Petroleum Geoscience - Volume 20, Issue 2, 2014

The Bunter Sandstone Formation (BSF) in the UK sector of the Southern North Sea is thought to have a significant potential for the injection and storage of anthropogenic CO2 within periclines that lie above salt domes and pillows formed by halokinesis in underlying Zechstein strata. During the formation of the periclines, the BSF and its overlying top seals were subjected to extensional stresses and, in consequence, are commonly cut by seismically resolvable faults that present a risk to the containment of gas and buoyant fluids such as supercritical CO2. Although most of the closed structures in the BSF are saline water-bearing, eight gas fields (total gas initially-in-place >72 bcm (billion cubic metres)) have been discovered to date. The seismically resolved structure of these gas fields demonstrates that two different top seals, the Haisborough Group and the Speeton Clay, can seal gas columns of up to 128 and 104 m respectively, despite the presence of faults with small displacements above the field gas–water contacts. The observed gas columns are equivalent to CO2 columns of up to around 100 m in height. Simple geomechanical modelling suggests that existing optimally orientated faults may dilate or be reactivated if the pore-fluid pressure increase as a result of CO2 injection exceeds a gradient of about 13.4 MPa km–1, potentially resulting in loss of storage integrity.

Preliminary dynamic modelling, using TOUGH2/ECO2N, has been carried out to assess the suitability of a site in the UK North Sea for sequestering CO2. The potential storage site is a previously unused saline formation within the Permian Rotliegend sandstone. Data regarding the site are limited. Therefore, additional input parameters for the model have been taken from the literature and nearby analogues. The sensitivity of the model to a range of parameters has been tested. Results indicate that the site can sustain an injection rate of around 2.5 Mt a–1 of CO2 for 20 years. The main control on pressure build-up in the model is the permeability of the unit directly beneath the Rotliegend in the location of the proposed storage site. The plume diameter is primarily controlled by the porosity and permeability of the site. A comparison between static, analytical and dynamic modelling highlights the advantages of dynamic modelling for a study such as this. Further data collection and modelling are required to improve predictions of pressure build-up and CO2 migration. Despite uncertainties in the input data, the use of a full three-dimensional (3D) numerical simulation has been extremely useful for identifying and prioritizing factors that need further investigation.

Natural gas hydrate (NGH) is a solid crystalline material composed of water and natural gas (primarily methane) that is stable under conditions of moderately high pressure and moderately low temperature found in permafrost and continental margin sediments. A NGH petroleum system is different in a number of important ways from conventional petroleum systems related to large concentrations of gas and petroleum. The critical elements of the NGH petroleum system are: (1) a gas hydrate stability zone (GHSZ) in which pressure and temperature lie within the field of hydrate stability, creating a thermodynamic trap of suitable thickness for NGH concentrations to form; (2) recent and modern gas flux into the GHSZ along migration pathways; and (3) suitable sediment host sands within the GHSZ. These elements have to be active now and in the recent geological past. Exploration in continental margin sediments includes basin analysis to identify source and host sediment likelihood and disposition, potential reservoir localization using existing seismic analysis tools for locating turbidite sands and estimating NGH saturation, and deposit characterization using drilling and logging. Drilling has validated first-order seismic analysis techniques for identifying and quantifying NGH using rock physics mechanical models.

Pore-lining chlorites are often associated with a low-resistivity contrast between corresponding reservoir units, making the identification and quantitation of hydrocarbon-bearing intervals difficult. In many low-resistivity situations, the traditional approach of using Archie’s equation to determine saturation from electrical resistivity fails, and modified Archie equations derived specifically for ‘shaly sands’ have been developed. In chlorite-bearing intervals, however, the effect of chlorite can be such that both Archie and the so-called shaly-sand models are inappropriate. Under these circumstances, calculating saturation from electrical resistivity can be circumvented by detailed analysis of the sedimentology and petrophysics, enabling the construction of a saturation height model based on core data. In this novel study we integrate a detailed core-based sedimentological facies scheme with wireline log data and petrophysical core data to demonstrate a clear link between chlorite occurrence, petrophysical characteristics and saturation height. Through this innovative approach, saturation is estimated without recourse to resistivity logs and improves hydrocarbon saturation estimates in chlorite-bearing reservoirs.

Understanding the controls on the size and shape of sandstone bodies deposited by fluvial systems is important in the reconstruction of ancient fluvial deposits and construction of quantitative reservoir models. Measurements and analyses of sandbodies from remotely sensed imagery have allowed quantification of width and length ratios of barforms in modern fluvial systems. For bank-attached bars the width:length ratios range between 0.12 and 0.47 (arithmetic mean: 0.25), for lateral bars between 0.19 and 0.42 (arithmetic mean: 0.30), for mid-channel bars between 0.09 and 0.49 (arithmetic mean: 0.28), and for point bars between 0.14 and 0.50 (arithmetic mean: 0.30). The majority of width:length ratios for all bar types range between 0.15 and 0.35. Examination of other parameters such as basin type, planform geometry, apparent stream width, river length, gradient over the investigated area, aggradational or degradational system, tectonic setting and climate do not significantly affect the width:length ratio. Therefore, the bar planform shape, the width:length ratio, can be considered to be scale invariant. The recognition that bar planform shape in fluvial systems is scale invariant will be useful in the construction of subsurface three-dimensional models of fluvial deposits with variable dimensions.