Description: Analytical well-test solutions are mainly derived for simplified and idealized reservoir models and therefore cannot always honour the true complexity of real reservoir heterogeneities. Pressure transients in the reservoir average out heterogeneities, and therefore some interpretations may not be relevant and could be misleading. Geological well testing refers to the numerical simulation of transient tests by setting up detailed geological models, within which different scales of heterogeneity are present. The concept of geological well testing described in this paper assists in selecting from multiple equi-probable static models. This approach is used to understand which heterogeneities can influence the pressure transients. In this paper, a low-energy multi-facies fluvial reservoir is studied, for which data from a well test of exceptionally long duration are available. The pervasive low reservoir quality facies and restricted macro cross-flow between the reservoir layers give rise to an effective commingled system of flow into the wellbore (i.e. zero or very low vertical cross-flow between the reservoir units). In our model, facies transitions produce lateral cross-flow transients that result in a ‘double-ramp-effect’ signature in the test response. A sophisticated multi-point statistical (MPS) facies modelling approach is utilized to simulate complex geological heterogeneities and to represent facies spatial connectivity within a set of generated static models. The geological well-test model responses to a real well-testing cycle are then evaluated using dynamic simulation. The pressure match between simulated and recorded data is improved by generating multiple facies and petrophysical realizations, and by applying an engineering-based hybridization algorithm to combine different models that match particular portions of the real well-test response. In this example, the reservoir dynamics are controlled by subtle interaction between high-permeability channels and low-permeability floodplain deposits. Effective integration of geology and dynamic data using modern methods can lead to better reservoir characterization and modelling of such complex reservoir systems.

Description: Many diverse challenges – political, economic, legal and technical – face the continued development and deployment of geological storage of anthropogenic CO 2 . Among the technical challenges will be the satisfactory proof of storage site security and efficacy. Evidence from many past geotechnical projects has shown the investigations and analyses that are required to demonstrate safe and satisfactory performance will be site specific. This will hold for the geomechanical assessment of saline aquifer storage site integrity where, compared to depleted hydrocarbon fields, there will be no previous pressure response history or rock property characterization data available. The work presented was carried out as part of a project investigating the improvement in levels of confidence in all aspects of saline aquifer site selection and characterization that could be expected with increasing data availability and in-depth analysis. Attention focused on the geomechanical modelling and the rock mechanics data used to populate models of two storage sites in geological settings analogous to those where CO 2 storage might be considered. Coupled geomechanical models were developed from reservoir simulation models initially incorporating generic rock mechanical properties and then laboratory-derived site-specific properties. The models were run in various configurations to investigate the effect of changing the rock mechanical properties on the geomechanical response of the storage systems. Modelling results showed that the pressure response at one site due to low injectivity caused significant potential for fault reactivation. Increasing the number of injection wells, thereby reducing the individual rates needed to deliver the target capacity, reduced the injection pressures and ameliorated, but did not eliminate, this adverse response.

Description: The wireline gamma-ray log is sensitive to open-hole conditions and, in particular, the diameter. This means that the log can jump at casing points. Although environmental corrections exist, they can fail at these points. We present a Bayesian method for deriving a new quantity – the shifted gamma–ray index – that takes these shifts into account by fitting a piecewise linear function to open-hole data in a depth window around the casing point. Because it is Bayesian, the method enables us to assess our uncertainty about its performance. This method requires very little knowledge of the borehole or drilling conditions but relies on the assumption that the lithology is consistent. Investigating the other wireline logs enables us to assess whether this assumption is valid. We demonstrate our method using well data from offshore mid-Norway.

Description: Core samples from seven wells in Lower Cretaceous limestones of the Upper Shu’aiba Member were characterized by conventional core analyses, petrography, bulk chemistry and mercury-injection capillary pressure data to define reservoir rock types (RRT). In the main oilfield studied, lithofacies are arranged in three main belts corresponding to ramp crest, upper slope and lower slope, with bioclast content and size decreasing down depositional dip. Rock typing is based on the observation of distinct, but overlapping, porosity–permeability transforms for each lithofacies, although most samples plot in or below the class 3 field of Lucia, reflecting the presence of abundant lime-mud matrix. Because of the wide range of porosity in each of the main lithofacies, an arbitrary division at 20% porosity is used in combination with lithofacies to define RRT with both three-dimensional (3D) geological significance and distinct ranges of permeability and capillary pressure characteristics. The use of total porosity as a rock-typing criterion is based on the interpretation that porosity is controlled on the reservoir scale by the depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms a have low clay, and, thus, highest porosity. Because both lithofacies and porosity are linked to the sedimentological and stratigraphic organization of the Upper Shu’aiba clinoforms, the RRT can potentially be implemented in a reservoir model for assigning distinct ranges of petrophysical properties to the different architectural elements comprising each clinoform. Two additional grain-dominated RRT have also been defined in a single core that was available from a second oilfield.

Description: In this paper we describe an improved sample-preparation technique for applying confocal laser scanning microscopy to image the void space of porous geological media, particularly various kinds of carbonate rocks with significant microporosity. We have improved the existing sample-preparation technique for confocal imaging by introducing a positive-pressure application step. This additional step helps to force the fluorescent-doped epoxy mixture inside the submicron pores (the microporosity) which make up a significant fraction of the total porosity of the carbonate rocks being characterized using confocal laser scanning microscopy. We also provide additional technical details and discuss practical aspects important to consider when imaging carbonate rock samples using this technique.

Description: One of the main objectives of nanotechnology in the oil industry is to identify applications that could bring significant benefits to enhanced oil recovery. Therefore, it has attracted the attention of many researchers over the last decade. This paper experimentally investigates the efficiency of surface-modified silica nanoparticles in enhanced oil recovery. These nanoparticles improve oil recovery through two main mechanisms: oil–water interfacial tension reduction; and wettability alteration. Various concentrations of nanofluid were made, and their effect on wettability and interfacial tension were investigated to determine the optimum concentration for injection into core samples. The results indicate that a concentration of 4 g l –1 is the optimum concentration. Moreover, this paper reports the nanofluids’ potential in enhanced oil recovery of water-wet core plugs. The results of coreflood experiments reveal that oil recovery increases by 26.2% and total oil recovery considerably improves after the injection of nanofluid. In addition, filtration of the nanofluid before injection into the core was very effective in reducing the risk of possible permeability damage that occurred due to the deposition of large nanoparticle aggregates onto the rock surface.

Description: Future geological CO 2 sequestration in the Gippsland Basin is contingent upon an effective regional top seal; potentially provided by the late Oligocene–early Miocene Lakes Entrance Formation. This study integrates various top-seal assessment methodologies into a workflow to estimate the efficiency of the Lakes Entrance Formation as a top seal. Factors related to, for example, top-seal lithology, shale volume, carbonate content and fracture density, and factors relating to the faults that cut the top seal, fault-zone shale content, strain, slip-tendency, etc., are compared to hydrocarbon leakage and seepage indicators reported in the study area. The factors that best correlate with reported leakage indicators are combined to map the spatial risk variation. While the study indicated that the ultimate control on top-seal efficiency is the formation’s membrane seal capacity; it also highlighted the spatial correlation between leakage indicators and some fault-related factors, suggesting that faults are key to top-seal bypass in much of the Gippsland Basin. Fault-zone shale content proved the dominant fault-related factor; as such, it can be concluded in the Gippsland Basin, at least, that a fault-zone shale content of less than 0.3 is the dominant factor with regard to faults enabling fluids to bypass top seals.

Description: Hydrocarbon leakage is a major exploration challenge in the western Hammerfest Basin. Most exploration failures in the area have been attributed to leakage; hydrocarbon-bearing traps are rarely filled to their structural capacity, and almost all traps have hydrocarbon shows down to their structural spillpoint or below. We have investigated to what extent the hydrocarbon column heights can be explained by vertical leakage along faults or at fault intersections. For the fields that we evaluated we observe that: (a) all dry structures have fault intersections at top reservoir level up dip of the well position: (b) the only structure where no faults intersect at top reservoir level is the only structure that is clearly filled to structural spillpoint; and (c) all fluid contacts in underfilled structures broadly coincide with the position of intersecting faults. The underfilled structures have less than two fault intersections up dip and above the gas-bearing reservoir. We suggest that vertical leakage at fault intersections has exerted a main control on the position of the gas–water contacts in the western Hammerfest Basin, and therefore that hydrocarbon column-height predictions can be improved by addressing the positions of such intersections at the top reservoir surface.

Description: The initialization of a reservoir simulator calls for the populating of a three-dimensional dynamic grid-cell model using subsurface data and interrelational algorithms that have been synthesized to be fit for purpose. These prerequisites are rarely fully satisfied in practice. This paper sets out to strengthen initialization through four key thrusts, all of which seek to optimize the bridgehead between reservoir geoscience and reservoir engineering, and thereby maximize value from reservoir simulation. The first addresses representative data acquisition, which includes the key-well concept as a framework for the cost-effective incorporation of free-fluid porosity and permeability within an initialization database. The second concerns the preparation of these data and their products for populating the static and dynamic models. Important elements are dynamically conditioned net-reservoir cut-offs, recognition of primary flow units, and establishing interpretative algorithms at the simulator grid-cell scale for application over net-reservoir zones. The third thrust is directed at the internal consistency of capillary character, relative permeability properties and petrophysically-derived hydrocarbon saturations over net reservoir. This exercise is central to the simulation function and it is an integral component of hydraulic data partitioning. The fourth concerns the handling of formation heterogeneity and anisotropy, especially from the standpoint of directional parametric averaging and interpretative algorithms. These matters have been synthesized into a workflow for optimizing the initialization of reservoir simulators. In so doing, a further important consideration is the selection of the appropriate procedures that are available within and specific to different software packages. It is the authors’ experience that implementation of these thrusts has demonstrably enhanced the authentication of reservoir simulators through more readily attainable history matches with less required tuning. This outcome is attributed to a more systematic initialization process with a lower risk of artefacts. Of course, these benefits feed through to more assured estimates of ultimate recovery and, thence, hydrocarbon reserves.

Description: The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.