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Abstract Lightweight or, alternatively, foamed cement slurries for surface casing operations are often necessary during special situations (i.e., low fracture gradients) for the required zone to be isolated. The foamed cement technique reduces the heat of hydration (HoH) of the slurries, reducing potential risk of shallow hydrate flow and losses because of its reduced hydrostatic pressure. This alternative for lightweight slurries has been used globally with successful results. The foamed cement operation was designed and executed considering specific aspects and details, including a combination of factors, such as expected low fracture gradient, mechanical property requirements, logistic constraints in terms of the difficulty managing two types of cement (large tonnage of Blend and G cement vs. rig capacity and safety volume requirements), long sections to be cemented, and the uncertainty of the cement volume excess necessary to achieve return in the seabed. Because this was the first cement operation for the operator at this remote deepwater field, the planning phase required extensive discussions. Rig silo capacities and deck space on the rig were limited, which constrained the possibility of considering backup for all bulks, chemicals, and equipment. Execution of the cement operation was as per the approved program without deviation. The cement volume returned at seabed indicated an openhole diameter with ±100% washout. A tracer additive (fluorescent dye) mixed with the spacer was successfully used to indicate fluid return at seabed (2120-m water depth). As part of the best practices to execute this operation, a liquid additive system was used to provide pump volume flexibility. Foamed cement laboratory tests were performed, considering field samples and the foaming agent (surfactant) were injected straight at the suction of the pump. As expected, the foamed cement operation is an extremely efficient and effective technique to achieve zonal isolation in a surface casing string of a deepwater well. Currently, this procedure is frequently used in fields globally. A case study of the first foamed cement application for surface casing in French Guiana is discussed.
Abstract Objectives/Scope The paper will have four objectives: to outline how satellite technology can enhance oil spill monitoring and therefore consequence management even at mid-latitudes; to explain the technical challenges of using satellite technologies at mid-latitudes, such as in the Arabian Gulf; to showcase studies of how satellite-based oil spill monitoring has been done successfully at mid-latitudes elsewhere in the world; to outline how collaborative satellite monitoring could be adopted by countries around the Arabian Gulf, patterned on Norway and the European Maritime Safety Agency's multi-stakeholder approach. Methods, Procedures, Process The presentation will begin with an explanation of the key benefits of using satellite technology for oil spill monitoring and enhanced consequence management, as well as the identification of likely polluters; outline the challenges posed by doing so at mid-latitudes, such as the Arabian Gulf; use the case study method to demonstrate how it has been done successfully elsewhere under similar conditions; provide a vision of how collaborative satellite oil spill monitoring and polluter identification could be used to great effect in the Arabian Gulf, modeled on examples from the Norwegian Clean Seas Association for Operating Companies (NOFO) and the European Maritime Safety Agency's (EMSA) multilateral monitoring program. Results, Observations, Conclusions The results of the paper will be two-fold. Drawing on the example of successes in the Gulf of Mexico and French Guiana, that there are two keys to successfully using satellite technology at mid-latitudes for oil spill monitoring and enhanced consequence management. First, that a multi-mission satellite provider is required because one single satellite will not offer sufficient daily coverage close to the equator to provide oil and gas operators, or regulatory authorities, with adequate actionable information. Second, that the satellite provider must be suitably equipped in its service delivery chain to offer near-real time service, meaning delivery of oil spill detection reports in under 2 hours. Against the background of these results, a conclusion will be drawn, which is that significant benefits would accrue from the countries in the Arabian Gulf adopting a collaborative oil spill monitoring program based on effective satellite technologies. This challenge is particularly pressing given that an oil spill at one end of the Gulf will inevitably threaten beaches and delicate marine eco-systems at the other end. And when it comes to effective oil spill detection and consequence management, the most valuable commodity is time, making genuinely actionable information vital, not optional. Novel/Additive Information The potential, challenges and solutions of using satellite technology for oil spill monitoring and enhanced consequence management are not well known in the petroleum industry. This presentation aims to address that knowledge gap and showcase novel solutions to a key, pressing, HSE challenge for the petroleum industry.
Abstract The health of conventional exploration had been suffering before the oil price crash in 2H 2014; commerciality and value creation both declined dramatically over the past five years. Overall discovered conventional volumes reached exceptional peaks of between 30 and 50 billion boe per year in the years 2009-2012, dominated by two mega-plays: the pre-salt in Brazil and East African gas. The next two years were disappointing in comparison, although average discovery sizes, volumes added per well and success rates held up well. Returns from conventional exploration have been on a downward trend for a decade. The proportion of gas grew, as did the share of volumes found in deepwater. Cost escalation was exacerbated by increasing complexity of both exploration and development. A growing emphasis on frontier deepwater plays resulted in several country-opening oil discoveries. However, these finds fell short of the giant size required to anchor a deepwater development in countries like Sierra Leone, Cote d'Ivoire and French Guiana. In the first half of the past decade, 70-80% of oil volumes are deemed commercial, but the proportion drops to 30-60% in the second half. A shift back towards mature offshore basins is underway and will accelerate in the near term. As the top explorers struggled to replace resources and create value from conventional exploration, many turned to exploration of unconventional resources. Volume additions were undoubtedly strong for most companies, but to outperform by value creation from exploration in resource plays in North America, companies must be first, fast and focused. These trends may hold lessons for those wishing to avoid the short-termism of the current environment. Companies with an appetite for counter-cyclical moves could capture long-term, low-cost resource opportunities, establishing a strong prospect pipeline and building a flexible portfolio that plays to their strengths.
Summary In this paper we explore the West Africa-South America analogue proven by the Jubilee and Zaedyus discoveries in Ghana and French Guiana, respectively. Instead of the Turonian turbidite fan reservoirs, we consider younger unproven deep water channel systems in Foz do Amazonas Basin in Brazil which could be analogous to the Campanian pay found in the Teak field in Ghana. We present a geological overview of the basin together with acquisition details and imaging results of a regional 3D CSEM survey in the area. Using CSEM as a fluid indicator, we calculate the Net Rock Volume (NRV) from a channel-shaped EM anomaly and with conservative parameterization we obtain a P10/P90 ratio of 14.7 and an average NRV of ~23000hm. Introduction In September 2011 Tullow Oil announced a significant oil discovery in the Zaedyus prospect in French Guiana that established the Turonian aged Jubilee play from Ghana, West Africa. Following the Zaedyus discovery, a 2012–2013 drilling program of 4 exploration wells targeting nearby turbidites resulted in disappointing commercial success. We will discuss the potential of the younger channel play in the lower Tertiary and upper Cretaceous in Foz do Amazonas basin rather than the Turonian turbidite fans. Continuing the West Africa/South America analogue, the channel systems could resemble the Campanian pay of the Teak-1 exploration well in Ghana (Kosmos Energy, 2011). First, we will give an overview of the geology providing potential reservoir and trapping mechanisms. Second, we will use results of a regional multi-client 3D CSEM survey as a fluid indicator. Acquired in 2013, the survey is bordering French Guiana towards west within 15km of the last exploration well of the drilling program, GM-ES-5, and within 50km of the Zaedyus discovery. Third, we will use the method introduced by Baltar and Roth (2013) to estimate the Net Rock Volume in a sub-region of the CSEM coverage. Geological overview The present day shelf margin region of the Foz do Amazonas Basin has undergone significant modification from mass wasting events and debris flows. The basin provides analogous examples for deep water depositional systems in the underlying Tertiary and Cretaceous sections. Based on seismic observations, the shelf is shaped by the orientation of shallow basement that is interpreted as continental crust from potential field data. The basement extends outward from the coastline for approximately 130 kilometers before rapidly dropping off in a series of complex fault systems that are related to older rift stage graben systems.
Summary In this paper we explore the West Africa South America analogue proven by the Jubilee and Zaedyus discoveries in Ghana and French Guiana, respectively. Instead of the Turonian turbidite fan reservoirs, we consider younger unproven deep water channel systems in Foz do Amazonas Basin in Brazil which could be analogous to the Campanian pay found in the Teak field in Ghana. We present a geological overview of the basin together with acquisition details and imaging results of a regional 3D CSEM survey in the area. Using CSEM as a fluid indicator, we calculate the Net Rock Volume (NRV) from a channel-shaped EM anomaly and with conservative parameterization we obtain a P10/P90 ratio of 14.7 and an average NRV of ~23000hm.
Abstract Exploration in deepwater areas of the world within the past 10 years has resulted in the discovery of several very significant conventional oil and gas accumulations within turbidite reservoirs, such as, those in the Lower Tertiary formations of the U.S. Northern Gulf of Mexico (Tiber, North Platte, and Shenandoah) and the Mexican southern Gulf of Mexico (Trion and Maximino), and in the Cretaceous basin-margin fans of the Ghana turbidite complex (Jubilee and Tweneboa-Enyenra-Ntomme, TEN), and the French Guiana (Zaedyus) turbidite fans. This paper considers the geologic origin of deepwater clastic sediments and describes the key geometric and architectural characteristics of four distinct deepwater turbidite facies:Upper Fan proximal (slope) high energy canyon channels; Middle Fan channel-levee complexes; Outer or Lower Fan basin-floor distal layered and amalgamated lobes and sheets; and lateral and interfan mud-rich mass-transport deposits (MTDs).
Abstract An abandonment cement plug is placed as part of the permanent barrier system to isolate permeable formations and maintain well integrity. Placing a cement plug in any well is critical. The challenges in placing a successful cement plug in deepwater environments can be accentuated by factors such as the low temperatures associated with the water depth, setting long plugs in a single attempt, inability to use mechanical separators, variety of local regulations and more. The accepted industry practice is to set a plug of 100 - 250 m in length. Longer plugs increase operational challenges such as stuck pipe. Slurry design in deepwater is also critical due to the temperature profile that the slurry is exposed to. The local regulations in French Guiana require 50 m of cement isolation above and below any permeable zone. Multiple or long permeable zones may require long cement plugs. The long abandonment plugs of more than 250 m in ultra-deepwater require careful attention to design and operational practices. The static time needs to be carefully incorporated in the slurry design to simulate the pipe pull out. After the plug placement, integrity and depth verification may involve either pressure testing or tagging of cement top with weight. The slurry design needs to have early compressive strength while still respecting the long static time and ultra-deepwater temperature profile. Slurry contamination from synthetic based mud (SBM) decreases by using mechanical separators during pumping. If a mechanical separator is not used, spacer fluid volume can be increased to minimize cement contamination. The cement contamination by spacer is affected by different types of surfactants that are used and it is important to understand the effect of each surfactant for successful recipe. Cementing simulation software can help achieve the objectives while planning a cement plug for well abandonment. Regulations are very stringent in regards to barriers for well integrity. In this particular case a total abandonment of over 2000 m was required. It was achieved by successive long cement plugs. The paper discusses sound engineering and operational practices that increase the chances of good plug placement. These practices may also save millions of dollars worth of rig time. Requirements for plug and abandonment in French Guiana The exploration wells in French Guiana were drilled offshore of Cayenne as is shown in Fig. 1. The plug and abandonment process was carried out as per operational planning and agreement with local regulatory standards. Regulations required permanent barriers of 50 m, above and below any permeable zone in any annulus. In addition, 50 m of " good" cement was required above the casing shoe immediately above the open hole. As defined in the well abandonment manual and guidelines (EP 2010–1305), a cement plug is the most acceptable permanent barrier. In addition, any critical permanent barrier by Shell standards must have a back-up permanent barrier that is able to control the maximum anticipated pressure if the first permanent barrier would fail. It must be positioned at a depth where the formation is impermeable and formation's strength exceeds the maximum anticipated pressure. The above requirements were used as guidelines for planning the plug and abandonment process of exploratory wells in French Guiana.
Despite some uncertainty in the global economy, the long-term outlook for energy demand remains strong and the industry will continue to be challenged to meet hydrocarbon supply over the next decade. In its latest outlook, the International Energy Agency estimates that approximately 32% of oil production needed by the end of this decade has yet to be discovered or developed, and by 2035 it will be closer to 50%. In response to this challenge, the exploration and production (E&P) industry has become more ambitious in searching out new frontiers, with some notable successes over the past few years, particularly in deep water. More than half of all oil and gas reserves discovered worldwide over the past 10 years have been offshore and the majority of large finds have been in water depths of more than 500 m (1,640 ft). We are reminded that 10 years ago pre-salt reserves offshore Brazil were still not proven, and that deepwater discoveries in areas such as French Guiana, Tanzania, and Ghana were not even on our industry's radar screens.
Guest editorial Despite some uncertainty in the global economy, the long-term outlook for energy demand remains strong and the industry will continue to be challenged to meet hydrocarbon supply over the next decade. In its latest outlook, the International Energy Agency estimates that approximately 32% of oil production needed by the end of this decade has yet to be discovered or developed, and by 2035 it will be closer to 50%. In response to this challenge, the exploration and production (E&P) industry has become more ambitious in searching out new frontiers, with some notable successes over the past few years, particularly in deep water. More than half of all oil and gas reserves discovered worldwide over the past 10 years have been offshore and the majority of large finds have been in water depths of more than 500 m (1,640 ft). We are reminded that 10 years ago pre-salt reserves offshore Brazil were still not proven, and that deepwater discoveries in areas such as French Guiana, Tanzania, and Ghana were not even on our industry’s radar screens. It is estimated that approximately 200 new deepwater fields will enter production over the next 4 years. By 2020, production from deepwater fields will represent about one-third of total offshore production, representing about 10% of total global oil supply. Deepwater well capex is expected to grow from USD 47 billion to approximately USD 128 billion by 2020, with 71% of this growth taking place in the Atlantic basin—particularly in Brazil, Angola, Nigeria, the US Gulf of Mexico (GOM), and Nor-way. Other countries with solid deepwater activity include Australia, Egypt, and India. To achieve this significant growth, an increase in the number of floater rigs is forecast, from 200 in 2008 to more than 400 by 2020—an average of more than 20 new rigs per year. This estimate is consistent with mid-term forecasts of new deepwater rigs and suggests that the trend will be maintained until the end of the decade. Over the period 2013-2020, deepwater well costs are expected to slightly increase in real terms. While efficiency gains are expected in regions such as the US GOM, thanks to next-generation rigs entering the market and the continued integration trend of new drilling technologies, these will be offset by increasingly complex and deeper wells. Exploration and appraisal activity is set to continue along the same trends for the rest of this decade, with further expansion in basins with recent discoveries such as the Mexican GOM, Equatorial Atlantic, east Africa, and the eastern Mediterranean. Activity will also be strong in basins with less-recent discoveries but where technology and/or access drivers have opened additional opportunities, such as Brazil, west Africa, and the US GOM.
Summary The Jubilee discovery offshore Ghana, made by Tullow in 2007, opened up several underexplored basins on the transform margin, and indicated the potential for further discoveries. In 2011, Tullow made the Zaedyus discovery offshore French Guiana, proving up the potential of the conjugate South American margin. Regional structural and stratigraphic analysis of West Africa, alongside studies of the trends and characteristics of successful producing fields from Sierra Leone to Nigeria, is used to define probable play types on the underexplored South American Equatorial conjugate margin. Cretaceous deep marine turbidites represent a key reservoir target, and key risks include source rock migration and reservoir distribution. Use of regional high quality seismic datasets for paleogeographic reconstructions such as these is necessary in order to better constrain the petroleum systems on both the African and South American Equatorial Margins.