High-resolution 3D Seismic Surveys Research Articles

Segmentation and lateral growth of intracratonic strike-slip faults in the northern Tarim Basin, NW China: influences on Ordovician fault-controlled carbonate reservoirs

Intracratonic strike-slip faults have been recognized as a major factor controlling the formation of fracture-cave carbonate reservoirs in deep buried basins, yet which properties and how the strike-slip faults influence reservoir distribution and their connectivity are still ambiguous. This uncertainty significantly restricts hydrocarbon exploration and development, such as in the Fuman oilfield, northern Tarim Basin, NW China. Using a high-resolution 3D seismic reflection survey and borehole data, we investigated the geometry and kinematic evolution of the FI17 fault zone in the Fuman oilfield. This fault zone is characterized by a single fault zone, pop-up or pull-apart structures, right-stepping en echelon normal faults, and much smaller displacement (<30 m) normal fault arrays from bottom to top. The FI17 fault zone consists of four genetic segments, including the extensional strike-slip duplex, Riedel left-lateral shear, right-stepping horsetail splay, and horizontal slip segments in map view. In particular, the formation of the ∼18 km Riedel shear zone is characterized by the growth and linkage of segmented shear faults (synthetic and secondary synthetic shears). We observed that the large-scale fault-controlled fracture-cave reservoirs are distributed in positions with wider fault zones, which are characterized by overlapping of neighboring secondary shear faults. Furthermore, the reservoir width examined in this study is natural logarithmic correlated (positively) to the fault zone width. The reservoirs linked by the same shear faults show better internal connectivity. The spatial coherence between fault geometry and reservoir features indicates that segmentation and lateral growth of intracratonic strike-slip faults controls the occurrence of fracture-cave reservoirs, which may provide support for reservoir prediction in the Fuman oilfield and other deeply buried fault-controlled carbonate reservoirs in general.

Strike-slip overprinting of initial co-axial shortening within the toe region of a submarine landslide and a model for basal shear surface growth: a case study from the Angoche Basin, offshore Mozambique

Submarine landslides (slides) are some of the most voluminous sediment gravity-flows on Earth and they dominate the stratigraphic record of many sedimentary basins. Their general kinematics and internal structure are relatively well-understood. However, how slides increase in volume and internally deform as they evolve, and how these processes relate, in time and space, to the growth of their basal (shear) zone, are poorly understood. We here use three high-resolution 3D seismic surveys from the Angoche Basin, offshore Mozambique to map strain within a shallowly buried, large, and thus seismically well-imaged slide ( c. 530 km 3 ). We document several key kinematic indicators, including broadly NW-trending lateral margins and longitudinal shears bounding and within the slide body, respectively, and broadly NE-trending symmetric pop-up blocks in the slide toe. Approximately 7 km downdip of the slide toe wall, thrusts and related folds also occur within otherwise undeformed slope material, with thrusts detaching downwards onto the downslope continuation of the basal shear zone underlying the slide body. Based on the style, trend and distribution of these features, and their cross-cutting relationships, we propose an emplacement model involving two distinct phases of deformation: (i) bulk shortening, parallel to the overall SE-directed emplacement direction, with contractional shear strains reaching c . 8%; and (ii) the development of broadly emplacement direction-parallel shear zones that offset the earlier-formed shortening structures. We infer that the contractional strains basinward of the slide body formed due to cryptic basinward propagation of the basal shear zone ahead of, and to accommodate updip sliding and shortening associated with, the entire slide mass. Our study demonstrates the value of using 3D seismic reflection data to reveal slide emplacement kinematics, especially the multiphase, non-coaxial nature of deformation, and the dynamics of basal shear zone growth.

High-Resolution 3D Seismic Imaging of Fault Interaction and Deformation Offshore San Onofre, California

The Inner California Borderland (ICB) records a middle Oligocene transition from subduction to microplate capture along the southern California and Baja coast. The closest nearshore fault system, the Newport-Inglewood/Rose Canyon (NIRC) fault complex is a dextral strike-slip system that extends primarily offshore approximately 120 km from San Diego to Newport Beach, California. Holocene slip rates along the NIRC are 1.5–2.0 mm/year in the south and 0.5 mm/year along its northern extent based on trenching and well data. High-resolution 3D seismic surveys of the NIRC fault system offshore of San Onofre were acquired to define fault interaction across a prominent strike-slip step-over. The step-over deformation results in transpression that structurally controls the width of the continental shelf in this region. Shallow coring on the shelf yields a range of sedimentation rates from 0.27–0.28 mm/year. Additionally, a series of smaller anticlines and synclines record subtle changes in fault trends along with small step-overs and secondary splay faults. Finally, sedimentary units onlapping and dammed by the anticline, place constraints on the onset of deformation of this section of the NIRC fault system. Thickness estimates and radiocarbon dating yield ages of 560,000 to 575,000 years before present for the onset of deformation.

Application of magnetotelluric (MT) study for the identification of shallow and deep aquifers in Dholera geothermal region

In India geothermal energy is still in nascent stage and there are several geothermal regions which are not explored. By exploring these fields India will be able to understand the potential of geothermal energy and its application for power generation and development in other industrial and agricultural sectors. As world is switching from conventional to renewable energy sector, geothermal energy will be one of the most promising alternative for fossil fuels. The Cambay region of West Coast continental margin has enormous geothermal potentials. In this paper one such geothermal zone of Cambay Basin namely Dholera has been explored to understand the potential of the region. An extensive MT survey has been carried out in this region along 6 profile lines and 66 station points. The main aim of the paper is to identify the shallow and deep aquifer zones in the study area for exploitation of geothermal energy which can be used for various societal benefits. In order to explore aquifer potentials MT data was acquired using System2000.net Phoenix Geophysics Ltd. equipment. This is the first high resolution 3D seismic survey was carried out in the study area in order to identify the geothermal sweet spots. Skew, Tipper and Polar diagrams were prepared to understand the dimension of the identified conductive bodies. The interpretation of MT data in the form of geoelectrical maps indicate presence of high conductive zones at 5 km depth extending up to 7 km. This high conductive bodies indicates the presence of aquifers which can be the zone of interest. Drilling will target these zones to exploite geothermal water.

CarbonNet progress towards a declaration of identified storage formation at the Pelican site with a new high-resolution 3D seismic dataset

The CarbonNet project is making the first ever application for a ‘declaration of an identified greenhouse gas storage formation’ (similar to a petroleum location) under the Offshore Petroleum and Greenhouse Gas Storage Act. Unlike a petroleum location, however, there is no ‘discovery’ involved in the application. Instead, a detailed technical assessment is required of the geological suitability for successful long-term storage of CO2. The key challenges to achieving a successful application relate to addressing ‘fundamental suitability determinants’ under the act and regulations. At Pelican (Gippsland Basin), a new high-resolution 3D seismic survey and over 10 nearby petroleum wells (and over 1500 basinal wells) supplement a crestal well drilled in 1967 that proved the seal and reservoir stratigraphy. The GCN18A 3D marine seismic survey has the highest spatial and frequency resolution to date in the Gippsland Basin. The survey was acquired in water depths from 15 to 35 m with a conventional eight-streamer seismic vessel, aided by LiDAR bathymetry. The 12.5 m bin size and pre-stack depth migration with multiple tomographic velocity iterations have produced an unprecedented high-quality image of the Latrobe Group reservoirs and sealing units. The 3D seismic data provides excellent structural definition of the Pelican Anticline, and the overlying Golden Beach-1A gas pool is excellent. Depositional detail of reservoir-seal pairs within the Latrobe Group has been resolved, allowing a confident assessment of petroleum gas in place and CO2 storage opportunities. The CarbonNet project is progressing with a low-risk storage concept at intra-formational level, as proven by trapped pools at nearby oil and gas fields. Laterally extensive intra-formational shales provide seals across the entire structure, providing pressure and fluid separation between the overlying shallow hydrocarbon gas pool and the deeper CO2 storage opportunity. CarbonNet is assessing this storage opportunity and progressing towards a ‘declaration of an identified greenhouse gas storage formation’.

High-productivity, high-resolution 3D seismic surveys for open-cut coal operations

3D seismic is routinely used for structural characterisation for underground coal operations, however the implementation of this technology for shallow, open-cut resources has been limited. The per...

Direct imaging of alteration with high-resolution hard-rock 3D seismic data at the Darlot Gold Mine

SummaryThe Darlot gold mine is an Archean orogenic deposit located in the world-class gold and nickel terrain of the Yandal granite-greenstone belt within the Yilgarn Craton in Western Australia.In 2016-2017, HiSeis designed, acquired and processed a high-resolution 3D seismic survey centred on the Darlot-Centenary mineralised system with the objective of improving lithological and structural interpretation of the project area and to support targeting of mineralisation.The capability of modern 3D seismic surveys to image formational contacts and structures in hardrock environments has had a game-changing impact on the effectiveness of brownfields exploration programs because the geometry of mineralised systems can now be directly imaged over large volumes of ground. More specifically, partially-preserved relative seismic amplitudes can allow the direct imaging of alteration associated with gold mineralisation in fertile structures, allowing discrimination between these and barren structures and dramatically improving drilling success rates.We present the results of a structural interpretation of the seismic data which focused on identifying drilling targets prioritised with seismic amplitude variation.

Can high-resolution reprocessed data replace the traditional 2D high-resolution seismic data acquired for site surveys?

Can high-resolution reprocessed data replace the traditional 2D high-resolution seismic data acquired for site surveys?

Utilization of AEM Methods for Cost-Effective Mapping of Shallow Neogene Intra-Plate Fault Systems in Eastern Australian Coal Seam Gas Basins

Neogene fault systems are increasingly recognised as an important control on hydraulic connectivity in some of Australia’s energy rich basins. However, accurate delineation of these faults systems is challenging and expensive. In this context, the main objective of the Exploring for the Future (EFTF) Surat-Galilee Basin (Phase 1) Project is to test novel methods for more cost-effective mapping of Neogene fault systems in the Coal Seam Gas (CSG) basins of eastern Australia. Methods assessed in this project include morphotectonic mapping using temporal remote sensing data and high-resolution terrain mapping techniques, airborne electromagnetics (AEM), and the use of earthquake databases to inform active tectonic and geomechanical analysis. The project is funded by Geoscience Australia (GA) as part of its EFTF Programme, and is focussed on exemplar areas in the Surat and Galilee Basins where Neogene fault activity has been interpreted on high-resolution 2D and 3D seismic reflection surveys. This paper reports on the use of airborne electromagnetics (AEM) for detecting near-surface (<50–150m) Neogene faults in both basins. Approximately 4,500 line km of AEM data were acquired in a number of smaller acquisition blocks where Neogene faults had previously been identified. The AEM inversion results are compared with interpretation of seismic reflection data, morphotectonic mapping, and other hydrogeological and tectonic/geomechanical data. The utility of AEM to map the broader hydrogeological system in these basins, including groundwater-surface water connectivity (springs and rivers), is also assessed.

Geologic significance and optimization technique of sweet spots in unconventional shale systems

Crude oil in unconventional shale systems, present as tight oil and shale oil, accumulates inside an oil kitchen in formations with coexistent sources and reservoirs. Organic matter present in oil shale is not yet mature and requires heating to convert it into crude oil. Oil exploration in shale systems involves the exploration of shale oil retained in source rocks and tight oil rich zones located near source rocks. Tight oil is a type of realistic unconventional oil resources in China. The marked increase in potential shale oil reserves, and exploration of these reserves, will result in a shale oil revolution similar to that experienced for shale gas. Based on a systematic comparison of geologic features of shale systems in the US and China, the geologic significance of the sweet spots in shale systems is proposed. This zone contains an abundance of unconventional oil in shale systems that can be explored and developed under current economic and technical conditions. The sweet spot zone refers to the zone in the tight oil rich zone which has industrial value within the scope of matured high-quality source rocks on the plane. The sweet spot interval refers to the high-productivity interval of tight oil which has industrial value through artificial stimulation. The main aim of oil exploration in shale formations is to identify the sweet spots. The distribution of the economic sweet spots in shale systems is evaluated by overlapping the geologic, engineering and economic sweet spots. Resource assessment techniques, the identification of logging data properties, high-resolution 3D seismic surveys, horizontal well production from well pads, and artificial reservoir development of sweet spots in oil-bearing shale formations can assist efficient development of oil. Globally, shale formations contain a significant volume of oil reserves. Currently, stimulated reservoir volume (SRV) techniques in horizontal wells in marine shale gas formations in the United States have average peak-productivity cycles of 10–15 years. To achieve commecial oil production in lacustrine shale systems in China, it is important to utilize large formation thicknesses and the high abundance of organic matter. In addition, the development of practical and economic techniques will result in an increase of productivity of tight oil and shale oil by 30–50 million tons, as well as the economic development of oil in lacustrine shale systems in China.

Why 3D seismic data are an asset for exploration and mine planning? Velocity tomography of weakness zones in the Kevitsa Ni-Cu-PGE mine, northern Finland

Kevitsa is a disseminated Ni-Cu-PGE (platinum group elements) ore body in northern Finland, hosted by an extremely high-velocity ([Formula: see text]) ultramafic intrusion. It is currently being mined at a depth of approximately 100 m with open-pit mining. The estimated mine life is 20 years, with the final pit reaching a depth of 500–600 m. Based on a series of 2D seismic surveys and given the expected mine life, a high-resolution 3D seismic survey was justified and conducted in the winter of 2010. We evaluate earlier 3D reflection data processing results and complement that by the results of 3D first-arrival traveltime tomography. The combined results provide insights on the nature of some of the reflectors within the intrusion. In particular, a major discontinuity, a weakness zone, is delineated in the tomography results on the northern side of the planned pit. Supported by the reflection data, we estimate the discontinuity, likely a thrust sheet, to extend down approximately 600 m and laterally 1000 m. The weakness zone terminates prominent internal reflectivity of the Kevitsa intrusion, and it is associated with the extent of the economic mineralization. Together with other weakness zones, a couple of which are also revealed by the tomography study, the discontinuity forms a major wedge block that influences the mine bench stability on the northern side of the open pit and likely will cause more issues during the extraction of the ore in this part of the mine. We argue that 3D seismic data should routinely be acquired prior to commencement of mining activities to maximize exploration efficiency at depth and also to optimize mining as it continues toward depth. Three-dimensional seismic data over mineral exploration areas are valuable and can be revisited for different purposes but are difficult to impossible to acquire after mining has commenced.

Offshore CO2 Storage Resource Assessment of the Northern Gulf of Mexico

Research programs recognize the need to further develop offshore storage resources for successful global deployment of CCUS. The inner continental shelf of the northwestern Gulf of Mexico is especially prospective because it has abundant available geologic data accumulated from decades of hydrocarbon exploration near many large point sources of industrial CO2. An ongoing study on the upper Texas coast to Vermilion Bay (western Louisiana) assesses prospective geologic storage resources for the approximately 8,000 square mile study area. The study, encompassing state and federal waters, utilizes 1) existing rock samples (e.g., whole cores), 2) well logs, and other data from existing or P&A wells and 3) available 2D, a convention regional 3D and a high resolution 3D seismic surveys to assess storage resources (e.g., faults, reservoir and seal units, etc.). The study utilizes the available geologic data resources to 1) assess the CO2 storage capacity of depleted oil and natural gas reservoirs, and 2) assess the ability of saline formations in the region to safely and permanently store nationally-significant amounts of anthropogenic CO2. The study also seeks to identify at least one specific site with potential to store at least 30 million metric tons of CO2 that could be further considered in the future for a commercial or integrated demonstration project.

Shallow Geology of the CO2CRC Otway Site: Evidence for Previously Undetected Neotectonic Features?

Australia's CO2CRC Otway Site hosts a carbon capture and storage (CCS) demonstration facility that has, to date, injected over 80,000 tonnes of CO2 into two separate geological reservoirs. The reservoir geology is well understood and the site has been the subject of several seismic investigations, though relatively little is known about the near-surface geology and how potential leaks from the injection wells would migrate, particularly within the Port Campbell Limestone. No shallow core has been taken from relevant petroleum wells or water bores, and although there is extensive exposure in the prominent sea cliffs, these are mostly inaccessible. In order to further define the structure and geology of the Port Campbell Limestone at the Otway site, a high-resolution, shallow focused, 3D seismic survey has recently been conducted. The assessment of the near-surface geology described in this paper was used to assist with planning the survey. Using available data, the Port Campbell Limestone is assessed as a series of laterally continuous intercalated limestone, marl, and marly limestones. Interpretation of three previously acquired 3D seismic surveys using a minimum similarity attribute demonstrates evidence for a shallow, steeply east-dipping fault striking approximately NNW-SSE directly below the Otway site. This is observed from approximately 100 m to 380 m depth below surface, where it appears to die out. In the shallow section, the fault is undetectable primarily due to low seismic resolution, and so it is unknown how shallow it propagates. Extrapolation of the fault to the surface projects to between the wells Naylor-1 and CRC-1. A recently acquired high-resolution 3D seismic survey over the study area will allow for this fault to be further delineated.

Tapping Difficult Oil in a Giant Carbonate Field in Qatar

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18296, “Tapping the Difficult Oil and Enhancing Reservoir-Development Strategy To Maximize Recovery From a Mature Waterflood Giant Carbonate Field in the Middle East: Arab C Reservoir, Dukhan Field, State of Qatar,” by Mohamed Naguib Bin Ab Majid, Carlos Troconiz, Mohammed Nedham Al-Shafei, Gheorghe Luca, and Ariel Cachi, Qatar Petroleum, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. After 70 years of production, more than 30% of the Arab C reservoir stock-tank original oil in place has been recovered through various mechanisms including natural depletion, waterflooding, gas lift implementation, and horizontal-well development. Extending production into future years requires a strategic approach focusing on innovative development to target the remaining oil saturation. Integration of a recently acquired, high-resolution 3D-seismic survey complements the data available for subsurface description and characterization, positively affecting reservoir-model history-matching metrics. Introduction The large, mature Dukhan field is located onshore Qatar, approximately 80 km west of Doha. The Arab C reservoir interval is a carbonate anticlinal structure lying 5,500 to 7,000 ft below the surface. Areally, the Arab C reservoir has been divided into four structural elements from north to south (i.e., Khatiyah, Fahahil, Jaleha, and Diyab). The first three sectors comprise the continuous oil-bearing extent of the reservoir, while Diyab is water-bearing on the basis of results from wells drilled to date (Fig. 1). Arab C is an undersaturated-oil reservoir. The original oil column ranged from 1,400-ft thickness in the Khatiyah sector to 400 ft in the Jaleha sector. It has a weak to moderate connected aquifer lying below the oil column. Arab C development started with vertical wells, initially completed openhole. Increase in water production led to a well-completion-scheme change; vertical wells were then completed cased-hole and perforated selectively. Horizontal drilling commenced in 1992 to improve recovery and enhance production. As the water front from injection progressed, gas lifting in Arab C was initiated in 2003 to continue producing the high-water-cut wells. Currently, 60% of the Arab C producers are flowing under gas lift assistance. Reservoir Description Arab C is a heterogeneous organization of limestone and dolomite lithologies deposited on a shallow-water Jurassic ramp system. Hydraulically, the 80-ft-thick interval represents a net-work of grainstone conductors compartmentalized by muddy carbonate baffles resulting in layer-constrained dynamic behavior. Lateral ranges of 1 to 4 km for baffling thin beds support a localized layer-constrained dynamic behavior and a high degree of vertical heterogeneity, though communication pathways are impacted by sporadic occurrences of cross-cutting conductive and resistive faults. Reservoir porosity is 15 to 20%, and the average permeability is approximately 150 md, but this varies widely on the basis of reservoir zone.

Paleokarst in the Grosmont Formation and reservoir implications, Saleski, Alberta, Canada

We delineated a bitumen-rich paleokarsted carbonate reservoir of the Upper Devonian (Frasnian) Grosmont Formation with a high-resolution 3D seismic survey tied to core and petrophysical log data from 35 wells within a [Formula: see text] study area in northern Alberta, Canada. There were two laterally continuous karst facies: a solution-enhanced vuggy dolostone that resulted from the carbonate dissolution of body fossils and a stratiform breccia that resulted from the dissolution of interbedded evaporites. Three laterally discontinuous karst facies were identified: sinkhole fills, collapsed paleocaves, and solution valley fills. We measured 368 subcircular features (sinkholes and collapsed paleocaves) having a median circle-equivalent diameter of 69 m and representing 5.5% of the total study area. Sinkhole fills include Cretaceous-aged sandstone, mudstone, and coal. Collapsed paleocaves were filled with matrix-supported breccia that had clasts of disoriented blocks of dolomite and a matrix of disaggregated dolomite and Cretaceous-aged mudstone. The paleocaves and sinkholes formed in the solution-enhanced karst facies of the Grosmont C at the interface of an interpreted ancient vadose-phreatic mixing zone. The marine deepwater deposition of the Clearwater Formation during the Albian filled the depressions created by the mechanical collapse of the paleocaves and provided a seal for thermal operations. The fracture density inferred from seismic amplitude variation with angle and azimuth analysis and corroborated by well data showed that fractures are ubiquitous and were enhanced during meteoric karst. The high-vertical permeability resulting from solution-enhanced fractures, the laterally predictable flow units, and a competent seal make this an ideal reservoir for thermal bitumen recovery.

Applications of engineering seismology in urban areas

I present two case studies which describe applications of engineering seismology in urban areas: High-resolution shallow offshore 3D seismic survey for the Bosphorus Subsea Road Tunnel Project, and seismic, geotechnical, and earthquake engineering site characterization for a residential project in Istanbul. In Case study 1, I conducted a 3D high-resolution shallow seismic survey in 2011 to confirm the geometry of the future Bosphorus Subsea Road Tunnel traverse. I processed the data to obtain 3D PSTM and PSDM volumes, and interpreted these image volumes and correlated the interpretation results with the offshore borehole data. With the recoverable signal band of 30–960 Hz, I attained a vertical resolution of less than 1 m.

Interburden mapping using 3D seismic attributes at an underground coal mine, Bowen Basin, Queensland

SUMMARY Six high resolution 3D seismic surveys comprising approximately 31 km 2 were recorded for an underground coal mine in the Permian aged Bowen Basin Central Queensland. The colliery had previously interpreted the data with view to identifying hazards at the mined seam level. The seismic data and an extensive set of borehole data were made available for a Masters Project at the Queensland University of technology with the focus being to study the geology of the interburden. This paper discusses the background to the seismic surveys and the work flow used for the interburden mapping. Conclusions and recommendations are drawn

The application of high-resolution 3D seismic acquisition techniques for carbonate reservoir characterization in China

This paper describes major challenges to seismic acquisition in China's Tarim Basin (Figure 1) and how high-resolution 3D seismic surveys can improve reservoir imaging in this area.

The mechanics of intermittent methane venting at South Hydrate Ridge inferred from 4D seismic surveying

Sea floor methane vents and seeps direct methane generated by microbial and thermal decompositions of organic matter in sediment into the oceans and atmosphere. Methane vents contribute to ocean acidification, global warming, and providing a long-term (e.g. 500–4000 years; Powell et al., 1998) life-sustaining role for unique chemosynthetic biological communities. However, the role methane vents play in both climate change and chemosynthetic life remains controversial primarily because we do not understand long-term methane flux and the mechanisms that control it ( Milkov et al., 2004; Shakhova et al., 2010; Van Dover, 2000). Vents are inherently dynamic and flux varies greatly in magnitude and even flow direction over short time periods (hours-to-days), often tidally-driven ( Boles et al., 2001; Tryon et al., 1999). But, it remains unclear if flux changes at vents occur on the order of the life-cycle of various species within chemosynthetic communities (months, years, to decades Leifer et al., 2004; Torres et al., 2001) and thus impacts their sustainability. Here, using repeat high-resolution 3D seismic surveys acquired in 2000 and 2008, we demonstrate in 4D that Hydrate Ridge, a vent off the Oregon coast has undergone significant reduction of methane flow and complete interruption in just the past few years. In the subsurface, below a frozen methane hydrate layer, free gas appears to be migrating toward the vent, but currently there is accumulating gas that is unable to reach the seafloor through the gas hydrate layer. At the same time, abundant authigenic carbonates show that the system has been active for several thousands of years. Thus, it is likely that activity has been intermittent because gas hydrates clog the vertical flow pathways feeding the seafloor vent. Back pressure building in the subsurface will ultimately trigger hydrofracturing that will revive fluid-flow to the seafloor. The nature of this mechanism implies regular recurring flow interruptions and methane flux changes that threaten the viability of chemosynthetic life, but simultaneously and enigmatically sustains it.

Making the most of mature field opportunities—2009 Cobia infill drilling campaign

The Halibut and Fortescue oil fields are located in the Gippsland Basin, offshore Australia, and have produced 1.3 billion barrels of oil since the 1970s. The fields have been developed from three platforms—Cobia, Halibut and Fortescue—using multiple infill drilling campaigns post initial development. A strong emphasis has been placed on leveraging the latest technology to optimise development of these fields. The advent of high resolution 3D seismic surveys and improved processing techniques have proved invaluable in recent programs. This is illustrated by the 2009 Cobia infill program where the nine wells drilled over six months have increased field production from an average of 4,000 to 20,000 barrels of oil per day. Key success elements for this program included the use of new 3D re-processing technology, the application of past learnings, and the in-house enhancement of 3D data, in addition to seismic modelling and the integration of production data. The maturing of individual leads to economically viable targets used fit-for-purpose analysis of the data in which 3D seismic, well and production data were integrated and later built into 3D geologic models. Location choice was also important to the success of the program, where several potential targets were rejected after failing to meet technical or economic criteria. Drilling performance was exceptional, with all nine wells drilled within budget. The new 2009 Cobia infill wells have already produced over 2.2 million barrels of oil and show how mature fields can be re-invigorated through the use of re-processed 3D seismic and integrated data analysis.