Summary Exploration in frontier basins provides limited information on lithology and stratigraphy when no well data are available for calibration. Herein, we demonstrate how omnidirectional sampled data acquired with multimeasurement streamers and seismic data processing using image processing methods reveal geologic features along horizons that allow interpretation for depositional environments at a 10-to 20-m vertical resolution. Acquisition geometries appropriate for exploration-scale coverage are able to support the higher spatial resolution required to unmask original and post-depositional lithology. Introduction Resolution limits on seismic data for analyzing depositional environments, lithology, and pressure depend on a number of factors. These comprise usable frequency content for vertical sampling, spatial sampling of the seismic data, and seismic velocities for proper migration of the wavefield to provide optimum horizons for geological interpretation.
In April 2009 a comprehensive review of the prospectivity of the offshore Nova Scotia Basin was commissioned by the Offshore Energy Technical Research Association of Nova Scotia (OETR). This was fundamentally based on a complete reevaluation of the exploration history of the Scotian margin.
This paper describes the overall approach used in this study and presents the main results and key conclusions.
The play fairway program addressed three key issues:
1. Plate Tectonic Reconstruction: a better understanding of the rift history of the Nova Scotia/Morocco conjugate margin pair was needed. Understanding the relationship between rifting and salt deposition is critical in developing models for potential syn-rift and early post rift depositional environment and the development of source rocks.
2. Sequence Stratigraphic Framework: lack of a published modern sequence stratigraphic framework for the margin has impeded the development of robust regional exploration models. Hence the program included a re-evaluation of the biostratigraphy of several key wells, which were integrated with the seismic interpretation, and tectonic models, to build a comprehensive sequence framework.
3. Forensic Geochemistry: although much geochemical data exists on the margin through the many hydrocarbon shows and discoveries, the source rock story was not well understood. The program has undertaken a systematic evaluation of the geochemistry of source rocks and hydrocarbon fluids. An important component of this work was analysis of hydrocarbon bearing fluid inclusion found in the salt. A key goal of this project was to demonstrate evidence for lacustrine or restricted marine early Jurassic source rocks, which would considerably enhance the hydrocarbon potential of the area.
The program integrated a number of specialist sub-projects to help develop a robust regional exploration model for the Scotian margin. These included extensive work on biostratigraphy, plate tectonics, seismic interpretation, geochemistry, petroleum systems analysis as well as acquisition of new geophysical data (refraction seismic) and reprocessing of multichannel and existing refraction seismic. The whole integrates to deliver a set of Gross Depositional Environment (GDE) maps built on internally consistent sequence and seismic stratigraphic interpretations. A key component of this was development of a thorough understanding of the salt kinematics offshore Nova Scotia. The complex salt dynamics have had a very significant influence on sediment dispersal pathways and present a significant challenge to oil and gas exploration.
The paper shows the underlying geological models that underpin the prospectivity of the Scotian margin. A number of plays can be been defined, including Jurassic carbonates, delta and deep marine reservoir systems, sourced locally or from deeper syn/post rift lacustrine/restricted marine sediments. Extensive large-scale salt related structures show the potential of a high value petroleum province in the under-explored shelf/deep water areas offshore Nova Scotia.
This paper presents the alternatives available and assessment of floating platforms, stationkeeping and riser systems based on studies undertaken for Arctic fields. The industry experience with floating units for both drilling and production operations in the offshore areas subjected to ice features are discussed. The salient aspects of these systems are discussed considering the general characteristics of selected basins.
The Arctic fields developed so far are in water depths up to 125 m and have used the Gravity Based Structures and detachable FPSOs, besides other systems such as jacket platforms and islands used in shallower water. There is significant industry interest in the development of Arctic and Sub-Arctic fields in water depths beyond commercial viability of bottom founded designs. The water depths in some North American and offshore Greenland Basins are up to 2,800 m. The development of fields in deeper water would require use and adaptation of floating units and subsea systems, which have been used in many deepwater basins. However, their use in deepwater Arctic would add significant challenges from harsh weather, severe ice features (pack ice, icebergs), lack of infrastructure, remoteness, and reduced accessibility.
The floating unit designs, alternatives for sub-systems, and subsea solutions and technologies are enabling development of Arctic fields offshore Norway and Russia, such as Goliat and Shtokman in up to 350 m water depth. Floating units provide flexibility in field development and ability to detach and move the unit from the path of significant ice loading events and icebergs. These features enable improve their technical and commercial feasibility by reducing load effects and risks.
Challenges in Arctic
The development of hydrocarbon fields offshore Arctic and Sub-Arctic in the North, have gained significant importance due to potential for very large reservoirs increasing their commercial viability. Some of the important leasing areas in the Arctic or Sub-Arctic offshore identified in Fig. 1 are in deepwater and ultra-deepwater: Barent Sea, offshore Norway and Russia; Orphan Basin, offshore Newfoundland; and fields offshore Greenland and Iceland. The water depths vary from 300 m to 3,000 m in these leases and several of these fields are in exploratory drilling or in the development planning stages.
In the fall of 2010, shale gas exploration and development in Canada is just getting started. Engineering advances are making unconventional gas plays more attractive. Provincial governments are looking to tap the economic benefits. Regulators are adjusting existing oil and gas regulations or drafting entirely new legislation. This paper covers a selection of topics for each of the seven Canadian provinces where shale gas development has started or is about to begin. So far, regulation of shale gas is not very different from the regulation of conventional gas exploration and development. Interest groups and regulators are following U.S. trends.
Wellbore positioning is a major challenge in eastern Canada because of the extensive faults in the Jeanne d'Arc basin. Accurate well placement is vital to the success of hydrocarbon production; accurate surveys are required in real time to drill 3D trajectories that penetrate multiple small geological targets and avoid costly subsurface collisions with adjacent wellbores.
Magnetic surveying has become increasingly accurate and now provides a cost-effective alternative to gyroscopic surveys in real-time drilling applications. Magnetic tools are subject to two main sources of error: variations in the local magnetic field and interference from magnetized elements in the drillstring. New techniques for identifying and compensating for these errors involve a better understanding of the natural variations in the earth's magnetic field, and new methods of mapping local variations improve magnetic modeling.
A key innovation is the ability to create an accurate and robust crustal model and integrate real-time diurnal measurements from nearby magnetic observatories. The addition of observatory data that improves positional uncertainty has made magnetic surveying a viable option, even at higher latitudes where more extreme variations in the local magnetic field would otherwise induce unacceptable positioning errors. Geomagnetic referencing services now offer a multitiered approach to achieve the requisite degree of positional accuracy within the economic restraints of a given drilling program.
Geomagnetic referencing can produce significant savings in overall project costs by providing accurate, real-time data on well position while corrections to trajectory are still possible. Real-time azimuth control can prevent the costly sidetracks that are often required when only a postdrilled survey is performed and reveals that the well has missed its target. Geomagnetic referencing also eliminates the cost of extra rig time required to run an accurate postdrilled gyroscopic survey, which can be a significant benefit when budget restraints are critical.
One of the key features of the Spar platform is its low motion response characteristics. This results in a high degree of functional flexibility that has enabled the Spar to be employed in a variety of different applications such as wet tree host, dry tree wellhead, with or without platform drilling facilities and with or without production facilities. The Spar has also been employed as wellhead only platform, utilizing Tender Assisted Drilling in place of a Spar mounted drill set. While all but one of the Spars in service today operate in the US Gulf of Mexico (the one exception being the Kikeh Spar in Malaysia), new designs have been developed for the Spar platform to further extend its use, both in terms of function and geographic location, in order to meet the needs of other oil and gas producing regions as they extend their E&P activities into deeper waters and more harsh environments. These designs range from relatively simple modifications, such as the incorporation of crude oil storage in the hull to facilitate the use of dry tree completions and motion sensitive riser systems in infrastructure-remote locations, to more significant modifications, such as the reconfiguration of the Spar as a power and control buoy platform, or as a deep water Arctic platform, which requires the Spar to function as an ice-breaker in sheet ice conditions, while also allowing it to be disconnected to avoid larger icebergs.
The functional requirements, export infrastructure, operating environments and construction and installation capacity vary significantly across regions. Each of these variations has the potential to drive alterations to the Spar hull configuration. This paper discusses the most significant requirements of a number of key regions where Spar technology can provide significant value, and addresses these requirements in terms of the resulting Spar configuration and how the Spar design has been, or can be, adjusted to meet the local challenges and requirements. The specific regions covered are the ultra deep waters of the Gulf of Mexico, S.E. Asia, West Africa, North Sea, Brazil and the Arctic regions of East Canada and the Barents Sea. A variety of Spar configurations are presented to address nominal solutions for each of the regions, each based on either the Classic, Truss or Cell Spar technology.
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19273, "The Offshore Petroleum Industry in Atlantic Canada - A Regional Overview," by R.P. Barnes, Canadian Association of Petroleum Producers, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
Twenty-four oil and/or gas discoveries have been made offshore Newfoundland and Labrador. Three of the oil discoveries have been developed and a fourth is under consideration. The focus of development activity has been on the larger oil discoveries. As production from the larger discoveries matures, facilities and other infrastructure will become available for development of the remaining smaller discoveries. Development and tie-in of smaller pools and fields provides an opportunity to utilize this spare production capacity at these fields. Currently, there are several satellite tie-in and expansion projects in progress and others are under review. Development of the discovered smaller fields will play an important part in sustaining production from offshore Newfoundland and Labrador. In addition, many of the offshore basins are under explored and represent other opportunities to supply the next round of developments.
Newfoundland and Labrador, Canada's easterly province (Fig. 1) is strategically positioned on international shipping lanes, with unique access to global petroleum markets.
This paper will give an overview of current and planned future offshore exploration, development and production activity taking place off the east coast of Canada. It will also cover other items of interest occurring in that area including industry related research and development, recent changes in government policy and future growth potential of the industry. Information provided in this paper will be of interest to petroleum supply/service companies wishing to market their goods and services in this region of Canada as it will identify what producers are active in this area and possible future growth opportunities. In addition, the information provided on petroleum related research and development taking place and being applied in the region for offshore development and production would be of interest to a technical audience wishing to apply such research and development to other producing areas.
This paper describes a risk based business approach for use of the ASTM Risk-Based Corrective Action (RBCA) process to establish baseline environmental conditions, classify environmental risks, and predict the potential remediation costs associated with historical oilfield operations. As part of an environmental due diligence performed for upstream oil and gas production facilities in Colombia, this risk-based due diligence process allowed prioritization and characterization of sites based on key risk and cost drivers. The methodology facilitated identification of remedial action strategies and development of an appropriate remedial action schedule, based upon inspection and review of a representative sample of the oilfield facilities. The case study in this paper is for an oilfield consisting of 1710 well sites, 7 active production stations, 76 abandoned substations, 2 crude oil dehydration plants, and a gas processing plant distributed over an area of 190 square kilometers. Within the limited time available for the due diligence, the approach facilitated completion of the property transaction and allocation of reserves as escrows in project negotiations to the satisfaction of all parties involved.
For this case study due diligence effort, site inspections were conducted at a representative percentage of each type of oilfield facility to identify site conditions posing concern in terms of "primary risk factors?? (human health or safety) or "secondary risk factors?? (i.e., impacts on ecological resources, water resources, land use, or regulatory compliance issues). Observed conditions were then characterized according to the RBCA classification system to define the relative magnitude of the risk posed and the relative urgency of need for a response action. For each type of oilfield installation, these data comprised a "risk distribution,?? defining the key risk drivers and the frequency of occurrence of higher risk (Class 1) vs. lower risk (Class 2, 3, or 4) conditions. These risk distributions were then used to predict the probability of encountering similar conditions within the balance of sites not inspected during the due diligence process, as well as to establish an overall schedule and budget for remedial actions (i.e., addressing high-priority conditions in the near-term and lower-priority conditions at a later time).