Andersen, Niels (National Space Institute – DTU Space & Polar DTU) | Bekker, Pieter (University of Dundee and Steptoe & Johnson LLP) | Bishopp, David (Galp Energia) | Nassif, Toufic (Sonde Resources Corporation) | Nordentoft-Lauridsen, Sune (National Space Institute & Polar DTU) | van de Poll, Robert (Fugro N.V.)
This paper provides an overview of the history of global maritime boundary issues, mechanisms to resolve boundary disputes, and the economic potential that can be unlocked by coastal States through the exploitation of hydrocarbons trapped in areas currently unavailable for exploration and production operations.
Vast hydrocarbon reserves are tied up in areas, either underlying waters greater than 200 nm offshore or disputed by coastal States. In the former case technology in the form of deepwater drilling has made testing the potential feasible, whilst in the latter case many of the 311 or so areas in dispute are able to be tested and developed using conventional techniques.
Anything that appears to show a sovereign entity ceding control of land or sea to another country inevitably takes on a high profile in the countries concerned, which in the worst case can lead to armed conflict. It is a credit to those States that subscribe to the principles of the United Nations Charter and the United Nations Convention on the Law of the Sea ("UNCLOS") that they have reached agreement on how the economic potential trapped in disputed areas may be divided or shared.
High-profile, high-stakes disputes relating to offshore oil and gas deposits underscore the importance of the modern law of the sea, and international law generally, to the peaceful settlement of boundary disputes affecting the energy industry. Yet boundary disputes form an overlooked area of investment risk management in the energy sector.
This paper will introduce the technical and legal principles behind the solutions reached by States and will highlight some of the areas with the greatest hydrocarbon potential that have yet to be exploited as well as the areas of risk that require mitigation before investors will advance risk capital.
Schmidt, Andre (University of Massachusetts Dartmouth) | Brickley, Peter (Horizon Marine) | Gangopadhyay, Avijit (University of Massachusetts Dartmouth) | Cadwallader, Matthew L. (Horizon Marine) | Sharma, Neha (Horizon Marine) | Nobre, Carolina (Horizon Marine) | Coholan, Patrice D. (Horizon Marine) | Feeney, Jim
Southeast of the Trinidad-Venezuela region, the North Brazil Current (NBC) retroflects and forms about 5-8 rings annually. The ensemble of trajectories of rings extends offshore of the 500 m isobath, with a mean translation speed of approximately 14 km/day and a mean length scale of about 100 km (Goni and Johns, 2001, 2003). At least two distinct ring types exist: surface-intensified and thermocline-intensified, with differences evident in both azimuthal velocity and water masses. This paper presents a recent implementation of an operational modeling system for this region. The key to this modeling effort is to implement the feature oriented regional modeling methodology for the NBC rings with an advanced initialization scheme to incorporate the varying ring structure, shape, and associated currents made possible by regular surveillance and deployment of instruments into the ring. Multiple observations provide input and guidance to the ring initial conditions for the feature model system.
Based on previous studies and data, a water-mass based feature model system for two distinct NBC rings is developed. The parametric models for temperature and salinity are built to capture the main features observed in vertical structure of those rings. For example, in the case of the thermocline-intensified ring, different empirical-analytical functions with tunable parameters are used to represent (i) the thermocline shoaling up in the intermediate depth of the ring, (ii) the dipping down in the inshore and offshore edges, and (iii) the presence of the maximum salinity water at 50-100 m. These feature models are first calibrated with available sea surface temperature (SST) data and then melded with background climatology in a feature-oriented multiscale objective analysis to develop a three-dimensional description of the regional ocean.
The feature oriented scheme is used to initialize an operational forecasting system using the Harvard Ocean Prediction System (HOPS) framework. Implementation, calibration, and validation of this system were carried out for multiple case studies during 2006 and 2007 when a number of drifter data sets were available. A hindcast study for 27 January 2010 is used for verifying the forecast system in a semi-operational mode. A fully operational system was launched in July 2010.
A study was completed in early 2008 (IMVPA, 2008) for the US Minerals Management Service (MMS) with the objective to deliver an assessment of oil and gas technology that may be applied to cold regions of the United States Outer Continental Shelf (OCS). An overview of this study and its results are presented in this paper.
This study assessed the current state of offshore technology in arctic and sub-arctic regions. The results of this assessment were used to provide insight and guidance into existing/future exploration and development technologies that might be applied on the US OCS, in particular those areas in the Beaufort, Chukchi and Bering Seas.
The work covers exploration structures, bottom-founded and fixed production concepts, floating production concepts, terminals, pipelines and subsea facilities, and also touches on other technologies that might be relevant to Alaskan OCS exploration and development. Advances in harsh environment offshore exploration and production technology have made it economically and technically feasible for some projects to proceed in ice-covered waters, and additional projects may be possible in future.
This study drew on a review of current state-of-practice and state-of-the-art used in, or proposed for, arctic and sub-arctic offshore development areas. Assessments of exploration and production options were primarily based on technical feasibility. As appropriate, other aspects were also considered including
constructability, capital costs, environmental considerations, operations, maintenance and repair, abandonment and decommissioning.
We use borehole and laboratory measurements with a probe to obtain local permeability estimates. Under ideal conditions sufficiently far from the probe, the flow induced is hemispherical. We describe an experimental apparatus that can flow fluids through a probe under isotropic confining stresses and present an analysis to deduce the optimal dimensions of a finite cylindrical rock to simulate hemispherical flow like that in a semi-infinite medium. We derive equations for permeability interpretation of laboratory measurements.
We made pressure measurements on a number of synthetic and natural rocks as functions of confining stress, probe size, flow rate, and flow direction. For synthetic rocks, the calculated permeability shows little dependency on these factors. For natural media, however, flow direction appears to have a major effect at high rates that increases with decreasing probe size. On the basis of these data, we propose a fines-migration mechanism. As expected, permeabilities show a hysteretic dependence on confining stress.
Hemispherical flow measurements with homogeneous porous media indicate that fluid injection would yield permeability close to the true value. Furthermore, sequential injection of multiple phases shows that endpoint effective permeabilities may also be obtained.
Traditionally, formation tester probes have measured reservoir pressures, obtained local permeabilities, and collected fluid samples. To ensure good hydraulic contact of the probe with the porous medium, it is customary to withdraw a small volume of fluid rapidly. During this "high" -rate or burst test, pressure is recorded, giving drawdown and buildup data.
Two distinct approaches to deduce permeability from transient pressure data have been considered in the past. The steady-state drawdown pressure is established by flow near the probe and is interpreted in terms of the local mobility. In contrast, the late-time buildup is assumed to reflect the far-field mobility. In this paper, our concern is establishment and interpretation of the steady-state pressure drop at the probe.
The Navarin Basin, located in the Alaskan Bering Sea, is the approximate size of the state of Louisiana. In 1984, industry paid over $681 million for leases in the Navarin Basin. Amoco Production Company, along with two other companies, decided to explore parts of the Basin in 1985 to evaluate its hydrocarbon potential.
Because of ice encroachment and associated environmental concerns, the drilling window for most of the Navarin Basin is between June and December. Amoco's strategy was to drill four to six wells starting in June (historically the time the ice regresses).
This paper presents how a systems-oriented approach was used to plan, prepare for drilling and drill five wells by mid-November 1985. This paper will show how the project objectives and environment led to the design of the "wareship concept" to support the drilling of five wells without one day being lost waiting on materials or personnel. The paper will present the first major use of Amoco's paper will present the first major use of Amoco's "Critical drilling Facility" concept to plan, prepare and drill the Navarin wells. prepare and drill the Navarin wells. The paper will show how two drilling rigs, a wareship, tanker, four workboats, two standby boats, three helicopters, a staging base in St. Paul and a secondary support base in Dutch Harbor was controlled by the Anchorage Navarin Operations Center using the Tulsa-based Critical Drilling Facility. This was all made possible by the advanced systems technology, including a sophisticated satellite communications system and a project-oriented methodology.
This paper will present the drilling system design, implementation, and results. This includes the design and use of a potassium lime mud system and the optimization of the solids control system on each drilling machine. Included results will show that the designed drilling system achieved all drilling objectives and had a significant impact on the success of the Navarin project.
The exploration of far northern frontier areas, such as the Navarin Basin, Gulf of Alaska, Norton Sound, St. Georges Basin, the Beaufort Sea and the east coast of Canada, have proved to be extremely costly, time consuming and dangerous. Logistical problems, severe weather conditions, limited problems, severe weather conditions, limited communications and environmental constraints can make drilling operations some of the most expensive in the world. In 1984, Amoco Production Company made the decision to explore certain prospects in the Navarin Basin where only one COST well had been drilled in the entire basin (Figure 1).
The Company had to develop an exploration strategy which considered some of the following factors: (1) given the weather window to explore in the Navarin is roughly from June to December, should the exploration be phased over a number of years or should the Company go ail out to evaluate as much of the basin as possible in one season?; (2) given that the Company had never operated in the Bering Sea, should it pursue a more aggressive drilling program or be more conservative?; and (3) if the Company only had five months to plan and get ready for the June startup, should it consider the more aggressive multidrilling rig approach versus the conventional single drilling rig exploration program?
RESERVES OF NATURAL GAS OUTSIDE THE COMMUNIST BLOCK COUNTRIES Michel T. Halbouty, Chairman of the Board and Chief Executive Officer, Michel T. Halbouty Energy Co., 5100 Westheimer Road, Houston, Texas, 77056, United States of America. Abstract. The proved natural gas reserves of countries outside the Communist Block as of 1.1.83 are estimated to be approximately 2003 Tcf (56.72 Tcm). Current geologic, engineering and economic assessments indicate that although these proved natural gas reserves are sizable, there are more reserves yet to be added to the resource base than have been found to date. The estimated undiscovered potential is approximately 2901 Tcf (82.15Tcm). Many of the present producing basins have yet to be fully evaluated and the vast frontier areas-onshore and offshore, in both moderate and harsh physical environments-await extensive exploration. Thus, there are good possibilities that the natural gas reserves of countries outside the Communist Block, i.e. the United States, Canada, Latin America, Western Europe, the Asia-Pacific regions, Africa, and the Middle East can be greatly increased. To arrive at these conclusions, this study concentrated on rapidly advancing technology, re-evaluation of known and newly discovered gas fields, reassessment of prospective areas which were previously considered uneconomical for exploration and development, additional potential resulting from deeper drilling, and the removal of many regulatory restraints which had previously discouraged extensive exploration in many areas of the world. Résumé. Les réserves prouvées de gaz naturel en dehors des pays communistes étaient évaluées au ler janvier 1983 à environ 56.72 10" m3 (2003 Tcf). Les estimations géologiques, techniques et économiques actuelles indiquent, malgré l'importance de ce chiffre, qu'il existe d'autres ressources à ajouter à celles trouvées maintenant. Le potentiel non encore découvert est estimé à 82.15 10" m3 (2901 Tcf). De nombreux bassins actuellement en production doivent faire l'objet d'évaluations complètes et il y a de vastes zones frontières-& terre comme en mer dans des milieux au climat aussi bien modéré que sévère-où une exploration poussée doit être entreprise. Ainsi, il existe de bonnes possibilités d'accroître considérablement les réserves de gas naturel de pays non communistes tels que les Etats-Unis, le Canada, l'Amérique latine, l'Europe de l'Ouest, les régions Asie- Pacifique, l'Afrique et le Moyen-Orient. Pour arriver à ces conclusions, l'étude s'est appuyée sur l'évolution rapide de la technologie de pointe, la réévaluation des gisements de gaz connus et récemment découverts, les estimations nouvelles de zones possibles où l'exploration et le développement avaient été précédemment jugés non économiques, l'étude du potentiel supplémentaire résultant de forages plus profonds et la suppression de nombreuses contraintes administratives qui
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This paper illustrates the requirement, design, development, and installation of a permanent mooring system for construction support vessels in the Piper field in the North Sea. Key features of the mooring system and its installation procedures are detailed.
The need for support vessels alongside the platform during construction programs offshore has focused attention on the problems of mooring and maintaining station in this service. In the past, mooring systems under storm situations have been designed primarily for open-ocean applications and have not primarily for open-ocean applications and have not catered to the requirements of operating and surviving alongside a fixed platform. In addition, anchor handling and dragging have been primary causes of damage to submarine pipelines. This problem becomes more acute as the number of problem becomes more acute as the number of vessels around the platform increases and the number of moorings over time becomes significant enough to constitute a hazardous situation. The Piper field operators - Occidental of Britain Inc. on behalf of partners Getty Oil Co., Allied Chemical (Great Britain) Ltd., and Thompson North Sea - experienced these mooring difficulties, compounded by poor topsoil conditions, which led to the design and installation of a fixed, permanent anchor-pile mooring system around the Piper A platform. platform. System Description
Eight anchor piles are positioned symmetrically around the Piper A platform to provide a suitable anchor pattern for a multiservice construction vessel to moor alongside the platform in periods of good weather and away from the platform in periods of bad weather. Each anchor pile is approximately 4,000 ft (1219 m) from the center of the platform, and the 1,010-ft (309-m) connecting chain lies on the seabed in a straight line between the anchor pile and the platform. The free end of each chain is connected to a pendant line and marker buoy, which is used to raise the free end of the chain to the surface during connecting or disconnecting operations (Fig. 1).
The anchor-pile system is designed to accommodate construction and tender vessels ranging from medium-sized to third-generation semisubmersibles with operating draft displacements in excess of 40,000 Mg. This system allows for vessels to moor on any of the four sides of the platform and maintain adequate clearance of the mooring catenary from the legs of the platform jacket. The vessel anchor line is "shackled up" to the anchor pile, making it a semipermanent connection. These piles are able to withstand vertical and horizontal forces, thus allowing for adequate "spring constants" throughout the vessel excursion distance even after introducing uplift forces at the anchoring point.
System Design Mooring System
The mooring system consists of eight anchor piles encircling the platform.