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The interpolative power of FTG measurements is playing a key role in helping oil and gas explorations achieve a better representation of the anomaly field and a clearer picture of the subsurface. Applications range from frontier exploration to augmenting existing data sets such as 2D seismic to produce more accurate 3D models of the geology. By measuring all the components of the gravity gradient tensor, the ability to interpolate or predict the variation of the field in between the survey lines can be greatly improved. This gives rise to an increased effective resolution of an airborne survey which is significantly better than that suggested by the line spacing. The key to the improvement is through joint processing where the information from the tensor components is combined to give a more complete picture of the gravity field. Our preferred method of achieving this is through an equivalent source density inversion which can accommodate any number of components measured at arbitrary locations. The resulting density distribution can subsequently be used to predict (Figure presented) components of the gravity and gravity gradient fields in between the original measurement locations by means of forward calculations. In the field example, it was shown that collecting full tensor data along flight lines with 5 km spacing could be processed to yield a data set with a useable average radial resolution down to 2 km wavelengths. This Figure is much less than the Nyquist limit of 9 km suggested by the line spacing (Pedersen and Rasmussen, 1990). The increased level of effective resolution was sufficient to image the signal from salt structures that had a width of approximately 2.5 km. The signal from the salt structures had a large amplitude and therefore provided ample signal to noise ratio even when only the data along the widely spaced survey lines were used. In other cases, the target signals can be much smaller and the line spacing is limited by the need to accurately measure the anomalous field in the presence of noise. This could be referred to as a detectability requirement and drives the line spacing down to produce a useable resolution that has sufficient bandwidth where the signal is above the noise. The enhanced effective spatial resolution resulting from multiple tensor measurements will then be superfluous as a high sampling resolution will already be provided by the survey pattern. In these cases, measuring a single component with a greater signal to noise ratio would be more beneficial. When signal to noise ratio is not the limiting factor, FTG measurements can be used to increase the line spacing without sacrificing resolution and therefore ultimately reduce the cost of a survey. © 2012 EAGE. Source


Houghton P.,ARKeX
Hart's E and P | Year: 2012

Identifying, mapping, and staying within sweet spots determining well locations and spacing so drilling can be optimized and designing the most effective production strategy, while taking heed of environmental sensitivities, are all key drivers for shale gas operators today. While information generated from seismic is crucial in guiding drilling and completion programs, gravity gradiometry imaging (GGI) also is playing an important role alongside 2-D seismic in optimizing exploration strategy in shale gas plays. These benefits are principally seen in two crucial areas - firstly, in indentifying zones where there is a high probability of structural complexity, which can subsequently have a negative effect on production and fracing programs and secondly, in reducing cost and risks surrounding shale gas exploration. Source


Brazil, the Gulf of Mexico, and Africa enclose significant discoveries in the pre-salt, much of them exhibiting complex overburdens. As a result, seismic technologies are of importance in drilling and to cover large areas. In Brazil, for example, the focus is now on the plays of the pre-salt in the hydrographic basins of Santos, Campos, and Espiritu Santo, covering over 800 km. Capture of high quality seismic images of pre salt prospects becomes exigent because the drilling costs in deep waters per well reach $(US)100 million. The discussion covers gravimetric gradiometry and the pre-salt; solution to the problem of the structure of the salt in the K-2 field; and data analysis. Gravity Gradiometry Imaging (GGI) maps small variations in density in underlying rocks. The K-2 field is in Block 562 of Green Canyon, in the deep waters of the Gulf of Mexico, 290 km south of New Orleans. It has a solid body of salt over 3,048 m thick. The GGI contributes to the outlining of the salt structure by obtaining images using the algorithm of migration. Source


Houghton P.,ARKeX
Hart's E and P | Year: 2011

Gravity gradiometry imaging (GGI), a technique with an ability to qualify vast regions quickly, accurately, and cost-effectively and optimize the design of future seismic surveys, is proving particularly attractive to today's independents oil and gas companies. Forent Energy Ltd., a Calgary-based oil and natural gas producer, has used GGI as a cost-effective method to image the subsurface of its Nova Scotia prospect area, leading to the more efficient placement of its 2-D seismic lines and also having minimal landowner impact. Tower Resources, a UK-based independent oil and gas exploration company, has been using GGI to improve structural definition within a proposed license area in northwest Uganda along the East African Rift System. In Tower's case, the GGI data are helping to improve the planning for a 91- to 122-mile 2-D seismic program, to take place in the next few months - by mapping structures in the deeper part of the basin to improve structural definition and assist in identifying a better developed reservoir section. Source


Murphy F.E.,ARKeX | Schodt N.H.,Maersk Oil | Andersen J.,Maersk Oil
73rd European Association of Geoscientists and Engineers Conference and Exhibition 2011: Unconventional Resources and the Role of Technology. Incorporating SPE EUROPEC 2011 | Year: 2011

The Kwanza basin is part of the greater Aptian salt basin of West Africa. The recent discovery of giant fields in the sub-salt section of the conjugate Brazilian margin has focussed interest on the essentially unexplored deep water Kwanza basin. The presence of a functioning petroleum system is known from onshore wells. However, the deep water and complex geology associated with poor seismic imaging makes conventional exploration challenging. Due to the high density contrast between the sediments, salt and basement, the area is an ideal case for application of potential field methods in an integrated interpretation workflow. Modelling of interpreted seismic sections constrained by potential field data exploits the complementary nature of the datasets. This study uses a subset of the WesternGeco multi-client dataset covering much of the Angolan passive margin. Gravity models were constructed along 10 regional seismic lines. The initial models were based on the pre-existing seismic interpretation. The basement was modified to produce a model consistent with both the seismic and potential field data. A regional basement surface was derived utilizing the 2D models as a constraint. Significant changes to the seismic interpretation of salt were also required to ensure a consistent fit to the gravity data. Source

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