First Break - Volume 34, Issue 12, 2016

Despite significant discoveries within Palaeogene-age reservoirs (e.g., Mariner) the East Shetland Platform (ESP) is underexplored, with only ten wells per 1000 km2. Mesozoic units are thin or absent whilst Paleozoic reflectors resemble acoustic basement on legacy seismic. Recent 3D dual-sensor broadband surveys (GeoStreamer) covering 17,200 km2 over parts of Quadrants 3, 8-9, 14-16 have allowed for clearer imaging. Here, this dataset is interpreted, leading to new insights into this large frontier region. The ESP petroleum system comprises multiple proven reservoir and source intervals, with viable play fairways. Up to four regional unconformities are interpreted, merging into fewer erosional surfaces on persistent highs. Elsewhere on the ESP, predominantly subsiding Permo-Triassic depocentres contain a nearly continuous Paleozoic-Mesozoic succession. The most prominent of these, to the south and south-west of the Beryl Embayment, is here referred to as the ‘Crawford-Skipper Basin’. Existing hydrocarbon discoveries on the ESP are in the vicinities (<7 km) of intra-platform Permo-Triassic basin margins. Exploration close to such basins is inherently less risky due to possible positive influences of deep-seated structures on the petroleum system. These include: (1) formation of Meso-Cenozoic closures; (2) Devonian source maturity and presence of simple fault-related migration pathways; (3) viability of sub-Cretaceous reservoir-trap-seal configurations.

The offshore Durban and Zululand Basins have recently become of interest to the oil and gas industry as a result of large discoveries made along the eastern margin of Africa, most notably in Tanzania and Mozambique. In South Africa, exploration over the last three decades has focused on near-shore trends of rotated fault blocks and a combination of structural-stratigraphic traps. This has resulted in the drilling of four wells north-east of the city of Durban. Although no wells have been drilled in the deepwater acreage yet, the area is considered to have petroleum potential. As a result of the growing industry interest and with collaboration from Spectrum and the Petroleum Agency of South Africa (PASA), CGG acquired a new multi-client broadband 2D seismic survey (CDZ13-14) in the Durban and Zululand Basins (Figure 1). The data were processed with Kirchhoff pre-stack time migration (PreSTM). The survey was shot and processed in two phases (2013-2014) using BroadSeis, a proprietary broadband solution using variable-depth streamers and advanced imaging technologies, and consisted of 6920 km of 2D lines over held acreage. The survey is made up of 42 lines widely spaced over the Durban and Zululand Basins and includes 17 strike lines and 25 dip lines. Water depths within the area of interest range from 400 m to 3200 m. The results of this broadband 2D survey have shed new light on the interpretation of the geology in the area.

Heterodyne distributed vibration sensing (hDVS) and, more generically, distributed acoustic sensing (DAS) are technologies that rely on traditional fibre-optic cables to provide inline strain measurement. In recent years, hDVS has found application in seismic monitoring; in particular vertical seismic profiling (VSP) greatly benefits from the advantage of using permanent fibres cemented behind casing (Mateeva et al., 2013). VSP measurements were also demonstrated using fibre installed on production tubing (Barberan et al., 2012) and deployed within a wireline cable (Hartog et al., 2014). Another potential application for hDVS is flow monitoring, where, owing to the fibre’s large spatial coverage, it is possible to monitor vibrations and waves along the length of the well. Baihly et al. (2015) offered an insight on this use of hDVS. Furthermore, Molteni et al. (2016) evaluated microseismic monitoring as another compelling hDVS application. This paper evaluates the viability of using hDVS for distributed dynamic pressure sensing in marine seismic acquisition while reviewing the readiness of hDVS technology for this application. An initial concept of including hDVS in a streamer was disclosed by Kragh et al. (2012). Here, a possible design of a towed streamer using hDVS was discussed along with experimental results showing the potential of the technology to acquire pressure measurements in marine seismic surveys. We show the results of using hDVS to measure the pressure wavefield in two different experiments, and the results are compared with reference data acquired with traditional hydrophones. The use of a distributed measurement in towed streamers would provide a new type of measurement. The characterization of the pressure wavefield would be continuous along the cable with a denser spatial sampling. Similarly, straight fibres deployed along the streamer could characterize the tugging noise with increased spatial resolution. Furthermore, the use of cost-effective and lightweight fibres would greatly reduce the electronics embedded in the streamer and the total weight of the cable. The use of hDVS would also have new challenges – for example in how to segment the streamer into shorter sections without the fibre-optic connectors compromising the quality of the backscattered hDVS signal.

T he crustal structure along the passive margin of offshore Somalia has remained largely unknown, due to limited geological and geophysical data collection during the long period of political instability and civil war. The extent of geological information in the area has for many years been restricted to regional-scale features defined from poor quality legacy seismic data (Bunce and Molnar, 1977) and potential field data (Coffin and Rabinowitz, 1987; Rapolla et al., 1995). These observations allowed the development of early plate reconstruction models for Africa and Madagascar. However, since 2012 the region has experienced a period of relative political stability following the inauguration of the Federal Government of Somalia. Two 2D seismic acquisition programmes were undertaken in 2014 and 2016. The newly acquired seismic data have facilitated the development of new theories and understanding of the evolution of the Somalian passive margin (Kearns et al., 2016). In this study, we integrate newly acquired long offset seismic data with wells and regional satellite gravity and magnetic data, to critically assess the structural configuration, and map the continental to oceanic crust transition. We use gravity modelling techniques to support our observations. We also discuss the possible implications of our findings on source rock thermal maturity.

The Wattenberg field is the fourth-largest oil and ninth largest gas field in the United States (EIA, 2015). A multi-component time-lapse seismic study has been conducted by RCP and Anadarko Petroleum Corporation in the Wattenberg field. This study includes an integrated dataset with seismic, microseismic, FMI log interpretations, and completion information. As part of a horizontal drilling programme, the Niobrara and Codell formations were targeted. P-wave seismic and S-wave seismic were analysed as part of the time-lapse study before and after the completion of 11 horizontal wells in the study area. Time-lapse P-wave pre-stack inversion was able to identify pressure compartments in the different reservoir intervals that were able to be distinguished by the pre-stack data. The inverted P-impedance percentage difference volume allows for identification of pressurized zones and whether the faults are acting as seals or conduits for the hydrocarbons. S-wave data provides a subset of the pressure compartmentalization that encompasses the stimulated reservoir volume. Time-lapse post-stack inversions of the shear wave datasets provide insight into how the shear impedance is affected by hydraulic fracturing through the work of time-lapse shear wave splitting. The inversions show an increase in fast shear wave velocity and a decrease in slow shear velocity after stimulation. The sensitivity of both the fast and slow shear seismic to stimulation correlates with the net pressure trends at each stage as well as base map microseismic patterns. The stimulated volume for the Niobrara and Codell reservoir intervals are now more accurately defined. Timelapse shear wave splitting is able to define the stimulated rock volume and reveal areas that are not being accessed by the wells currently drilled. These areas are now detected within the Wishbone section, and may be candidates for future re-completion.

The stratigraphic traps in Unayzah formation play an important role in central Saudi Arabia where Aeolian sandstone with good reservoir quality is laterally sealed by up-dip playa siltstone with low porosity and low permeability due to the facies change. The recognition of facies and lithology therefore is a good way to characterize the stratigraphic traps. Seismic waveforms are employed using a supervised artificial neural network (ANN) to classify and identify the seismic facies since they carry multiple information such as amplitude, frequency and phase. Supervised ANNs are proven to be a successful classification technique which is implemented by the multi-layer perceptron (MLP) network with two layers. The network is trained with the facies information in the first layer and is to define and classify the input into several subclasses. When the training is completed, the sub-classes are combined and associated with the targeted facies in the second layer. And then the trained network is applied to the seismic data to predict the facies between well locations. The seismic reflection patterns for recognizing facies include configuration, amplitude, continuity, frequency, and interval velocity. Important lateral variations in reflectivity and reflector continuity provide information which is absent from the individual seismic waveforms and this is blended into the waveform classification map in order to improve the facies recognition.

The concept of value of information (VOI) was introduced to the oil and gas industry by Grayson (1960). Although the method is not limited to a specific kind of information, its thorough application is usually limited to seismic surveys, the most common source of geological and geophysical information in hydrocarbon exploration. According to Bratvold et al. (2009), 29 out of 30 reviewed VOI papers over 1962-2006 focused on valuing seismic information. A recent industry survey demonstrated that 10% of exploration wells fail due to a misinterpretation of a trapping structure; 15% fail due to lack of a reservoir or its poor effectiveness, 30% due to the lack of charge, and 45% due to absent or poor top or/and lateral seal (Laver et al., 2012). This means that analyzing the effects of information addressing the latter three geological risk factors should receive as much attention and study as VOI from seismic studies. We propose a new methodology to assess the value added to a prospect assessment through information provided by petroleum systems modeling (Hantschel and Kauerauf, 2009). The impact of a petroleum systems model (PSM) on a prospect assessment is usually more difficult to evaluate than the effect of a new 3D seismic survey because the information provided by a PSM has primarily a basin- or a play-wide extent.

The complex royalty system developed by Mexico for deepwater contracts in the Gulf of Mexico (GoM) may deter companies from bidding during the final phase of Bidding Round 1, which is due to close on 4 December, 2016. The variable royalty system involves an adjustment factor that is triggered once the contractor has recovered the initial investment, rapidly increasing the royalty rate. The variable royalty system leads to a profit split between contractor and government of 42-58% (contractor NPV divided by the sum of the government NPV plus the contractor NPV), with an average royalty of 25% (total royalty collected divided by total gross revenue). The US has a more appealing profit split of 54-46%, in favour of the contractor, with an average royalty of 16.66%. Additionally, the US royalty does not move any higher, only lower when the deepwater royalty waiver applies, which brings down the royalty to 12.5%. However, Mexico’s deepwater royalty rate of 25% only applies when a meagre 5% over royalty is offered in the bidding process. Companies that would offer higher royalties are more likely to win the bid, but at the expense of their profits because the average royalty rate will then be even higher than 25%.