor se ajusta aos dados amostrais. Em tais casos, como ilustra a análise numérica, pode-se cometer erros significativos ao selecionar a média aritmética amostral como sendo o estimador da média populacional. Os resultados apontam que o uso inadequado do tipo de distribuição pode gerar impactos significativos nas estimativas das reservas recuperáveis, observando-se que a média aritmética tende a subestimar o P90 e a superavaliar o P10.

When Will the Oil Run Out?

In his Policy Forum “Oil: Never cry wolf—why the petroleum age is far from over” (21 May 2004, p. [1114][1]), L. Maugeri has done considerable double-counting to reassure us that “the world is not running out of oil.” He cites various upward revisions in historical estimates of oil reserves and resources, culminating in the 2000 U.S. Geological Survey estimate of 3021 billion barrels of ultimately recoverable resources, from which he draws the conclusion that “overall, the world retains more than 3 trillion barrels of recoverable oil resources.” Unfortunately, that 3021 figure includes the oil that has already been consumed. It consists of “undiscovered conventional oil” (732 billion barrels), “reserve growth” (688 billion barrels), “reserves remaining” (891 billion barrels), and “cumulative production” (710 billion barrels) ([1][2]). Deduct the 710 billion barrels already consumed, and the remaining oil totals 2311 billion barrels, a figure closer to other estimates. Maugeri ignores the fact that the discovery of reserves lowers the estimate for undiscovered oil; it does not necessarily raise the total figure for ultimate recoverable oil resources. He also calculates a “life index” of 40 years for known reserves, using current consumption figures. Using the 891 billion barrels (reserves remaining) figure would reduce that number to 32 years, but there are flaws in that calculation. Making projections based on current consumption is meaningless if consumption is rising (which it is). With a projected annual growth worldwide of 1.9% from 2001 to 2025 ([2][3]), the 32 years' supply would decline to about 26 years. I believe we should draw very different conclusions from the present estimates. First, although the experts may quibble over their differences, they are in broad agreement: All the estimates I have seen agree within a factor of about two as to how much oil remains. The policy implications are not much different, wherever you may stand in that range. Oil resources are running down, and the supply is inelastic. Second, we should be preparing now for a difficult transition. Europe and Japan, poor in oil resources, have gone much farther in making adjustments in energy use than the United States. Furthermore, they have stable or declining populations and similar requirements for energy and have chosen to limit demand, particularly by imposing high taxes on gasoline. The United States is putting itself in the worst possible position for the energy transition by encouraging unchecked population growth (mostly driven by immigration) and doing very little to encourage energy efficiency. 1. [↵][4]USGS Digital Data Series DDS-60. 2. [↵][5]U.S. Department of Energy, Energy Information Administration, International Energy Outlook 2004, Table A2, “World Total Energy Consumption by Region & Fuel, Reference Case” (EIA, Washington, DC, 2004). [1]: /lookup/doi/10.1126/science.1096427 [2]: #ref-1 [3]: #ref-2 [4]: #xref-ref-1-1 View reference 1 in text [5]: #xref-ref-2-1 View reference 2 in text

INFLUENCES OF ASPHALTENE PRECIPITATION ON CAPILLARY PRESSURE AND PORE SIZE DISTRIBUTION OF CARBONATE RESERVOIRS

Asphaltene depositio n has profound effects on oil flow through porous medium. The investigation of the influences of asphaltene precipitation on carbonate reservoir rocks has minor interests in comparison to studies investigated sandstones ones. Therefore, this study is undertaken to provide accurate insights, especially for carbonate reservoirs of low permeability. In this study, two groups of experiments are undertaken. The first experimental group investigates effects of asphaltene precipitation on (a) petrophysical properties of carbonate rocks, including absolute permeability, effective porosity, and hydraulic radius, and (b) on oil-water relative permeability and water flooding performance. The second group searches for the effects of asphaltene precipitation on capillary pressure and pore size distribution of low permeability carbonate reservoirs. Conducted experiments are achieved using actual reservoir liquids of crude oil and brine, flowing through actual carbonate cores under similar reservoir conditions of temperature and pressure. The results indicated that asphaltene precipitation damages absolute permeability and hydraulic radius drastically, reduces effective porosity, and improves relative permeability of water for different asphaltene contents of crude oil flowing through carbonate reservoirs. In addition, oil reservoirs of high asphaltene content have shown higher values of irreducible water saturation than that ones of low asphaltene content in their crude oils. Precipitation of asphaltene in carbonate rock causes changes in the position of capillary pressure at high mobile oil saturation and reduces values resulted for pore size distribution curves, especially for small pore radii carrying crude's of high asphaltene content. Neglecting the proven influences of asphaltene precipitation may lead to erroneous description of carbonate reservoirs. Therefore, analysis of petrophysical properties and pore size distribution of carbonate reservoirs has to be updated during the extended life of oil reservoir and based upon accurate values of asphaltene content of the flowing crude oils. Applications of the attained results of this study are expected to provide real improvement in reservoir description, more reliable estimation of oil reserves, accurate predicted values of reservoir rock damage, and also better descriptive functions for future reservoir simulation studies.

Published Estimates of Oil Reserves Do Not Influence Us Doe/Eia Oil Production Forecasts. World Oil Reserves to Increase through Next Two Decades?

Non-OPEC oil reserves worldwide have an R/P ratio of 15. In the USA, the ratio is near 10; a figure stated for much of the last century. The US DOE/EIA world oil production forecasts given in Table 1 ignore the published forecasts of oil reserves. The naive statement of the position for the USA is that the presently known oil reserves will have been used by 2010. In 2010, US production is forecast to be a little less than 9 million b/d and in 2020 is forecast to be a little over 9 million b/d. The US DOE/EIA is clearly confident that there will be oil reserves available to support world oil production of 87.7 million b/d in 2005; 96.6 million b/d in 2021; 105.6 million b/d in 2015 and 15.4 million b/d in 2020. Hence real at economic world oil reserves are forecast to increase steadily through the next two decades.

Shell Petroleum Exploration and Production 1980 to 1997: Reserves Analysis and Key Financial Statistics in Money and in Real Terms

An analysis of Shell's petroleum exploration activities over an eighteen year period is presented Key findings include; - the cost of finding oil decreased by a factor of four over the period 1981 to 1997. - revision to oil reserves have shown no trend - improved recovery estimates of oil reserves have shown no trend - well analysis shows that whilst in 1980 only one exploration well in four was successful, in 1997 more exploration wells were productive than dry. There is now only a few per cent chance that a development well will be dry compared with a 5 to 10 percent chance of a dry development well in the early 1980s. - depreciation depletion and amortisation (DDA) changes on Shell's reserves have increased substantially in money and in real terms over the last eighteen years. DDA changes are now sometimes equal to capex whilst in 1980 they were only 30 per cent of capex. - from 1982 to 1997, capex per b.o.e. reserves has increased by 60 per cent in real terms. - for crude oil and NGLs, Shell has dropped the reserves to production (RIP) ratio from 13 years in the 1980s to 11 years since 1994. - production costs for oil and gas have fallen from $11.0 per b.o.e. in 1981 to $2.9 per b.o.e.£. in 1997. whilst the net proceeds (selling price of crude oil and natural gas) have fallen from $48.6 b.o.e. in 1981 to $17.0 b.o.e. in 1997, net earnings (profits after tax and all expenses) have fallen from $7.1 b.o.e. in 1980 to $3.5 b.o.e. in 1997 both expressed in (1997) real US$ terms.

Petroleum reservoir engineering for crude oil and natural gas developments.

This paper presents characteristic studies that should be considered in oil and gas field developments. Several significant articles are illustrated and discussed, covering the following items; (1) reservoir rock properties, (2) waterflooding, (3) underground natural gas storage and (4) petroleum reserves and techno-economics. The effects of clays and clay minerals on relative permeability curves are clarified. The new porosity measurement of shaly sand cores is devised. At the planning stage, A and B blocks in Sarukawa oil field were given the priority of waterflooding projects by means of application of reservoir engineering data, in addition to the usual geological and geophysical information. The reservoir engineering study on Sekihara gas field has contributed to research for underground natural gas storage. The proposed procedure on moving boundary problem may be required in relatively smaller reservoir. The developed probability model on estimation of oil reserves and techno-economical appraisal method are discussed.

A Probabilistic Model for Estimation of Oil Reserves

This paper presents an actual FORTRAN program of probabilistic model for uncertainty analysis in estimating oil reserves. Factors in this calculation are expressed by triangular probability distribution and uniform random numbers are generated by multiplicative congruence method. The authors consider the shape effect of triangular distribution on estimation of oil reserves. Acknowledgment is given to Dr. Paul J. Root, Associate Professor of Petroleum and Geological Engineering, University of Oklahoma for his valuable informations concerning with Decisions under Uncertainty in carrying out this study.

Developments in Western Canada in 1951

Exploration and development activity in Western Canada continued to increase in 1951 with Alberta as the main center of interest. The total number of wells drilled in 1951 was 1,270, and 485 of these were exploratory tests. At the end of the year 218 rigs were operating. Of 153 geophysical parties, 140 were operating seismic surveys. The discovery picture for 1951 is similar to that in other reef-oil provinces. Most of the new pools in Alberta are extensions on the trend of previous discoveries. Interest is increasing in the northern part of the Williston basin area in Saskatchewan and Manitoba owing to the discoveries in North Dakota, at Virden in Manitoba, and, at the beginning of 1952, at Fosterton in western Saskatchewan. At the end of the year there were signs of renewed interest in several areas of the Rocky Mountain foothills. The export of gas from Alberta, except for defence needs, is still banned, but new regulations to stimulate the search for increased gas reserves resulted in considerable increases in the 1950 reserves and the lifting of the export ban is in consequence anticipated. Permission was given, subject to certain controlling conditions, to export natural gas for the use of Montana metal mining and smelting defence projects. Estimates of oil reserves in Western Canada vary, but a conservative estimate indicates an increase to nearly 1,300 million barrels, and available gas reserves have been given as 8 trillion cubic feet on January 1, 1952. A new pipeline outlet to the West Coast has been approved and plans for its construction are going ahead. The Alberta Government stimulated interest in the Athabaska tar sands as a potential oil source by sponsoring a well attended technical conference at Edmonton in September. The Saskatchewan Government in consultation with oil operators has prepared new oil and gas regulations which probably will be enacted in 1952.

The Estimation of Oil Reserves

Published in Petroleum Transactions, AIME, Volume 52, 1916, pages 645–648. At present it is impossible to estimate closely the amount of oil obtainable from a given area of land. However, after the completion of a few properly distributed prospect wells, one can calculate the approximate yield of the sands penetrated, with a probable error of say 50 per cent. Even rough predictions of this kind are of value in large operations. Without wells upon it, one can never be absolutely certain that an area will produce any oil whatever, and one can only indulge in wild guesses of the probable productive area, before the geological structure has been carefully contoured and the top of the basal water plotted on a map. This requires wells. At times it is desirable to form an idea of the possible yield of oil in advance of drilling, as in cases where the price asked for undeveloped land seems too high, but where the probability of finding oil is furnished by neighboring development, supported by the geology. In such cases the most one can do is to make an estimate of possible maximum yield, which may of course far exceed results, and which is of use mainly in the prevention of excessive initial investment. The method is very significant in a general way, as in regions like the Bighorn Basin, Wyoming where the productive sands in the Cretaceous shale are so few and so think and fine that they cannot develop very great production, although the high quality of the oil probably will counterbalance this defect sufficiently to give local profit in favorable areas. Reservoir Capacity of Sands - The porosity of a stratum is the measure of its maximum reservoir capacity for liquids and gases. The porosity may be determined experimentally and must be used in connection with the total volume of the sand. T.P. 051–45