Peak In Oil Production Research Articles

Evolution and generation mechanism of retained oil in lacustrine shales: A combined ReaxFF-MD and pyrolysis simulation perspective

To accurately investigate the evolution characteristics and generation mechanism of retained oil, the study analyzed organic-rich lacustrine shale samples from the Paleogene Kongdian Formation in Cangdong Sag, Bohai Bay Basin. This analysis involves Rock-Eval pyrolysis, pyrolysis simulation experiments, Gas Chromatograph Mass Spectrometer (GC–MS), and reactive molecular dynamics simulations (ReaxFF). The results revealed the retained oil primarily consisted of n-alkanes with carbon numbers ranging from C14 to C36. The generation of retained oil occurred through three stages. A slow growth stage of production rate was observed before reaching the peak of oil production in Stage I. Stage II involved a rapid increase in oil retention, with C12–C17 and C24–C32 serving as the primary components, increasing continuously during the pyrolysis process. The generation process involved the cleavage of weak bonds, including bridging bonds (hydroxyl, oxy, peroxy, imino, amino, and nitro), ether bonds, and acid amides in the first stage (Ro =0.50%–0.75%). The carbon chains in aromatic ring structures with heteroatomic functional groups breaks in the second stage (Ro =0.75%–1.20%). In the third stage (Ro =1.20%–2.50%), the ring structures underwent ring-opening reactions to synthesize iso-short-chain olefins and radicals, while further breakdown of aliphatic chains occurred. By coupling pyrolysis simulation experiments and molecular simulation technology, the evolution characteristics and bond breaking mechanism of retained oil in three stages were revealed, providing a reference for the formation and evolution mechanism of retained oil.

A systematic comparison of solvents and their concentrations in bitumen gravity drainage under controlled thermodynamic conditions

Solvent-assisted SAGD (SA-SAGD) has been studied as an alternative to improve the efficiency of SAGD. This paper reports a new set of experimental data for SA-SAGD and analyzes the characteristics of bitumen-solvent mixing in the experiments using history-matched numerical models. The dimensions of the sand pack were 3 in. in diameter and 15 in. in length, and the sand pack was contained in a 25-L cylindrical pressure vessel. An annular void space surrounded the sand pack with a gap thickness of 1 in., within which a steady state flow of the injected vapor phase maintained the controlled pressure, temperature, and composition. Therefore, the gravity drainage in the sand pack occurred at a set of specified thermodynamic conditions for the surrounding annular steam chamber, unlike transient conditions near the edge of a steam chamber in larger-scale steam injection processes. In addition to SAGD as the base case, five sets of SA-SAGD were performed: 20 mol% C4, 40 mol% C4, 10 mol% C8, 20 mol% C8, and 10 mol% condensate coinjected with steam at 3500 kPa.The peak oil production rate was 9.84 cm3/min with SAGD, 14.61 cm3/min with 20 mol% C4-SAGD, 16.34 cm3/min with 40 mol% C4-SAGD, 31.33 cm3/min with 10 mol% C8-SAGD, 12.36 cm3/min with 20 mol% C8-SAGD, and 12.33 cm3/min with 10 mol% condensate-SAGD. SAGD was the least effective in bitumen gravity drainage, while the 10 mol% C8-SAGD was the most effective. Increasing the C4 molar concentration from 20 to 40 mol% slightly increased the peak rate; however, the peak rate in C8-SAGD significantly was decreased by increasing the C8 concentration from 10 to 20 mol%. This counter-intuitive result was reported in a few simulation studies with heavy solvents (e.g., C7 and C12) in the literature, but had not been experimentally confirmed before this research.Although the condensate contained 93 mol% C7-like pseudo component (C7, eq), the peak rate of 10 mol% condensate-SAGD was much smaller than that of 10 mol% C8-SAGD. These experimental observations highlight the practical importance of understanding the sensitivity of bitumen gravity drainage to heavy-solvent concentrations near the edge of a steam chamber in SA-SAGD.

Model Development for Micellar/ Polymer Flooding Process

Flow of hydrocarbon from the reservoir is a function of pressure differential provided by natural reservoir energy at initial stage of production. The pressure declines over time with a corresponding reduction in production rate. To salvage for this, polymer/micellar flooding a chemical method deployed to enhance the recovery of oil from the reservoir. The key point here is to improve overall sweep efficiency. In this work, the reservoir was produced using a polymer injection well and analysis were made using a time step of 1 day over 100 days of production period. Simulation using Eclipse 100 result shows that similar cells in terms of relative permeability reduces with increasing polymer concentration and relative distance from the injector. The field performance in this work was analyzed in terms of production rate, field pressure, and saturation. Peak pressure value of 4470Psia was reached at the day 75 with peak oil production rate of 205STB/Day at day 68 with a continuous decline in oil saturation. Sensitivity study was performed in terms of polymer adsorption/injection rate in relation to time, polymer injection rate/oil production rate against time, fluid oil rate/field pressure against time. The overall result shows that the polymer adsorption weakens the interfacial tension of the in-situ of oil phase.

A numerical simulation investigation on low permeability reservoirs air flooding: Oxidation reaction models and factors

A precise oxidation reaction model determines the reliability of numerical simulation results and the prediction of field performance of air injection-based enhanced oil recovery (EOR). By reviewing the classical oxidation reaction model and combining with geological characteristics of a low permeability reservoir, this work creatively divides pseudo-components and temperature regions and further proposes the improved low temperature oxidation (LTO), middle temperature oxidation (MTO), and high temperature oxidation (HTO) numerical models with chemical reaction coefficients. The EOR effects of reservoir temperature, permeability, air flow rate and bottom hole pressure during LTO and full temperature regions are determined on the basis of a 3D reservoir simulation model via CMG STARS. The results show that peak oil production rates of N2 flooding and LTO are 17.70 and 29.97 m3/d, respectively. The cumulative oil production in LTO stage is about 35%, which is higher than that in N2 flooding. The oxygen addition reaction in LTO stage can release much heat and increase sweep efficiency from thermal expansion and viscosity reduction. The peak oil production rates of LTO and full temperature oxidation (FTO) reactions are 42.16 and 44.34 m3/d, respectively, and the cumulative oil production of the FTO model was about 17% higher than that of LTO. The FTO model could more truly reflect the production performance during air flooding of low permeability oil reservoir. Strong oxygen consumption capacity and significant heat release effects can be observed under higher initial temperature, permeability, air flow rate, and lower bottom hole pressure. Thermal flooding and flue gas flooding are the main EOR mechanisms in FTO process. Considering the inescapable field problem of gas channeling, thorough contact between oil and air can be promoted by artificially preheating oil reservoir and adjusting air injection rate and pressure. Thus, oil recovery can be further improved under the premise of ensuring the safety of field application of air flooding technique.

Numerical Investigation of a Novel Bottom-Up Assisted Pressure Drive Process in Oil Sands Reservoirs with Shale Barriers

Steam-assisted gravity drainage (SAGD) is widely applied to recover bitumen and heavy oil resources. Reservoir heterogeneity, especially the presence of shale barriers, continues to challenge the performance of SAGD. A novel enhanced oil recovery process, bottom-up assisted pressure drive, is proposed to improve the oil production in the reservoirs with shale barriers. In this work, numerical simulation is applied to investigate the feasibility of a bottom-up assisted pressure drive process. A reservoir model with typical oil sand reservoir properties is developed considering shale barriers. The performance of bottom-up assisted pressure drive and SAGD is compared under the same reservoir conditions, including steam chamber development, oil production rate, cumulative oil production, and the pressure difference between injector and production. The inherent mechanisms associated with the bottom-up assisted pressure drive are also well understood and confirmed. In the bottom-up assisted pressure drive, a flat steam chamber is developed from the bottom of the reservoir in the early stage of the process and grows upward with the injection of steam. The large volume of the steam chamber and the huge contact area between steam and bitumen contribute to a high oil production rate. The peak oil production rate in the bottom-up assisted pressure drive is approximately three times that in the SAGD process. The cumulative oil production in the bottom-up assisted pressure drive is 20% higher than that in the SAGD process. The effect of shale barriers on bottom-up assisted pressure drive is less, indicating one advantage of this novel process over SAGD in oil sands reservoirs with shale barriers. The pressure difference in the bottom-up assisted pressure drive is greater than that in the SAGD process. The pressure drive is another mechanism for improving oil production. The calculated net present value (NPV) in the bottom-up assisted pressure drive process is 27% higher than that in the SAGD process. This is mainly attributed to the high oil production rate in the early stage of the process and high cumulative oil production. The simulation study in this work provides technical support for the future field applications of this novel recovery process.

Hydrocarbon accumulation mechanism in the far-source reservoirs of Dongsha Uplift of the Pearl River Mouth Basin, northern South China Sea

There are a lot of exploration examples of far-source reservoirs, but the description of the connotation and accumulation mechanism is very rare. The Dongsha Uplift is one of the major oil-producing areas in the eastern Pearl River Mouth Basin in the northern South China Sea. The uplift lacks generally hydrocarbon source rock and is far from the generative kitchen, making it a typical far-source oil and gas reservoir. The accumulation mechanism of crude oil in the reservoirs are still unknown. By systematically comparing biomarkers, nitrogenous compounds and isotopic characteristics of the crude oil and source rocks with those in the neighboring depressions, and combining with fracture, sand body, unconformity migration conduits and barrier conditions, this paper simulates oil and gas migration paths and formation time with Pathway and IES software, and analyzes oil and gas accumulation process from a dynamic perspective. We found that the deep lacustrine hydrocarbon source rocks of the Wenchang Formation in the H26 Sag of the Huizhou Depression reached peak oil production at the end of the Hanjiang Formation deposition. Influenced by the strong tectonic activities at the final deposition of the Hanjiang and Yuehai formations, two episodes of hydrocarbon charging occurred at the top of the Dongsha Uplift. The accumulation of hydrocarbons far from the source rocks in the Dongsha uplift is mainly controlled by the efficient carrier system at hydrocarbon generation period. The oil is mainly accumulated in L4-1 and L11-1 oil fields through the long-distance stepped migration mode. The spatial and temporal relationship between hydrocarbon generation of source rock and episode of fault activity are mainly responsible for accumulation in the far-source reservoirs of the Dongsha Uplift.

E&P Notes (October 2022)

E&P Notes (October 2022)

The Adverse Impact of Muddy Laminae on Conventional SAGD Performance and Improvement Strategy with the Multilateral Well Pattern

With further progress of Steam-Assisted Gravity Drainage (SAGD) technology, a growing number of oil sands or heavy oil reservoirs were put into production in an efficient way. However, owing to the existence of muddy laminae within reservoirs, there are challenges associated with the expansion of the steam chamber and oil drainage during the SAGD process. The purpose of this study is to evaluate the adverse impact of muddy laminae on conventional SAGD performance and introduce an improvement strategy with multilateral well patterns to reduce the adverse impact and improve the performance. In the research reported here, the reservoir numerical simulation approach is applied to conduct the research. The analysis conducted on a prototypical reservoir reveals that the steam chamber may expand slowly in some sections due to the poor capacity of heat and mass transfer, and the expansion of the steam chamber is relatively uneven along the wellbore, when the muddy laminae are existing in the formation. The influence level of the muddy laminae on conventional SAGD performance under different distribution modes is different, but the adverse effect is mainly reflected in the delay of peak oil production, the decrease in peak oil production, the decrease in steam chamber volume, and the increase in the cumulative steam oil ratio (mainly in early and middle stages of the SAGD process). On the basis of aforementioned researches, the improvement strategy with two different multilateral well patterns, planar multilateral well and upward multilateral well, is introduced to improve the SAGD performance. The results indicate that the combination of a planar multilateral injector and planar multilateral producer has the best performance. By adopting such kind of combination, the recovery factor can be increased from 31.36% to 47.08%, and the cumulative steam oil ratio can be decreased from 5.29 m3/m3 to 4.64 m3/m3 under the combined distribution mode of muddy laminae. It can be known that the branches of the planar multilateral well are very helpful for the expansion of the steam chamber and oil drainage, once the heat connection between branches of the injector and producer is well established. Overall results show that the multilateral well pattern is promising for SAGD applications at oil sands or heavy oil reservoirs which are rich in muddy laminae.

The Pelican Field, Block 211/26a, UK North Sea

Abstract The Pelican Field lies in the East Shetland Basin, in Block 211/26, roughly 150 km NE of the Shetland Islands. It was discovered in 1975 by exploration well 211/26-4. Development was delayed until 1995 when economic development became feasible as a subsea tie back to the Cormorant Alpha Platform. The reservoir is the Middle Jurassic Brent Group, comprising sands deposited in a fluvio-deltaic, shallow-marine, wave-dominated system. The reservoir interval has an average thickness of around 300 ft, ranging from 220 ft on the crest to 400 ft in down-flank areas. The crest of the field lies at around 10 500 ft true vertical depth subsea. Current estimate of oil in place for the field is c. 500 MMbbl. The Pelican Field suffers from significant deterioration of reservoir properties with depth, leading to low recovery factors of 15–20%. To date, 21 production and injection wells have been drilled recovering a total of 76 MMbbl. Oil production started in 1996 and peak oil production was achieved at 50 000 bopd in the same year. Rates declined due to water-cut development in most of the wells and current production rates are around 2000 bopd.

A new comprehensive model to estimate the steam chamber expansion and recovery performance of entire SAGD process

Steam-Assisted gravity drainage (SAGD) technique has been successfully applied to unlock the oilsands resources in Canada. But to accurately estimate the steam chamber expansion and productivity of the entire lifetime of a SAGD well pair is still challenging. In this paper, a new comprehensive model is proposed encompassing the different stages of SAGD. Firstly, for the rising stage, based on the theory of volumetric displacement, an analytical model is developed for the rise speed and oil rate. Thereafter, based on Butler's theory, a 2D numerical approach is modelled for predicting the lateral spreading and confinement stage of steam chamber. Thus, combining the two different mathematical models, the steam chamber shape and recovery performance of a SAGD process can be calculated. The calculation results are also compared against 3D experimental results and field data to confirm the accuracy of this model. Then, a sensitivity analysis is performed to discuss the effects of operation parameters on steam chamber expansion and recovery performance of SAGD process. Results indicate that the calculated results can match the experiment results and field date very well. The calculated peak oil production rate causes a large error and the plateau time of SAGD process obviously is shortened if the preheating stage is neglected. A higher steam chamber pressure results in a narrower inverted triangle interface shape in the rising stage and a more concave-like interface in the sideways expansion stage. In addition, the oil rate increases with steam chamber pressure allowing for varying steam injection rate, whereas the increasing trend of ultimate recovery decreases with the steam chamber pressure increases, which indicates that a proper steam chamber pressure to be chosen can not only achieve a preferable ultimate recovery but also benefit for project economics.

Potential of Denver Basin oil fields to store CO2 and produce Bio-CO2-EOR oil

The capacity of the Denver Basin to store CO2 in hydrocarbon reservoirs was analyzed using two techniques. The first approach employed by the Southwest Carbon Partnership assumes CO2 is injected into depleted hydrocarbon reservoirs but no fluids are withdrawn. The second method analyzes the storage capacity of the Denver Basin assuming CO2 is injected until the pressure in each oil reservoir reaches the hydrostatic gradient, and CO2 then continues to be injected into the oil reservoirs in order to recover additional oil, until the incremental oil recovery would no longer be commercially viable. The amount of CO2 sequestered in the 30 oil fields studied was found to be 160 Mt with the first method but only 50 to 70 Mt using the second method. If the CO2 source is fermentation emissions available from corn ethanol plants in Nebraska, and the produced bio-CO2-EOR oil is refined into gasoline that is consumed in Colorado, then the CO2 sequestration project described in this paper could reduce the GHG emissions from the transportation sector in Colorado by 10% during peak oil production from the project.

Иран на мировом рынке нефти

Iran is the fourth world largest holder of proved oil reserves, extraction costs of Iranian oil are comparatively low. Oil production dynamics in the country is sharply cyclical and these cycles are generated by political factors, exogenous to the oil sector. Peak in oil production was achieved in 1974 and for the last forty years Iran’s share in the world oil production is declining. The article reveals that among powerful exogenous shocks negatively affecting the dynamics of oil production in Iran there were unilateral and multilateral sanctions. The first sanctions against Iran were introduced by the USA in 1979. Since the middle of the 1990-ies sanctions have become a system. The long-term negative effects of sanctions substantially exceed the short-term ones. Largely due to the sanctions the technological level of Iranian oil sector remains very low. Global energy companies and banks prefer to reject interactions with Iranian counterparties due to the expanding practice of the extraterritorial regime of US sanctions that has transformed Iranian hydrocarbons into a “toxic asset”. Asia-Pacific countries, preserving oil import from Iran under the sanctions regime, got an opportunity to set very favorable for them terms of contracts. Iranian oil is bought with a price discount, for partially convertible and/or unconvertible currencies, often in exchange for a counter barter supply of goods. Expectations that non-Western oil companies would substitute for European investments have failed so far. Given the accelerating global race for monetization of hydrocarbon reserves and risk of forthcoming peak in global demand for oil there is a growing probability that a substantial part of commercially competitive Iranian oil reserves will remain in the ground.&nbsp

A critique of Hubbert’s model for peak oil

In 1956, Shell Oil Company geologist M. King Hubbert published a model for the growth and decline over time of the production rates of oil extracted from the land mass of the continental US. Employing an estimate for the amount of ultimately recoverable oil and a logistic curve for the oil production rate, he accurately predicted a peak in US oil production for 1970. His arguments and the success of his prediction have been much celebrated, and the original paper has 1400 publication citations to date. The theory of “peak oil” (and subsequently, of natural resource scarcity in general) has consequently become associated with Hubbert and “Hubbert” curves and models. However, his prediction for the timing of a world peak oil production rate and the subsequent predictions of many others have proven inaccurate. We revisit the Hubbert model for oil extraction and provide an analysis of it and several variants in the language of (time) autonomous differential equations.

Experimental and numerical study of solvent optimization during horizontal-well solvent-enhanced steam flooding in thin heavy-oil reservoirs

As a major technique for enhancing heavy-oil recovery, steam flooding has been used successfully at large scales around the world. Long-term indoor experiments and field trials, however, have revealed problems, such as heat loss to the overburden and a limited steam zone for steam flooding in thin heavy-oil reservoirs, which severely limit the thermal efficiency of the steam and the economic benefits of the reservoirs. Therefore, we established a set of two-dimensional sandpack models to study the steam chamber expansion characteristics of the horizontal-well solvent-enhanced steam flooding (HW-SESF) of different solvents and its influence on production performance. We established a numerical model based on the experimental parameters to simulate the solvent migration in the steam chamber and its effect on temperature, viscosity, and oil saturation profile. The results demonstrate that, compared with steam flooding, the HW-SESF strategy can effectively reduce the oil viscosity both at the front and inside the steam chamber and improve the steam-injection capability (the stronger the steam-injection capability is, the easier the steam can be injected into the model) of the horizontal injection well, which enhances displacement efficiency and enlarges the swept area of the steam chamber. For HW-SESF of light solvents, the displacement efficiency at the low water-cut production was high, and water cut increased rapidly as the steam front reached the production well. For HW-SESF of medium solvents, the period of stabilized production was long, and the recovery ratio was the highest compared with other solvents. For HW-SESF of heavy solvents, the peak oil production rate was high, and the oil production rate dropped quickly. Therefore, the HW-SESF strategy reduced the heavy-oil viscosity more effectively than conventional steam flooding, and thus the zone of the steam chamber was enlarged and the recovery ratio enhanced. Compared with light and heavy solvents, medium solvents can achieve the best results for steam chamber optimization and the highest recovery ratio; thus, it is considered the most effective method to exploit thin heavy-oil reservoirs.

The Hubbert diffusion process: Estimation via simulated annealing and variable neighborhood search procedures—application to forecasting peak oil production

Accurately charting the progress of oil production is a problem of great current interest. Oil production is widely known to be cyclical: in any given system, after it reaches its peak, a decline will begin. With this in mind, Marion King Hubbert developed his peak theory in 1956 based on the bell‐shaped curve that bears his name. In the present work, we consider a stochastic model based on the theory of diffusion processes and associated with the Hubbert curve. The problem of the maximum likelihood estimation of the parameters for this process is also considered. Since a complex system of equations appears, with a solution that cannot be guaranteed by classical numerical procedures, we suggest the use of metaheuristic optimization algorithms such as simulated annealing and variable neighborhood search. Some strategies are suggested for bounding the space of solutions, and a description is provided for the application of the algorithms selected. In the case of the variable neighborhood search algorithm, a hybrid method is proposed in which it is combined with simulated annealing. In order to validate the theory developed here, we also carry out some studies based on simulated data and consider 2 real crude oil production scenarios from Norway and Kazakhstan.

Establishment of a multi-cycle generalized Weng model and its application in forecasts of global oil supply

Low oil prices under the influence of economic structure transformation and slow economic growth have hit the existing markets of traditional big oil suppliers and upgraded the conflict of oil production capacity and interest between OPEC producers and other big oil supplier countries such as the USA and Russia. Forecasting global oil production is significant for all countries for energy strategy planning, although many past forecasts have later been proved to be very seriously incorrect. In this paper, the original generalized Weng model is expanded to a multi-cycle generalized Weng model to better reflect the multi-cycle phenomena caused by political, economic and technological factors. This is used to forecast global oil production based on parameter selection from a large sample, depletion rate of remaining resources, constraints on oil reserves and cycle number determination. This research suggests that the world will reach its peak oil production in 2022, at about 4340 × 106 tonnes. China needs to plan for oil import diversity, a domestic oil production structure based on the supply pattern of large oil suppliers worldwide and the oil demand for China’s own development.

Implications for the floor price of oil of aggressive climate policies

This paper identifies combinations of technical and behavioral measures that lead to progressively lower global demand for oil, culminating with a scenario that eliminates global oil demand by 2060 – in line with the broader requirement that anthropogenic CO2 emissions reach net zero by this date in order to have a 60% chance of staying below a global mean warming of 2°C above the pre-industrial level. The cumulative oil consumption from 2010 to the point when zero oil demand is achieved is compared with a recent oil supply-marginal cost curve. Assuming that oil is consumed in order of increasing extraction cost, the price of oil need not rise significantly above $25–35/bbl. Even substantially less-aggressive efforts to reduce CO2 emissions need not see oil rise substantially above $50/bbl. Under aggressive climate policies, the peak in oil demand occurs before the supply-constrained peak in oil production would occur. This would render expensive oil (>$50/bbl) permanently uneconomic. This includes oil from the Canadian tar sands (currently costing $65–95/bbl for new greenfield developments) and most shale oil (with current average oil-play costs of $48–65/bbl). This in turn implies that governments should not be promoting or permitting development of high cost oil, and also provides a clear warning to private and institutional investors.

Comparison of Strong-Alkali and Weak-Alkali ASP-Flooding Field Tests in Daqing Oil Field

Summary Alkali/surfactant/polymer (ASP) flooding is one of the most-promising enhanced-oil-recovery (EOR) technologies. Strong alkali (NaOH) was used in early field tests mainly because of its stronger emulsification ability and wider surfactant range, which can meet the requirements of ultralow interfacial tension (IFT). However, subsequent field tests indicated that the advantages of a strong alkali did not outweigh the disadvantages caused by serious scaling and production-capacity loss. Although a critical comparison of strong alkali ASP (SASP) and weak alkali ASP (WASP) on the basis of field tests is quite difficult and complex, considering the small differences in reservoir characteristics, injected fluid, and operational changes, the two completed field tests in Daqing provided us with valuable and important information. The petrophysical features of the two field tests were similar. The well spacings and well patterns of the two field tests were critically the same, and the same screening standards and design ideas were followed. The incremental recoveries of WASP and SASP were nearly the same, while WASP had a higher peak oil production than SASP after the injection took effect. WASP was proved to have less liquid-producing-capacity loss than SASP. The emulsification effects of WASP were weaker than those of SASP, which also lowered the difficulty and cost of the treatment of the emulsified fluid. The chromatographic separation was different in the two pilot tests, in which WASP had alleviated chromatographic separation. Breakthrough of the polymer occurred before the alkali followed by the surfactant, and this occurred at 0.06 pore volumes (PV) for SASP but was delayed until 0.13 PV for the WASP flooding. The scaling of SASP was much-more severe than that of WASP, leading to a much-higher treatment cost. The economic performances of the two tests, which are of vital importance in a low-oil-price era, were quite different, and WASP had much-better performance than SASP. The input/output ratios of WASP in B-2-X and SASP in B-1-DD were 1:3.7 and 1:2.3, respectively. The returns on investment (ROIs) of WASP in B-2-X and SASP in B-1-DD were 19.1 and 12.9%, respectively, whereas the financial internal rates of return (FIRRs) after tax were 22.3 and 18.0%, respectively. The average FIRR of local oil-industry projects is 12%. Field tests indicated that WASP is both technically and economically better than SASP under the conditions in the Daqing oil field.

Prediction of Oil Depletion in Ghana Based on Hubbert's Model

This study seeks to fulfil four specific tasks: to predict the year of peak oil production in Ghana, to estimate the quantity that will be produced at this peak point, to investigate the year of total oil depletion and last but not the least is to assess the total recoverable oil resources at the point of depletion. The study applied Hubbert’s model of oil production and depletion. There was however modification to the approach in that Nonlinear Least Squares were used to estimate the logistic growth parameter instead of linear regression techniques. The modification was due to the fact that the historical data of oil production in Ghana did not follow a linear trend. The study acknowledges the influence of technology, economic, and political factors in the shorter time scales but hypothesizes that the amount of recoverable oil resources dominates all other factors in the long run. Hence the focus was placed on physical or geological constraints. The study results show that peak production in Ghana will occur in 2022. A maximum of about 100 million barrels will be produced per year though currently the annual production is about 40 million barrels. The predicted logistic curve also shows that total oil will be depleted by 2060. Ghana has total recoverable oil resources of about 1.8 billion. The data for the study was obtained from the U.S Energy Information Administration covers the period of production from 1992 to 2014.

Measuring regional resilience towards fossil fuel supply constraints. Adaptability and vulnerability in socio-ecological Transformations-the case of Austria

Resilience has become a prominent concept to understand system vulnerabilities and flexible ways of adapting to crises. Recently, it gained importance in discussions about the possible peak in oil production (peak oil) and its consequences, which might affect economic performance, social well-being and political stability, and thus also the energy transition to a low-carbon economy. The paper presents a new way of measuring resilience as absolute resilience related to a best practice-model of a resilient society. The resilience model is grounded in explicit theoretical assumptions. All indicators are justified by theoretical and empirical arguments. We present a case study of Austrian municipalities and broader-scale spatial types, which were defined according to their degree of urbanization. The mean resilience of Austrian municipalities is moderate, the difference between resilience values of municipalities is small. Significant differences between spatial types exist. Higher resilience is displayed by less urbanized types due to a higher share of agricultural activities and a more favorable level of GDP per capita. Austria has considerable latitude to improve resilience. Corresponding policies should target resilience components with the lowest values first. A sole focus on regionalization is not recommended. These conclusions are applicable to OECD countries in general.