The commitment to use advanced technology, seismic data and geophysical expertise was the backbone of a recent acquisition, processing and interpretation of a large multiclient program in the underexplored Pegasus Basin offshore New Zealand.

Between 2014 and 2016 WesternGeco conducted 2-D and 3-D seismic programs across the East Coast of the North Island and into the basin, adding to one of the largest in the industry’s multiclient libraries.

The seismic acquisition and processing technologies used in the program yielded a complete reinterpretation of stratigraphic and structural features. This provides E&P companies with a new high-quality dataset with which to explore this highly prospective region (Figure 1).

Geological setting and prospectivity

More than 300 known onshore oil and gas seeps occur in the eastern part of New Zealand’s North Island, indicating at least one active petroleum system. Although more than 40 wells have been drilled onshore, only two have been drilled offshore, making this region vastly underexplored.

The eastern margin of the North Island is part of the forearc of the Hikurangi subduction zone, which accommodates oblique convergence between the Australian and Pacific plates. Associated Miocene-Recent compression along the margin has created a northeast-southwest trending fold and thrust belt, with a series of elongated growth structures and adjacent inverted sub-basins with fill that is variable and diachronous.

Primary plays in the region involve fault-bounded anticlines and stratigraphic pinchouts against structural highs. An extensive gas hydrate system also indicates additional potential for gas accumulations trapped beneath the gas hydrate layer.

Both offshore wells drilled to date targeted structural highs adjacent to the Titihaoa sub-basin. In 1994 the Titihaoa-1 well targeted one of the many fault-bounded hanging-wall anticlinal closures along the margin and encountered thinly bedded reservoir-quality Miocene turbiditic sandstones. In 2004 Tawatawa-1, which was drilled 35 km (22 miles) northeast of Titihaoa-1, intersected Miocene thinly bedded siltstones and shales.

The two offshore wells did not find commercial reservoirs, but they did encounter elevated gas readings, suggesting the presence of hydrocarbon charge in the basin. A key target is Neogene clastic reservoir quality rocks, which are present onshore and are suspected also to be offshore. Identifying their presence and extent in the offshore environment is under investigation, and knowledge of the geological setting is crucial to further exploration efforts.

New acquisition and interpretation

The 2-D survey acquired in 2014 provided a much-needed regional perspective and allowed the mapping of major structures. However, a 3-D survey was required to deliver more accurate imaging and positioning in structurally complex areas such as steeply dipping intervals and overhangs.

Understanding the geological challenges was critical as the correct high-end model-building technologies and workflows were applied to completely image the region. Several workflows were used to derive a detailed tilted transverse isotropy (TTI) model, including multiparameter common image point picking, premigration azimuth preservation, steering filters and joint parameter updates.

Multiparameter common image point picking was performed to ensure that complex residual moveout of small-scale velocity anomalies were detected and fed into the tomographic input. Premigration azimuth preservation was used to incorporate ray tracing in the correct azimuth, particularly in acquisition turn areas to confirm the convergence of the velocity updates. A TTI model was selected so that the migration considered the slow and fast velocity direction as well as the dip and azimuth of the complex structures to generate the most accurately positioned depth image.

These technologies used 3-D Kirchhoff prestack depth migration to create a high-quality image of the complex subsurface. As a result, better input data with a more accurate earth model and robust migration algorithms delivered a more accurate final image for interpretation and quantitative analysis (Figure 2).

The 3-D uplift

Figure 2 (bottom) shows the latest uplift in imaging achieved throughout the entire depth section of the 3-D survey. A bottom simulating reflector can be seen marking the base of the gas hydrate stability zone in both the 2-D and 3-D data. Nevertheless, with the 3-D dataset, stratigraphic events near the bottom simulating reflector are clearly trackable through the high-amplitude band. This detail enables shallow intervals to be interpreted with increased confidence and the gas hydrate play to be assessed in further detail.

The high-resolution imaging within the trench-slope basins in the 3-D dataset also offers a more comprehensive insight of sedimentary fill within. Sedimentary units and unconformities can be traced and correlated across individual sub-basins, giving an improved visualization of the interplay of sedimentation and the structural evolution along the margin. Crisper imaging shows finer detail within mass transport complexes, with individual and stacked systems now evident. Faults and folds can be seen within mass transport complexes that act as paleo-flow indicators, assisting in the study of sedimentary fill within individual sub-basins.

Given the areal extent of the survey, scanning through the 3-D volume highlights the evolving degree of deformation along the margin. Starting inboard, the margin is represented by a highly deformed reactivation zone with up to 5-km-thick (3-mile) trench-slope sub-basins composed of syn-subduction sediments. Progressing outward, the mid portion is dominated by a series of imbricated thrust faults and folds with asymmetrical sub-basins forming on the back limb of the folds. The outboard of the imbricated zone is represented by a relatively nondeformed outer portion consisting of long wavelength frontal folds underlain by propagating thrusts.

Even though major structures are visible in the 2-D data, the limitations of 2-D imaging mean that there is little understanding of the deeper portions and the relationship between structures. With the 3-D dataset and the rich low-frequency content, there is a significant improvement in event continuity at depth. As a result, improved interpretability of deeper previously undefined structural elements enables more accurate structural models to be built and the evolution of the margin to be investigated.

The 3-D seismic acquisition and processing technologies give a considerable imaging uplift over the 2-D data and create a platform on which to image and map the structural and stratigraphic elements in detail across the Pegasus Basin. As a result, E&P companies can conduct more thorough investigations of the subsurface, helping to unlock the full potential of this region.