Petroleum Geoscience - Volume 17, Issue 2, 2011

Nuclear magnetic resonance (NMR) is a useful tool in reservoir evaluation. The objective of this study is to predict petrophysical properties from NMR T 2 distributions. A series of laboratory experiments including core analysis, capillary pressure measurements, NMR T 2 measurements and image analysis were carried out on sixteen greensand samples from two formations in the Nini field of the North Sea. Hermod Formation is weakly cemented, whereas Ty Formation is characterized by microcrystalline quartz cement. The surface area measured by the BET method and the NMR derived surface relaxivity are associated with the micro-porous glauconite grains. The effective specific surface area as calculated from Kozeny's equation and as derived from petrographic image analysis of backscattered electron micrograph's (BSE), as well as the estimated effective surface relaxivity, is associated with macro-pores. Permeability may be predicted from NMR by using Kozeny's equation when surface relaxivity is known. Capillary pressure drainage curves may be predicted from NMR T 2 distribution when pore size distribution within a sample is homogeneous.

This paper presents an integrated seismic, petrophysical and analogue core study of the Mid-Eocene Grid deep-water Sandstone Member from the Nelson Field area, Central North Sea. Two possible turbiditic units were identified in seismic data. Grid 1 shows channel-like features and a complex stratigraphy whilst Grid 2 consists of scattered bright amplitude events (shown to be slumped shales and chalky limestones by cuttings analysis). Lower Eocene Tay Sandstone Member core from the nearby Gannet Field provided an analogue for sedimentary facies. This enabled petrophysical and seismic observations of the Grid Sandstone Member to be tied to sedimentological facies. An integrated model shows five facies associations and a complex reservoir quality distribution. A comparison with outcrop and seismic examples of channelized turbidites indicates that the Grid system represents a medium-scale channel complex, exhibiting multi-storey, nested offset stacking.

This work presents a new example that provides a link between laboratory experiments on topographic interaction of turbidite flows with seismic-scale observations and facies determination. The Grid system also adds to our knowledge of Palaeogene turbidite evolution from sheet-like to channel-like forms and provides a useful analogue for improving hydrocarbon exploration and production efficiency in adjacent areas.

The Pereriv Suite reservoir in the Azeri culmination of the ACG Oilfield is characterized by laterally continuous layers of variable net-to-gross (NTG) ratio deposited in a channel-dominated, fluvio-deltaic environment. The reservoir is being developed by down-dip water injection, with up-dip gas injection on the more steeply dipping central north flank. We use high-resolution models derived from outcrop analogue and subsurface data to demonstrate that four key sedimentological heterogeneities control recovery in both oil–water and gas–oil displacements: (1) local variations in NTG within low NTG (<55%) layers; (2) the degree of communication between low NTG layers and adjacent high NTG (>85%) layers; (3) sinuosity and (4) stacking pattern of channel-fill sandbodies in low NTG layers. The first three heterogeneities control sandbody connectivity; the fourth controls sweep efficiency in the connected sandbodies. Two further heterogeneities control recovery in gas–oil displacements in high NTG layers: (5) vertical-to-horizontal permeability ratio of channel-fill sandbodies and (6) mud clast lags at channel bases. Models which omit these small-scale features predict that sedimentological heterogeneity has little impact on water–oil or gas–oil displacements in high NTG layers, but fail to capture the effect of heterogeneity on the gravity stability of the gas–oil displacement, which significantly impacts on recovery.

Reservoir mapping in the Gulf of Suez petroleum system is challenging because rift-parallel and cross-rift faults disrupted the sediments, leaving the reservoirs confined to stratigraphic, structural, and combined traps. We have developed a technique to address this challenge that integrates fault outcrop mapping using satellite image interpretation, seismic near-surface characterization techniques such as Rayleigh wave velocity mapping and ray parameter interferometry, as well as ant tracking of faults and geobody delineation on a prestack time-migrated (PSTM) cube. The technique uses a combination of geographic information system (GIS) and geological modelling software such as Petrel for surface/subsurface integration. The joint analysis of Rayleigh wave data with satellite imagery provides a near-surface structural geological model.

The acquisition, processing, and interpretation of point-receiver seismic data enables the interpretation of near-surface geological structures. Detailed shallow structural geology can be imaged in the near surface, a data regime that is conventionally masked by the acquisition noise from the seismic acquisition. The shallow geological model comprises shallow lithological horizons as well as fault zones, the mapping of which may assist with the mitigation of shallow drilling risks.

The integration of surface and subsurface structural mapping provides a tectonic framework for the delineation of reservoirs in the rift-faulted environment of the Gulf of Suez.

Fault seal plays a critical part in hydrocarbon traps, and the same will be true for CO2 storage. The standard workflow for prediction of capillary seal of hydrocarbons can be readily adapted to prediction of CO2 seal since the fluid properties of CO2 at reservoir temperatures and pressures are within the range shown by hydrocarbons. The workflow is applied in a feasibility study into the proposed CO2 storage in the Johansen Formation of the Troll Field.

Computation of Shale Gouge Ratio (SGR) over the fault surfaces, in combination with juxtaposition diagrams, was used to estimate the sealing potential of faults cutting the Johansen Formation. SGR values were converted to potential CO2 column heights that might be trapped at each fault. Column heights are generally less than 100 m at each fault, allowing a cross-fault migration route from the Johansen Sand via the Statfjord Formation, Cook Formation and Brent Group.

Analysis of in-situ stresses suggests that the faults in the Troll Field are not close to failure and therefore up-dip leakage of CO2 is unlikely. Extremely large CO2 columns (>300 m) would be required to change this stress stability, and across-fault capillary leakage would occur first.

Exploration well 50/26b-6 in the UK Southern North Sea discovered a trap containing a gas-bearing Rotliegend Group (Leman Sandstone Formation) reservoir which was a major surprise at the time of drilling in that its gas composition was approximately 50% CO2 (with 9% N2 and the remainder methane). Christened the ‘Fizzy Discovery’, the accumulation was appraised by well 50/26b-8. Subsequently, another CO2-rich discovery (Oak) was made along-strike in nearby block 54/1b. Column heights at the well locations are of the order of a few tens of metres, but at the Fizzy Discovery the column height at the trap crest is estimated to be over 200 m. Interpretation of a high fidelity PSTM 3D seismic dataset has been constrained by 33 exploration wells allowing fault geometries and stratigraphic offsets to be determined with confidence. Despite late-stage (Late Cretaceous) structural inversion, the net boundary-fault offset is sufficient in both the Fizzy and Oak discoveries to almost breach the Zechstein Group evaporite super-seal, and the CO2-bearing Rotliegend Group in the footwall is now juxtaposed against hanging wall sediments of the uppermost Zechstein Group. Hence, these Zechstein Group units evidently act as a robust long-term side-seal for the carbon dioxide column. The Fizzy and Oak accumulations are noteworthy in providing a natural demonstration of top seal and fault side-seal integrity for carbon dioxide in a subsurface reservoir, that has remained intact over a geological timescale in what is otherwise a prolific methane-rich reservoir play fairway.