Deepwater Frontier Research Articles

Depositional environment and source rock distribution of the Late Cretaceous Rakopi formation in the deepwater Taranaki Basin, New Zealand

The interpretation of depositional environments and evaluation of potential source rocks in deepwater frontier basins are challenging because of the limited data availability. The Deepwater Taranaki Basin, the northwest extensional area of the Taranaki Basin in New Zealand, hosts the Late Cretaceous Rakopi Formation, which is one of the most important source rocks and potential reservoirs in the Taranaki Basin. This study utilized seismic data and well ties from the Romney-1 well to interpret three seismic units in the study area, representing different depositional environments and evolutions. These units were correlated with the regional Megasequences B2–B4 in the Deepwater Taranaki Basin. Sediment transport and progradation mainly occurred from the northeast to the southwest direction. Fluctuations in relative sea levels influenced the shifting of the shelf and marginal environments, potentially creating coal-bearing strata in the study area. The key source rock strata were identified within units 2 and 3 characterized by kerogen type III, coaly source rocks in a marginal environment. A minor source rock interval was found in unit 2, characterized by kerogen type II, marine organic matter in a bathyal environment in the depocenter of the study area. Coal seams were identified using seismic and well log data. However, thin coal seams were challenging to distinguish clearly, sometimes showing a similar response to sandstone beds, because of the limited seismic resolution. Thus, within limited data areas, source rock predictions can be made in the context of depositional interpretation.

E&P Notes (February 2022)

E&P Notes (February 2022)

Revealing oil migration in the frontier Bight Basin, Australia

Abstract The Bight Basin along the southern margin of Australia represents one of Australia's most prospective deep-water frontier hydrocarbon exploration regions, however its 15 km-thick sedimentary succession remains largely untested. Whilst there is some evidence of oil from shows, fluid inclusions and natural strandings of asphaltite along the basin margin, it is unclear if any hydrocarbons were generated in the deep-water Ceduna Sub-basin. Fluid inclusions offer a unique method to test for petroleum migration that would otherwise remain hidden and a study, using CSIRO's Grains with Oil Inclusion (GOI™) technique, was undertaken on Gnarlyknots-1A along with other historic exploration wells. With the exception of Jerboa-1, in the Eyre Sub-basin, the GOI results (

Malaysia’s Petronas is Looking Near and Far for Gas and Oil

Petronas is looking within its home country, around Southeast Asia, and to the Americas in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. It is also exploring new partnerships with other global operators that offer regional and technical expertise. The integrated company, whose upstream portfolio consists primarily of natural gas, wants to both accelerate its exploitation of the hydrocarbon and add more oil to the mix. Back home, Petronas—the world’s third-largest LNG seller—continues to target domestic gas to leverage its control of the gas value chain all the way to its petrochemical and LNG liquefaction plants. The company’s LNG facilities include its 30-million tonnes/annum (mtpa) complex in Sarawak, and the world’s first floating LNG facility, the 1.2-mtpa PFLNG Satu. A second floating LNG facility is expected to be ready for sail away by 2020. Petronas is taking advantage of a growing Southeast Asia gas market, counting Japan, Korea, Taiwan, “and increasingly China” as major LNG customers, said Adif Zulkifli, Petronas executive vice president and chief executive officer of gas and new energy, on the sidelines of a recent SPE forum in Kuala Lumpur. Adif said one of Petronas’ primary goals is to turn Malaysia’s large inventory of contingent resources into proved reserves. The company has worked “to intensify exploration activities in Malaysia,” and it is seeking to bring more partners into the fold: The country recently revised terms in its deepwater production-sharing contracts to attract more international participation. “We are quite progressive in terms of attracting investment, and that has brought in some new plays into the space,” he said. Adif believes “there is much potential within the deep waters of Sabah that is still left untapped and remains very attractive to investors.” Last year, the Total-operated Tepat-1 well in deepwater Sabah tested a frontier Miocene carbonate buildup “and is believed to have found oil and gas, though commerciality is uncertain and the results are being kept very tight,” according to a report from research consultancy Westwood Global Energy. “Tepat demonstrates that explorers are still testing new plays in the region and that a breakthrough could yet happen.” Elsewhere in Southeast Asia, said Adif, the company hopes to soon monetize its operated deepwater Kelidang cluster project off Brunei, continue exploratory work on the recent onshore Sakakemang discovery in Indonesia, and improve recovery from its Yetagun block off Myanmar. Petronas farmed in to the Sakakemang block in January, a month before operator Repsol announced the discovery, which comes with a preliminary estimate of 2 Tcf in recoverable resources. Petronas also intends to explore the deepwater Moat-tama Basin off Myanmar and frontier areas off East Indonesia, he added.

Challenges in the use of potential field data for studies of remote, deep-water frontier basins

Given the sparsity of seismic data covering remote offshore frontier basins, Geoscience Australia?s studies of these areas rely heavily on gravity and magnetic data. These data complement 2D seismic reflection data by allowing interpretations to be extrapolated away from the generally widely-spaced seismic lines. However, interpreting potential-field data in frontier areas is challenging. Continuous gravity coverage is only available from satellite-altimetry-derived data, but the resolution of these data is often not sufficient for detailed geological interpretation and the data are subject to error in areas of shallow water or close to the coastline. Shipborne data provide higher-resolution data along track, but the sparsity of ship-tracks means that line levelling is difficult. Modelling gravity data to test seismic interpretations of sediment thickness is further complicated by poor constraints on the depth to the Moho. Efforts to understand frontier basins could be improved with better knowledge of the Moho (e.g. from seismic refraction data) and by better ship-track coverage. Extensive acquisition of airborne gravity and magnetic data over Australia?s margins would also provide better coverage and provide a seamless link between offshore and onshore areas.

A CSEM case study in Southeast Asia

SUMMARY This case study presents the CSEM results of 3D datasets acquired over three prospects in a frontier deepwater area in Southeast Asia. The survey was performed as part of the requirements for the drilling campaign in order to mitigate exploration risk. To obtain an understanding of the subsurface resistivity distribution, the acquired CSEM data were subjected to basic processing and inversion before further interpretation. Resistive features corresponding to the anticipated prospect outlines are observed in the attribute analysis and unconstrained 3D isotropic inversion results. Subsequently, post inversion modelling suggests that localized resistors are clearly required in the target area to explain the measured data for two out of the three prospects. Finally, the CSEM results obtained have provided useful input in conjunction with other G&G data for firming-up the drilling priority between the prospects.

New insights on Upper Cretaceous stratigraphy and sedimentology of the Bight Basin, Australia from IODP Site U1512

The Bight Basin, on Australia’s southern margin, is one of the world's most prospective deepwater frontier basins. The 10 offshore wells drilled in the basin had limited success or yielded disappointing results. There has been a strong dependence on seismic data to interpret stratal ages and the regional depositional history because of the limited number of wells, which are all in the more proximal region. In October 2017, the International Ocean Discovery Program Expedition 369 drilled a hole at Site U1512 that straddled the Australian Geological Survey Organisation Survey s065 line 06 on the continental slope, ~67 km south-east of the Jerboa 1 well. The recovered core is the most extensive lithological dataset acquired from the basin and consists of a 10 m thick Pleistocene ooze overlying a 690 m succession of Turonian–Santonian strata. The Cretaceous strata consist of silty claystone with a few thin beds of glauconitic and sideritic sandstone (<32 cm thick). The Tiger Supersequence is substantially thicker than had been anticipated. Preliminary palynofacies analysis indicates a prevailing dysoxic marine environment, with the assemblage dominated by phytoclasts (40–90% of the assemblage). This may have been a consequence of high rates of freshwater runoff into the restricted basin. Rapid sedimentation rates (up to 260 m/Myr), the silt content (2–25%) and the palynofacies suggest the strata were deposited primarily by hyperpycnal and hypopycnal flows. These new datasets will provide a means to re-evaluate the palaeogeography of the basin and its resource potential.

Riser-System Design in Water Depths Greater Than 3000 m

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25840, “Frontier Deepwater Developments: The Impact on Riser-System Design in Water Depths Greater Than 3000 m,” by N. Saglar, B. Toleman, and R. Thethi, 2H Offshore, prepared for the 2015 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed. The offshore industry anticipates the need for production-riser systems in ultradeepwater fields. The development of these fields [this paper considers a field located in the central Gulf of Mexico (GOM)] leads to many challenges with respect to the selection of the riser concept; in some instances, such applications may require extending riser technology beyond its current limits. This paper evaluates the feasibility of a number of production-and export-riser configurations for ultradeepwater applications. Riser-Wall-Thickness Sizing Please note that riser-design criteria, methodology, and data (riser functions and associated pipe sizes; riser internal-fluid properties; and riser-strength assessment) are provided in the complete paper. Production Risers. Steel-catenary-riser (SCR) wall-thickness sizing is initially carried out when considering X65 line pipe. For a design pressure of 5 ksi, the wall thickness of the production riser is primarily driven by collapse because of external hydrostatic pressure. The maximum wall thicknesses required for 8-, 10-, and 12-in. pipes are 1.51, 1.85, and 2.17 in., respectively, and are driven by burst owing to the 15-ksi internal design pressure. It should be noted that these wall thicknesses are designed to resist only the burst and collapse pressures. The longitudinal-load and combined-load design checks are performed after the sizing is performed for collapse and burst. For ultradeep water, the longitudinal-load design criterion becomes a limiting requirement. For 3000-m water depth, the production risers meet both the longitudinal-load and combined-load design criteria. Buckling caused by combined bending and external pressure is also checked with the calculated wall thicknesses. The allowable bending strains of all the production risers are determined to be greater than the assumed maximum bending strain of 0.5%. The field-proven thickest wall to date for conventionally welded X65 single-pipe wet-tree production-riser systems is 1.65 in. In this paper, the maximum wall thickness that can be welded for offshore fatigue-sensitive riser systems is assumed to be 1.9 in., on the basis of existing tests. Only the wall thickness required for a 12-in. production riser with a design pressure of 15 ksi exceeds the 1.9-in. limit. Export Risers. SCR wall-thickness sizing is initially carried out considering X65 line pipe with a design pressure of 5,000 psi. The wall thickness of the export riser is first calculated to resist the burst and collapse pressures. It is determined that the wall thickness required for collapse is higher than the sizing based on burst for all water depths and outer diameters. However, the wall thickness driven by collapse does not meet the 0.5% allowable bending strain considering the combined bending and external-pressure criterion. The wall thicknesses of the export risers are increased to maintain the allowable bending strain of 0.5% in the pipe. Therefore, the wall thickness of the export risers is driven primarily by buckling because of the combined bending and external-pressure criterion. The wall thicknesses of the export risers are shown in Fig. 1. The maximum wall thicknesses required for 16-, 20-, and 24-in. pipes are 1.55, 1.95, and 2.32 in., respectively, and occur at a water depth of 4500 m. When considering the longitudinal load from the static tension in the flooded condition at the top of the riser in water depths of at least 3750 m, the effective tension exceeds the 60%-of-yield tension capacity. For ultradeep water, the longitudinal-load design criterion becomes the limiting requirement.

Pipe technology and installation equipment for frontier deep water projects

Project perspectives in new offshore districts are targeting water depths of 3000–4500m in open ocean. Field development is often located in the proximity, not far from the toe of the continental slopes. In many circumstances the preferred option for exporting the products is the subsea pipeline, routed across the complex features of the continental slopes. Export pipelines from such fields are therefore large diameter pipes with thick walls to meet deep water strength criteria. Current projects show that material and linepipe technology are at the upper bound of what can be produced within the stringent criteria imposed by the application. Installation implies heavy lay spans that require large vessels as well as high capacity handling and pipe lay equipment. Specific upgrading of existing lay vessels cannot exceed certain limits and proven technology as high strength steel wire cables cannot implicitly provide adequate answers to the needs. Further, in case of huge fields, the development is progressive and the early pipelines include In-Line Structures that allow to accomodate future links to adjacent fields. The challenge is to lay along routes where features and bottom roughness require careful procedures to meet the established targets e.g. specific location of subsea structures in relation to pipeline alignment and their verticality.In this paper new solutions backed by advanced engineering tools are presented and discussed. Attention is paid to the installation of pipelines and heavy structures in ultra-deep water.

Technology Focus: Deepwater Projects (May 2015)

Technology Focus As the oil and gas industry pushes into deeper water, more-complex environments, and frontier unproduced areas, the technical and nontechnical risks related to appraisal and development of deepwater projects are likely to continue to increase substantially. While the technical challenges related to deepwater developments are significant— perhaps more significant and critical to the venture success—it is important that the nontechnical aspects of managing a new development in a frontier area be incorporated at the onset. After the successful discoveries in deepwater basins across the globe in west Africa, the North Sea, the Gulf of Mexico, Brazil, and elsewhere, operators are using the lessons learned and technologies developed in these fields to explore other frontier deepwater fields. The exploration in deep water becomes complex on the basis of various factors, such as water depth, geological formations, weather conditions, lack of oilfield infrastructure, and material and tools availability. The definition of deep water may vary with operators, but one definition of a deepwater field is any area of exploration where the water depth is greater than 150 m and there is a subsea blowout preventer. NORSOK defines deep water as water depth in excess of 600 m. Deep water may range from 600 to 3000 m, and ultradeep water is anything deeper than that. Deepwater operations create several additional challenges that need to be addressed in the design phase. Some of these, such as low temperatures at seabed, shallow flow hazards, and possible hydrates, are problems that are most commonly associated with deepwater operations. Other challenges, such as low fracture gradients and proper mud removal for cement placement and zonal isolation, are also common in nondeepwater environments; however, these become more complex, more significant, and more difficult to manage in deep water. There is no question that deepwater production will play a very important part in meeting the world’s future energy demand. The challenge for the oil and gas industry is to meet this demand safely, efficiently, and profitably. This is not an easy challenge in deep water, given the limited margin for error. The technical complexity and multibillion-dollar development costs require a robust development strategy that allows a project to deliver the promised value within the constraints of time. JPT Recommended additional reading at OnePetro: www.onepetro.org. OTC 25135 Deepwater Development Strategy by Martijn Dekker, Shell, et al. OTC 25443 50 Reservoirs, 48 Well Slots, and Two TLPs—Maximizing Recovery From the Deepwater Prolific Mars Field by Derek Newberry, Shell SPE 169245 Overcoming Ultradeepwater Cementing Challenges.in.the Caribbean by N. Gupta,_Schlumberger, et al. SPE 170286 A Novel Approach in Locating Single Loss Zone During Deepwater Drilling With Distributed- Temperature Measurement by Yuanhang Chen, The University of Tulsa, et al.

Producing pore pressure profiles based on theoretical models in undrilled, deepwater frontier basins

A working petroleum system was established on the shelf in offshore Labrador with the Bjarni H-81 discovery in 1973 in the Hopedale Basin. The same reservoirs as those targeted on the shelf are present in the deep water, which is currently receiving attention as the result of newly acquired seismic data. To date, only a very small number of wells have been drilled in the deep water, i.e., Blue H-28, Orphan Basin, and none off mainland Labrador. The wells that were drilled in the deep water had encountered significant overpressure, e.g., kicks that indicated overpressures of 26,850 kPa in the Mid-Cretaceous. Therefore, it was reasonable to assume that pore pressures be similarly high for any new deepwater prospects identified. To help reduce the risk in unexplored environments, we developed an approach that can be adopted to model pore pressure in deepwater settings, with Labrador as the main case study area featured, but also we discussed other global examples such as the Vøring Basin, Mid-Norway. Our results indicated, as a first approximation, that seismic velocity-based pore pressures in shale-rich intervals were similar to the geologic model down to the Lower Tertiary. Deep lithologies were, by regional analogue, likely affected by cementation that will act to preserve overpressure generated by disequilibrium compaction by reducing permeability but will not generate additional pore pressure. The cements (and any carbonate or volcanic lithologies) will, however, result in faster shales and will underpredict pore pressure by mimicking low porosity. A theoretical or “geologic modeling” approach can be used to sense-check any pore pressure interpretation from seismic velocity. The geologic approach also can be used to assess the risk for mechanical seal failure by allowing for estimates of the pore pressure, and related fracture pressure, to be made without the effects of cementation that affect the logs and seismic velocity data.

Can E&P Cut Costs Grow Stronger?

The E&P sector faces the seemingly conflicting imperatives, to cut costs in response to the supply glut and low natural gas and liquids prices, but also, to invest to meet the world's longer term needs for roughly 40 MMb/d of new liquids production by 2030. Moreover, some of this growth must come from higher-cost resources, such as deep-water projects, oil sands, and difficult international frontiers. A cost transformation that is premised on an appropriate capabilities-driven strategy can resolve the seemingly conflicting imperatives - to cut costs, and to invest in growth.

E&P Notes (August 2014)

E&P Notes ’High-Pressure/High-Temperature BOP Equipment Becoming a Reality’ The offshore industry has taken another step toward opening up new deepwater frontiers to exploration with Maersk Drilling ordering the first 20,000-psi blowout preventer (BOP) made by GE Oil and Gas. The BOP is expected to be delivered in the first half of 2018 and is part of a multiyear collaboration between Maersk and BP to design a new generation of offshore drilling rigs for deepwater basins dubbed “20K Rigs.” The ultimate goal is to enable the development of highpressure/ high-temperature reservoirs with pressures up to 20,000 psi and temperatures as high as 350°F. The technical limit of the highest-rated BOPs in operation today is 15,000 psi and 250°F. BP believes that with the 20,000-psi BOPs, and other technologies in development, it will be able to develop fields that may add an additional 10 billion to 20 billion BOE across its portfolio. ’Refracturing Success Demands a Better Understanding of Past Failures’ Refracturing older unconventional wells is likely to reward those willing to investigate the reasons why production declines and what can be done to restore it, according to George King, distinguished engineering adviser at Apache Corp. King talked about what has been learned from refracturing wells, and why companies need to invest in answering the questions that remain unanswered in this young branch of the exploration and production (E&P) business. “We are going to have to look for better ways of fracturing initially and refracturing these wells,” he said during a webcast, which can be found under online events at SPE.org. ’US Approves BP's use of Unmanned Aerial Vehicles in Alaska’ In June, the United States Federal Aviation Administration (FAA) issued the first approval for the overland use of unmanned aerial vehicles (UAVs) in Alaska. The authorization was granted to BP and UAV maker AeroVironment for aerial surveys of roads and pipelines in Alaska’s prolific North Slope oil fields. Last year, the FAA issued a more restrictive approval to BP and ConocoPhillips that allowed the companies to fly UAVs over Arctic waters, and only during optimal conditions. BP and AeroVironment carried out the first approved flight on 8 June, using a Puma AE, a hand-launched vehicle that is 4.5 ft long with a 9 ft wingspan. BP intends to use the lightweight UAV for “high-accuracy” land surveys and for map making to identify maintenance requirements on roads and infrastructure. “The (unmanned aerial system) technology has potential to improve safety, efficiency, and the reliability of BP’s Alaska North Slope infrastructure and maintenance programs,” said Dawn Patience, a BP spokesperson. ’BHP Billiton Testing New Methods To Maximize Returns on Completions’ Running a shale exploration and production operation requires a sharp focus on costs, but not all are measured the same. BHP Billiton’s method for evaluating the cost of drilling an unconventional well is different from the one used to gauge the cost of completing one. The difference reflects the potential production upside of spending more to fracture formations more effectively compared with drilling. BHP is seeking ways to create more productive fracture networks by manipulating the stresses in the rock between wells, and seeking efficient ways to go back into older wells without the cost of the hardware needed for the initial fracturing work. ’Saudi Aramco Wants Fields Fully Smart by 2017’ Saudi Aramco’s new strategy aims to implement its intelligent field (I-Field) concept in all its upstream operations by 2016-2017, according to a source close to the company. The move is part of the company’s efforts to be more proactive in field management and move toward a vision of autonomous fields. “All of Saudi Aramco’s fields are set to be intelligent by 2016- 2017,” the source said. Saudi Aramco is considered one of the leading national oil companies to adopt a smart field initiative through the I-Field concept, which integrates real-time data in its upstream business processes. It currently has 19 I-Fields underway. ’Saudi Aramco Aims to Slash Costs’ Saudi Aramco is working on slashing the production cost of tight formations to around USD 2 to USD 3 per thousand cubic feet in the next couple of years, according Adnan Kanaan, manager of the Gas Reservoir Management Department (GRMD) at Saudi Aramco. Kanaan said that his company expects to reach its target that may lead to a break-even cost that would equal the best unconventional plays in the US. “We are seeing good signs from the sandstones and good costs in our drilling and completions,” Kanaan said during the 21st World Petroleum Congress held recently in Moscow.

Technology Focus: Offshore Drilling and Completion (April 2014)

Technology Focus As the saying goes, “Necessity is the mother of invention.” And never were truer words spoken regarding the oil field and new frontiers. Indeed, as the industry significantly increases the number of work fronts in both the established and the new deepwater frontiers, ever-more-innovative approaches are being developed to address the challenges faced. However, innovation in isolation is not sufficient. As we push the envelope of application, it is a necessity that the equipment and approaches being applied be fit for purpose, robust, and engineered. In support of this, while a model is a useful tool and plays a role as part of a development process, such complex engineering can best be implemented efficiently through obtaining actual performance data, which may then be used as a basis for improvement and expanded qualification. Data play a key role in two distinct and principal areas of technology development: data that are obtained and used to demonstrate the initial qualification (surface) and in-situ performance (deployed) data that are used to calibrate simulations and models and to allow further efficiencies to be securely achieved. As a technical advisor in hydraulic fracturing and unconventionals, I fully appreciate the plan/do/measure/learn cycle because this is fundamental to our overall efficiency. However, deepwater drilling and completion operations are quite different from those in unconventionals. With few wells and much higher costs, the statistical multiwell approaches taken onshore with unconventionals simply do not apply to deepwater efforts. While approximately 20,000 unconventional wells are drilled per year in North America, fewer than 200 deepwater wells have been drilled in the Gulf of Mexico to date. This makes each opportunity to gather data in deep water particularly valuable. And the key to maximizing industry efficiency will be to make sure that data gathering is part of our everyday business. Of course, this is best achieved by embedding the opportunities to gather such data within our standard practice. In this way, we improve incrementally. The following papers provide just a small snapshot of the areas in which incremental improvements are being achieved, allowing the deepwater drilling and completions envelope to be pushed further. It is very likely that such data-driven innovation will continue to be the lifeblood of the business. JPT Recommended additional reading at OnePetro: www.onepetro.org. OTC 24275 Real-Time Drilling-Data Diagnosis Implemented in Deepwater Wells—A Reality by R.A. Gandelman, Petrobras, et al. OTC 24081 Concept Alternatives and Feasibility Analyses of Deepwater Dual-Gradient Drilling-Riser Systems by Atul Ganpatye, Stress Engineering Services, et al. SPE 166554 Low Cycle Fatigue Analysis of Threaded Connectors for Subsea Drilling and Production by B. Zhu, GE Oil and Gas, et al. SPE 166589 Structural Response Monitoring of Huntington HP Drilling and Completion Riser by A. Rimmer, 2H Offshore Engineering, et al.

Petroleum geological summary of the 2012 offshore acreage release for petroleum exploration

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2012, 27 areas in nine offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or twelve months after the release date, i.e. 8 November 2012 or 9 May 2013, depending on the exploration status in these areas and on data availability. As was the case in 2011, this year’s Release again covers a total offshore area of about 200,000 km2. The Release Areas are located in Commonwealth waters offshore Northern Territory, Western Australia, South Australia, Victoria and Tasmania (Fig. 1). Areas on the North West Shelf feature prominently again and include under-explored shallow water areas in the Arafura and Money Shoal basins and rank frontier deep water areas in the outer Browse and Roebuck basins as well as on the outer Exmouth Plateau. Following the recent uptake of exploration permits in the Bight Basin (Ceduna and Duntroon sub-basins), Australia’s southern margin is well represented in the 2012 Acreage Release. Three new areas in the Ceduna Sub-basin, four areas in the Otway Basin, one large area in the Sorell Basin and two areas in the eastern Gippsland Basin are on offer. Multiple industry nominations for this Acreage Release were received, confirming the healthy status of exploration activity in Australia. The Australian government continues to support these activities by providing free access to a wealth of geological and geophysical data.

Geology and petroleum prospectivity of the deepwater Otway and Sorell basins: new insights from an integrated regional study

The frontier deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania at the eastern end of Australia’s Southern Rift System. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic. The complex structural and depositional history of the basins reflects their location in the transition from an orthogonal–obliquely rifted continental margin (western–central Otway Basin) to a transform continental margin (southern Sorell Basin). Despite good 2D seismic data coverage, these basins remain relatively untested and their prospectivity poorly understood. The deepwater (> 500 m) section of the Otway Basin has been tested by two wells, of which Somerset–1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell–1. As part of the federal government-funded Offshore Energy Security Program, Geoscience Australia has acquired new aeromagnetic data and used open file seismic datasets to carry out an integrated regional study of the deepwater Otway and Sorell basins. Structural interpretation of the new aeromagnetic data and potential field modelling provide new insights into the basement architecture and tectonic history, and highlights the role of pre-existing structural fabric in controlling the evolution of the basins. Regional scale mapping of key sequence stratigraphic surfaces across the basins, integration of the regional structural analysis, and petroleum systems modelling have resulted in a clearer understanding of the tectonostratigraphic evolution and petroleum prospectivity of this complex basin system.

Challenges in the use of potential field data for studies of remote, deep-water frontier basins

Challenges in the use of potential field data for studies of remote, deep-water frontier basins

Oil and the Deepwater Frontier

Oil and the Deepwater Frontier

New exploration opportunities on the southwest Australian margin—deep-water frontier Mentelle Basin

Acreage release by the Australian Government in 2010 offers exploration opportunities in the frontier Mentelle Basin for the first time. The Mentelle Basin is a large deep-water basin on the southwest Australian margin. It consists of a large, very deep water (2,000—4,000 m) depocentre in the west and several depocentres in the east, in water depths of 500–2,000 m. The major depocentres are estimated to contain 7–11 km of sediments. Initial rifting in the Mentelle Basin occurred in the Early Permian, followed by thermal subsidence during the Triassic to Early Jurassic. In the Middle Jurassic renewed extension led to the accumulation of very thick sedimentary successions in half-graben depocentres. Early Cretaceous continental breakup was accompanied by extensive volcanism resulting in a thick syn-breakup volcanic succession in the western Mentelle Basin. Assessment of the petroleum prospectivity of the Mentelle Basin is based on correlations with the adjacent Vlaming Sub-basin. These correlations suggest that the Mentelle Basin depocentres are likely to contain multiple source rock intervals associated with coals and carbonaceous shales, as well as regionally extensive reservoirs and seals within fluvial, lacustrine and marine strata. Petroleum systems modelling suggests that potential source rocks are thermally mature and commenced generation in the Early Cretaceous. The Mentelle Basin offers a wide range of play types, including faulted anticlines and fault blocks, sub-basalt anticlines and fault blocks, drape and forced fold plays, and a large range of stratigraphic and unconformity plays.

Deepwater Completions Offer Great Potential

Guest editorial Deepwater E&P is a growing part of the world's energy supply. Estimates are that deepwater production will grow 78% by 2011, making it one of the leading growth sectors in our industry. The explanation is simple: many of the world's largest untapped reservoirs are in deep water. The "golden triangle" of the Gulf of Mexico, offshore Brazil, and west Africa are joined by newer areas of opportunity in India, Malaysia, Australia, the eastern Mediterranean, offshore Norway, and eastern Canada. There are even more promising possibilities in the salt and subsalt reservoirs located in the basins of the golden triangle. The industry's definition of deepwater exploration and its technical challenges are expanding along with knowledge of the reserves. Ten years ago, deep water was anything more than 1,500 ft water depth. Today, the deepwater frontier is more than 5,000 ft. The frontier of a decade ago is now practically routine. And along with these greater water depths, operators are facing increasing total well depths and higher temperatures and pressures. The deepwater opportunity comes at a price—the high rig rates and capital intensity make it a high-risk and high-reward proposition. And the enormous technical challenges make deepwater wells a focal point for developing and deploying advanced technology in every aspect of well construction and production. Completions technology brings operators more production, lower costs and lower risks, and holds the promise of enabling the future production the world demands. What follows is a snapshot of the deepwater completions picture, with emphasis on those areas that will contribute most to operators’ success. All these elements are interrelated and complementary. Developments in one area contribute to the effectiveness of the others. Ultimately, it is the integrated development of all aspects of deepwater completions that promises to make possible the production the world is counting on over the next several years. High-Rate Fracturing Systems Stimulating production through hydraulic fracturing is a proven way of making deepwater wells economical. Frac packs of long, thick unconsolidated producing intervals in turn depend on the ability to pump frac fluid at a high rate and place proppant in large quantities. Tools and techniques that make access to these zones profitable include using hydrostatic properties of frac fluids to increase bottomhole fracture pressure without unsafe surface treating pressures. This helps achieve the high pressure needed for the fracture without exceeding the pressure rating of surface equipment. Also, tool systems using carbide-protected crossover tool designs are now able to withstand the large volumes of proppant at high rates needed to capitalize on the high-rate fluid pumping. These technologies are valuable in their own right, and they are crucial to the development of single-trip multizone completions.