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Timely and detailed evaluation of in-situ hydrocarbon flow properties such as oil density and viscosity is critical for successful development of heavy oil reservoirs. The prediction of fluid properties requires comprehensive integration of advanced downhole measurements such as nuclear magnetic resonance (NMR) logging, formation pressure, and mobility measurements, as well as fluid sampling.

The reservoir rock presented in this paper is an unconsolidated Miocene formation comprising complex lithologies including clastics and carbonates. The reservoir fluids are hydrocarbons with significant spatial variations in viscosity ranging from (60-300 cP) to fully solid (tar). Well testing and downhole fluid sampling in this formation are hindered by low oil mobility, unconsolidated formation that generates sand production, emulsion generation, and very low formation pressure.

We present a two-pronged log evaluation workflow to identify sweet spots and to predict fluid properties within the zones of interest. First, the presence of "missing NMR porosity" and "excess bound fluid" is estimated by comparing the NMR total and bound fluid porosity with the conventional total porosity and uninvaded water-filled porosity logs, respectively. Secondly, two-dimensional NMR diffusivity vs. T2 NMR analysis is performed in prospective zones where lighter and, possibly, producible hydrocarbons are detected. The separation of oil and water signals provides a resistivity-independent estimation of the shallow water saturation. Additionally, we correlated the position of the NMR oil signal with oil-sample viscosity values. The readily available log-based viscosity greatly improves the efficiency of the formation and well-testing job.

We successfully sampled high viscosity hydrocarbon fluids by utilizing either oval pad or straddle packer. The customized tool designed for sampling aided gravitational segregation of clean hydrocarbons from the water-based mud filtrate and emulsion; and therefore providing representative reservoir fluid samples based on downhole fluid analyzers.

Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.

Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.

The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.

The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (Gale et al., 2007, Slatt and O’Brien, 2011).

The recent crash in the oil market has allowed the industry to reduce the pace of evaluation and completion decisions in unconventional reservoirs, and turn to a more science-based decision-making process for project execution. The traditional stimulation design based on the geometric spacing of induced fractures is now gradually changing to geological spacing (i.e., a design based on an understanding of the reservoir geology) to enhance hydraulic fracture stimulation effectiveness for drastically reduced cost. A methodical rock texture characterization of core samples and cuttings can provide powerful information that can be used reliably and cost-effectively to optimize fracture stimulation designs by placing frac stages based on rock characteristics. This paper presents a new method to quantify rock texture based on automated petrographic analysis that uses advanced microscopy image analysis from scanning electron microscopy (SEM) and optical microscopy. A procedure called "quantitative evaluation of minerals using a scanning electron microscope" (QEMSCAN) and optical microscopy analyses were used to image rock samples prepared from cores and cuttings. Rock texture parameters were extracted automatically using new digital data processing techniques. The information from automated petrographic analysis was used to determine the spatial distribution of all components including mineral composition, framework grains, matrix, cement, grain size and shape, pore size and shape, modes of contact between grains and the nature of porosity. The results showed that while mineral composition of rock is important, texture characterization is far more significant to understand rock behavior than has been reported in the industry. Our results demonstrate the importance of quantitative microscopy and how it can provide an understanding of the key relationship between rock texture and rock behavior.

A new method was produced to characterize rock texture quantitatively from advanced image analysis with the aid of an automated petrographic system.

Recovery mechanism due to brine injection (Dynamic Water, Low Salinity, etc.) in carbonate remains a point of discussion and widely open for research. As wettability alteration is heavily suggested as the main driver for recovery, this study focuses on the in-situ evaluation of wettability alteration due to multiple successive dynamic water flooding of carbonate cores plugs.

Five different core flooding with Nuclear Magnetic Resonance (NMR) T₂ monitoring were performed on three different carbonate core plugs. These plugs were fully characterized in terms of petrophysical parameters and petrography. NMR T₂ measurements were performed throughout the core flooding experiment including the heat up, brine injection, soaking and cooling down.

Initial results on two samples that are of similar T₂ distribution showed relatively different irreducible water saturation (10.7 and 14.9 %) after centrifugation and an NMR T₂ inverted wettability after ageing of (-0.15 and -0.04). in the first case, the core was flooded with Gulf sea water. NMR showed clear trend towards increasing water wetness as a result of subjecting the cores with soaking periods, this accompanied with a clear additional recovery following the soaking. In the second case, the core was flooded with Gulf sea water followed by 10 times diluted sea water. Despite a high similarity with the previous core plug, recovery with sea water flooding alone resulted in 57% recovery without further recovery when the other brines were injected. In this case, where most of the effects seems to be happening during the first flooding, NMR, consistently with the production data, did not detect any clear wettability change during the soaking periods.

The results clearly indicate, for the first time, an in-situ wettability alteration due to Dynamic Water injection as demonstrated by NMR T₂ distribution analysis.

When a well reaches the end of its life-cycle, it is permanently plugged and abandoned. Since the first discovery in 1966 on the Norwegian Continental Shelf (NCS) till October 2014 nearly 5496 wells have been drilled. Of these wells, 3978 are development and 1518 are exploration wells. Of the development wells, 699 have permanently been abandoned and 279 are in temporary abandonment status. It is estimated that 3279 development wells need to be plugged and abandoned in the future. Besides, the number of wells which will be drilled in future should be added for plug and abandonment.

The costs of these P&A operations will be substantial. Hence, there is a need for technology development that will reduce the costs of all these operations. This development involves both techniques, tools and materials. The current work describes different plugging materials and important characteristics of permanent barriers with respect to long-term integrity. In addition, different roots of failure modes of permanent barriers have been discussed. Geopolymers are suggested as possible permanent plugging materials. Geopolymers are aluminosilicate materials, which solidify. A new geopolymeric material is introduced for the permanent zonal isolation and well plugging; an aplite-based geopolymer. Its placeability was studied by investigating the rheological behavior of the geopolymer slurries. The Bingham and Casson models selected to simulate the slurries' viscosities. Both models were fitted to the measured data. Strength development of the produced geopolymers showed sufficient compressive strength. X-ray powder diffraction was used to characterize the microstructure of the produced geopolymers. X-ray patterns showed formation of an amorphous phase. The measured permeability was in the range of nano Darcy. The initial result shows that the aplite-based geopolymer has the potential to be utilized as a permanent plugging material for well plugging and zonal isolation.

Trans-Tasman Resources Limited (TTR) was established in September 2007 in New Zealand to explore, assess and develop the off shore titano-magnetite iron sand deposits, located off the west coast of the North Island of New Zealand.
TTR holds exploration permit(s) and a prospecting license granting exclusive mineral rights over 9633 km2 of seabed, within New Zealand's territorial and Exclusive Economic Zone (EEZ) waters. Subsequent to a large airborne magnetic survey, TTR has undertaken a series of shallow and deep drilling campaigns which have defined an initial JORC1 mineral resource. This JORC compliant mineral resource was defined by Golders Associates on the basis of drilling campaigns that were performed using in house designed and operated drilling units, the first of its kind in the world.
TTR is developing innovative solutions for all aspects of its exploration and feasibility studies. In relation to exploration, TTR are competing in an environment which has offshore contractors and equipment focused on the petroleum industry, therefore it has been essential that TTR remain innovative to ensure cost effectiveness, fit for purpose and industry standards (JORC) are paramount. Exploration to date has enabled TTR to estimate an offshore titano-magnetite iron sand resource, using low cost marine reverse circulatory drilling units developed specifically for this purpose (patent pending) in conjunction with other exploration techniques.
The purpose of this paper will be to discuss some of the main challenges in the exploration and the subsequent engineering studies used in the feasibility studies for the development one of the world's first large off shore mineral resource of iron ore. The key strategic advantage of the envisaged off shore wet mining operation would be its much lower capital cost compared to land based operations, as no deep sea port or heavy gauge rail is required.
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The study of wave attenuation in partially saturated porous rocks over a broad frequency range provides valuable information about the fluid system of reservoirs, which are inherently multiple phase fluid systems. Until now, not much laboratory data have been collected in the seismically relevant low frequency range and existing literature data on experimental measured partially saturated rock are very limited. The main goal of our work is to experimentally measure the bulk seismic attenuation on fluid-bearing rocks, using natural rock samples in an efficient way at in situ conditions and employing linear variable differential transformers (LVDTs). Bench-top results are promising and show consistency with reported experimental data for dry, partially, and fully fluid saturated rocks. Measurements with the machine are accurate and precise. We are able to detect a wide range of attenuation values, from nearly elastic materials, like aluminum, up to very well characterized viscoelastic material, such as Plexiglas. This can be considered the end-members for a saturated rock in the low frequency range at different degrees of saturation.

Coals have been studied extensively to understand their chemical and thermodynamic properties. Yet, surprisingly very few data exist on their maturation and elastic properties relationship. In this paper, we present the relationships between rank metamorphism and ultrasonic velocity of coals. Seven coals maturation from several basins in world was assessed by Source Rock Analyzer. The total organic carbon (TOC) range values show that the organic matter is predominantly gas prone (mostly type III). The vitrinite reflectances suggest wide rank of maturation from lignite to semi-anthracite. Laboratory ultrasonic velocity measurements of the 7 dry coals exhibit different dynamic elastic properties which correlate to coal rank and applied confining pressure. Compressional and shear wave velocities increase as function of coal rank increases. Nevertheless, pressure dependence on coal elastic properties exist for confining pressure under 5 MPa. This sensitivity is affected by the cleats presence. Based on geochemistry — velocity cross plot elastic anisotropy may occur at high maturity coal rank due to the increasing TOC or decreasing hydrogen index (HI).

There are numerous methods which make use of different algorithms to solve the well-known deconvolution problem in seismic data processing. Most of these solutions require restrictive assumptions to seismic wavelet and reflectivity series, in particular wavelet to be known and/or the seismic reflections to be white. Here we use a different approach in the deconvolution that is not sensitive to the phase characteristics of wavelet nor to the whiteness of reflectivity series. We define an inversion problem for deconvolution to avoid from computing the inverse of the seismic wavelet. First, we locate spikes by means of Adaptive Simulated Annealing (ASA) and then compute the amplitudes of them by Least Square method. A comparison between this method and Minimum Entropy Deconvolution (MED) shows that although both methods try to simplify the seismic model, this method yields better results.

The volumetric water content (θ) of peat soils below the water table is largely controlled by the production of biogenic methane-rich gas bubbles that are subsequently released to the atmosphere, thereby having significant implications for carbon cycling. Geophysical methods have recently shown promise for improving studies of gas storage and release in peatlands. We investigated the relationship between dielectric permittivity and volumetric water content in organic peat soil using ground-penetrating radar. We developed a novel approach for controlling water content using a pressurized test chamber to reduce the volume of bubbles under high pressure as described by the ideal gas law. This method simulates the bubble-rich natural conditions much more closely than previous studies that utilized drying to vary water content. Our results cover a range of highly saturated peat that is commonly observed in poorly decomposed near-surface peat and we demonstrated that a linear model can be used to estimate water content in peat for a range of water contents (i.e. θ>90%). The data collected from samples taken from different peatlands suggests that it is possible to use our resulting model to convert dielectric permittivity extracted from ground-penetrating radar data into free-phase gas concentration via the water content.