This is the first academic study of well costs and drilling times for Australia???s petroleum producing basins, both onshore and offshore. I analyse a substantial database of well times and costs sourced from government databases, industry and over 400 recent well completion reports. Three well phases are studied - Pre-Spud, Drilling and Completion. Relationships between well cost factors are considered, including phase time, phase cost, daily cost, rig day rate, well depth, basin, rig type, water depth, well direction, well objective (e.g. exploration), and type of completion (P&A or producer). Times and costs are analysed using scatter plots, frequency distributions, correlation and regression analyses. Drilling times are analysed for the period 1980 to 2004. Well time and variability in well time tend to increase exponentially with well depth. Technical Limits are defined for both onshore and offshore drilling times to indicate best performance. Well costs are analysed for the period 1996 to 2004. Well costs were relatively stable for this period. Long term increases in daily costs were offset to some extent by reductions in drilling times. Onshore regions studied include the Cooper/Eromanga, Surat/Bowen, Otway and Perth Basins. Offshore regions studied include the Carnarvon Basin shallow and deepwater, the Timor Sea and Victorian Basins. Correlations between regional well cost and well depth are usually high. Well costs are estimated based on well location, well depth, daily costs and type of completion. In 2003, the cost of exploration wells in Australia ranged from A$100,000 for shallow coal seam gas wells in the Surat/Bowen Basins to over A$50 million for the deepwater well Gnarlyknots-1 in the Great Australian Bight. Future well costs are expected to be substantially higher for some regions. This study proposes methods to index historical daily costs to future rig day rates as a means for estimating future well costs. Regional well cost models are particularly useful for the economic evaluation of CO2 storage sites which will require substantial numbers of petroleum-type wells.

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This is the first academic study of well costs and drilling times for Australia???s petroleum producing basins, both onshore and offshore. I analyse a substantial database of well times and costs sourced from government databases, industry and over 400 recent well completion reports. Three well phases are studied - Pre-Spud, Drilling and Completion. Relationships between well cost factors are considered, including phase time, phase cost, daily cost, rig day rate, well depth, basin, rig type, water depth, well direction, well objective (e.g. exploration), and type of completion (P&A or producer). Times and costs are analysed using scatter plots, frequency distributions, correlation and regression analyses. Drilling times are analysed for the period 1980 to 2004. Well time and variability in well time tend to increase exponentially with well depth. Technical Limits are defined for both onshore and offshore drilling times to indicate best performance. Well costs are analysed for the period 1996 to 2004. Well costs were relatively stable for this period. Long term increases in daily costs were offset to some extent by reductions in drilling times. Onshore regions studied include the Cooper/Eromanga, Surat/Bowen, Otway and Perth Basins. Offshore regions studied include the Carnarvon Basin shallow and deepwater, the Timor Sea and Victorian Basins. Correlations between regional well cost and well depth are usually high. Well costs are estimated based on well location, well depth, daily costs and type of completion. In 2003, the cost of exploration wells in Australia ranged from A$100,000 for shallow coal seam gas wells in the Surat/Bowen Basins to over A$50 million for the deepwater well Gnarlyknots-1 in the Great Australian Bight. Future well costs are expected to be substantially higher for some regions. This study proposes methods to index historical daily costs to future rig day rates as a means for estimating future well costs. Regional well cost models are particularly useful for the economic evaluation of CO2 storage sites which will require substantial numbers of petroleum-type wells.

Thesis (Ph. D.)--University of Texas at Austin, 2008. / Vita. Includes bibliographical references and index.

Thesis (M.S.)--King Fahd University of Petroleum and Minerals, 1989. / Title from document title page. Includes bibliographical references. Available in PDF format via the World Wide Web.

Thesis (M.S.)--Wildlife and Fisheries Sciences Dept., South Dakota State University, 2009. / Includes bibliographical references (leaves 91-100). Also available via the World Wide Web.

Thesis (Ph. D.)--University of Texas at Austin, 2005. / Vita. Includes bibliographical references.

Thesis (M.A.)--University of Delaware, 2005. / Principal faculty advisor: Nancy Signorielli, Dept. of Communication. Includes bibliographical references.

This thesis explores two themes on upstream oil and gas economics centred on offshore safety economics and third party access to infrastructure in the United Kingdom Continental Shelf (UKCS). The first part involves work that explores the nexus between the offshore safety regime and safety outcomes. It contributes to the literature by explaining the post-Piper Alpha safety regime changes with regard to our understanding, framing of safety decision making and benchmarking of safety outcomes. The second part investigates third party access to infrastructure issues in the UKCS. It contributes to our understanding of how different third party access to infrastructure arrangements can be utilised to maximise economic recovery. Each chapter addresses fundamental issues of North Sea oil and gas operations through the application of microeconomic, operations research and econometric methods within a formal analytical framework. The results provide insights into decision-making complexities in the upstream oil and gas industry by guiding policy makers. Specifically, part one of this thesis looks at safety performance in the post-Piper Alpha era in the UKCS. It investigates ways through which a more comprehensive and theoretically informed framework can be used to understand the linkages that arise when dealing with safety regulations and their impacts on the offshore oil and gas industry. Our objective is to empirically ascertain the determinants of offshore hydrocarbon releases within the context of the post-Piper Alpha offshore safety regime regulations. This is done using an observed number of hydrocarbon releases linked to a population denominator data of the number of the installations present in the UKCS. Three research problems are examined: (1) the transmission mechanisms through which safety regulation influence firm and industry productivity; (2) the assessment methods utilised in measuring and benchmarking regulatory outcomes in terms of safety compliance; and (3) the extent to which safety policies contribute to enhancing safety levels in the oil and gas industry. We initially review the background and literature on offshore safety with a particular emphasis on the UKCS in Chapter 2. We also frame our research questions and underlying hypothesis here. In Chapter 3, we present our underlying empirical framework and model specifications followed by some descriptive analysis of the hydrocarbon releases data. The results of the various econometric model specifications are analysed in Chapter 4. The second part of the thesis explores how possible different ownership patterns (including access arrangements) might affect the economic viability of exploiting remaining resources in the UKCS. This section attempts to answer two critical questions namely how the impact of the separation of infrastructure and field ownership affect economic recovery and the impact of taxation on field and hub economics in a mature oil basin. We explore how possible different ownership structures and access arrangements might affect the economic viability of remaining UKCS reserves. We apply a mixed integer programming (MIP) model to field data from the Northern North Sea. Specifically, we examine how the unbundling of infrastructure and field ownership, as well as different cost sharing and tariff arrangements, affect the long-term economics of hubs and their user fields. Regarding the layout, Chapter 5 talks about access to infrastructure issues in the UKCS namely the regulatory framework for access and related legislation. It leads to the development of a conceptual framework and model based upon which extractions are made to capture the various potential market outcomes. In Chapter 6, the empirical model, which utilises the mixed integer programming approach, is discussed. The data sources and characterization, as well as the presentation of the results from the Baseline Model, are presented in Chapter 7. The analysis of the Tax Model and the Cost Sharing plus Tax Model including structure and simulated results with underlying assumptions are presented in Chapter 8. Finally, Chapter 9 leads to a thorough discussion of the results followed by conclusions and policy recommendations.

Orientador: Paulo Roberto Ribeiro / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica, Instituto de Geociencias / Made available in DSpace on 2018-08-12T20:48:00Z (GMT). No. of bitstreams: 1 Atolini_TarcilaMantovan_M.pdf: 2488021 bytes, checksum: c3cbe83ac1e08cbfdb561f27e085ffcc (MD5) Previous issue date: 2008 / Resumo: Um dos avanços referentes ao desenvolvimento de tecnologias para perfuração de poços em condições severas de pressão e temperatura está ligado aos fluidos de perfuração. O entendimento do comportamento da mistura de fluido de perfuração e gás da formação, numa situação de influxo de gás da formação para o poço (kick), é essencial para as operações de controle de poço. Especialmente quando se utilizam fluidos orgânicos, os quais dificultam a detecção do influxo. O principal objetivo do presente trabalho é o estudo do comportamento termodinâmico desses fluidos a condições compatíveis com as de fundo de poços de alta temperatura e alta pressão (ATAP). Para atingir esta meta utilizou-se uma célula PVT com limite operacional de 200°C e 100MPa. Primeiramente estudou-se o sistema metano/nparafina nas composições de 0 a 95% em fração molar de metano e nas temperaturas de 70°C a 130°C. Numa segunda fase do trabalho foi estudado o sistema metano/emulsão com duas composições de emulsões, uma 60% n-parafina e outra 70%, variando-se também fração de gás e temperatura. Através dos dados experimentais do sistema metano/n-parafina realizou-se modelagem computacional para o cálculo da solubilidade, densidade e fator volume de formação, obtendo-se correlações que permitiram avaliar projeções baseadas na hipótese da aditividade. Para o cálculo direto dessas propriedades obtiveram-se correlações para o sistema metano/emulsões, as quais foram empregadas em cálculos de volume ganho no tanque como exemplo de sua aplicabilidade / Abstract: One of the advances in the development of drilling technologies under severe conditions of pressure and temperature is related to the drilling fluids. The understanding of the behavior of drilling fluid and the formation gas mixture, in a kick situation, is essential for the well control operations. Especially when organic fluids are used, which makes it more difficult to detect the influx of gas from the formation into the well. The main objective of this work was the study of the PVT behavior of these fluids at pressures and temperatures consistent with the HTHP well conditions. In order to accomplish that, a PVT cell with an operational limit of 200°C and 100MPa was used. First the system methane/n-paraffin was studied, with compositions from 0 to 95% in molar fraction of methane and at temperatures from 70 to 130°C. In a second phase of this work the system methane/emulsion was studied, for two different emulsions, one with 60% n-paraffin and another with 70%, also varying gas fraction and temperature. Through the experimental data of the methane/n-paraffin system a computational modeling was conducted to calculate solubility, density and formation volume factor, resulting in correlations that enabled the evaluation of the validity of the additivity hypothesis. For the entire experimental parameters spam, mathematical adjustments of the methane/emulsion system were done. This correlations were used in pit gain calculations as an example of its applicability / Mestrado / Explotação / Mestre em Ciências e Engenharia de Petróleo