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Weijermars R.,Texas A&M University | Weijermars R.,Technical University of Delft | Van Harmelen A.,Alboran Energy Strategy Consultants | Van Harmelen A.,Technical University of Delft
Geophysical Journal International | Year: 2014

Reaching sub-salt hydrocarbon targets in the deeper part of the Gulf of Mexico requires drilling through a salt canopy. The suture zones in the salt canopy are potential drilling hazards due to anomalous pressure behaviour of entrapped sediments. The Pólya vector field of coalescing salt sheets inside the canopy is used to explain suture formation and distinguish between upright and inclined suture contacts. Our analytical models, based on complex potentials, provide exact solutions for multiple source flows as they compete for space when spreading into the viscous continuum of the salt canopy. The velocity gradient tensor yields the strain rate tensor, which is used to map the principal strain rate magnitude inside the canopy. Quantification of one of the principal strain rates is sufficient because the plane deformation assumption ensures the two principal strain rates are equal in magnitude (but of opposite sign); the third principal dimension can have neither strain nor deviatoric stress. Visualization of the locations where the principal stress vanishes or peaks (with highs and lows) is useful for pre-drilling plans because such peaks must be avoided and the stress-free locations provide the safer drilling sites. A case study-of the Walker Ridge region-demonstrates the practical application of our new method. © The Authors 2015. Published by Oxford University Press on behalf of The Royal Astronomical Society. Source

Weijermars R.,Alboran Energy Strategy Consultants | Weijermars R.,Technical University of Delft | Watson S.,Ashridge Business School
SPE Economics and Management | Year: 2011

Stock-listed independents have played a leading role in the development of unconventional natural-gas resources in the United States and Canada. Shareholders have provided up to 57% of the total capital tied up in a representative panel comprising the 20 leading US and Canadian operators. The accumulated equity-financed capital also provided the collateral for the complementary 43% debt financing. Prudent management of shareholder value in unconventional-gas businesses is therefore essential for ensuring security of gas supply, not only in North America, but also in other countries with emergent unconventional gas plays. This study analyzes and benchmarks the working capital cycles in unconventional-gas companies. The working capital and cashflow cycles are compared with those of diversified oil and gas majors. The ability to accumulate retained earnings is generally much lower for unconventional-gas producers than for integrated majors. Unconventional-gas producers tend to grow their share capital by new issues and not from economic value added by profit from business operations. Although little or no asset value is built from economic profit, shareholder returns may still grow for unconventional-gas companies as long as investor expectations remain positive about future earnings. In contrast, shareholder returns in conventional-gas companies come from genuine economic value added in profitable business operations. The root cause of the weakness or absence of operational profits in unconventional-gas operations is a combination of low gas prices and well flow rates that are too modest to pay for the total cost of the unconventional-gas production. The operating margins for unconventional-gas companies are either close to zero or negative, but not for the integrated oil and gas majors, which have impressive cash margins even at globally suppressed gas prices. The benchmarks provided here help one to understand which parameters impact the financial performance of unconventional-natural-gas companies most significantly. Recommendations are formulated to avoid the destruction of shareholder value, and to instead maximize total shareholder returns (TSRs). Copyright © 2011 Society of Petroleum Engineers. Source

Weijermars R.,Alboran Energy Strategy Consultants | Weijermars R.,Technical University of Delft
Applied Energy | Year: 2014

This study models the uncertainty range in the future gas production output from US shale plays up to 2025. The future spread in gas output in our models follows from variations in the number of wells that will be drilled according to three distinct scenarios. Each scenario assumes a well development plan for the six major shale plays over the studied period and then quantifies the cumulative US production output from the combined shale plays. We compare the bottom-up model results with other model projections for future US shale gas output, including the top-down shale gas production forecasts by the US National Energy Modeling System (NEMS). The remarkable growth of North American gas output from unconventional resources has been highlighted in numerous industry reports and government publications, but what has remained relatively underexposed is the deterioration of economic margins due to the failure to predict the gas price decline in the North American market. The past development record of North America's shale gas resources suggests that security of future gas supplies seems ensured, but here we develop a contrarian view. Our scenario models take into account the effect of recent declines in gas rig counts and decline in gas well completions due to the depressed gas prices. A scenario with declining shale gas output - one of three scenarios considered - cannot be excluded as being unlikely to occur, which means the future security of US gas supply that assumes a steady growth of shale gas supply cannot be ascertained at present. © 2014 Elsevier Ltd. Source

McCredie C.,Alboran Energy Strategy Consultants | Weijermars R.,Alboran Energy Strategy Consultants | Weijermars R.,Technical University of Delft
Petroleum Review | Year: 2011

The EUs diminishing gas reserves must be replaced by gas importation. Pipeline imports from Russia, North Africa and at least 200 billion cu/yr of LNG imports could fill the emerging demand-supply gap. Russia plans to increase its gas deliveries to Europe to 200 billion cu/yr by 2030. Building new long-distance gas pipelines, primarily to supply oil-indexed gas from Russia, raises the question as to whether that expensive gas will not again be displaced in the future by cheaper LNG supplies from elsewhere. Meanwhile, the EU thinks the Nabucco pipeline can provide leverage on Russia and Gazprom, but the gas for Nabucco would need to come from former Soviet states in central Asia. The major prospective supplier, Turkmenistan, will remain under Russian patronage as long as Russia uses Gazproms pipeline "diplomacy" to keep Turkmenistan gas flowing via the Brotherhood pipeline to Ukraine and western Europe. For Europe, even the planned increase of LNG imports to 200 billion cu m/yr by 2030 may not be easy to achieve. The worlds LNG receiving capacity is three times greater than LNG supply train capacity. This means Europe may face stiff competition in securing the 200 billion cu m/yr LNG imports required by 2030. Source

Weijermars R.,University of Texas at Austin | Weijermars R.,Technical University of Delft | Jackson M.P.A.,University of Texas at Austin | van Harmelen A.,Alboran Energy Strategy Consultants | van Harmelen A.,Technical University of Delft
Geophysical Journal International | Year: 2013

Safe exploration and production of pre-salt (or subsalt) hydrocarbons require that drilling operations be optimized. We introduce analytical models of wellbore closure, accounting for variations in both the wellbore net pressure and far-field flow rate of an autochthonous or allochthonous salt sheet penetrated by the wellbore. We demonstrate how closure rates of such a wellbore evolve for increasingly stronger Rankine flow. For high viscosity salt (̃1018 Pa s) the wellbore closes by a pure sink flow without any Rankine shift from its vertical trajectory path. For low viscosity salt (̃1016 Pa s) Rankine flow dominates.Wellbore closure in salt sheets may vary within the same wellbore due to differential tectonic creep rates at different depths. Mitigation of wellbore closure by, for example, reaming, jarring, brine solution and thermal control, is most effective if spatial variation in closure rates is understood and quantified. Evaluation of wellbore closure rates due to salt creep should be customarily included in wellbore stability analyses before drilling and during well monitoring. © The Authors 2013. Published by Oxford University Press on behalf of The Royal Astronomical Society. Source

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