Bennett, Nicholas (Schlumberger-Doll Research) | Donald, Adam (Schlumberger) | Ghadiry, Sherif (Schlumberger) | Nassar, Mohamed (Schlumberger) | Kumar, Rajeev (Schlumberger Middle East S.A.) | Biswas, Reetam (The University of Texas)
A new sonic-imaging technique uses azimuthal receivers to determine individual reflector locations and attributes, such as the dip and azimuth of formation layer boundaries, fractures, and faults. From the filtered waveform measurements, an automated time pick and event-localization procedure is used to collect possible reflected arrival events. An automated ray-tracing and 3D slowness time coherence (STC) procedure is used to determine the raypath type of the arrival event and the reflector azimuth. The angle of incidence of the reflected arrival is related to the relative dip, and the moveout in 3D across the individual sensors is related to the azimuthal orientation of the reflector. This information is then used to produce a 3D structural map of the reflector, which can be readily used for further geomodeling.
This new technique addresses several shortcomings in the current state-of-the-art sonic-imaging services within the industry. Similar to seismic processing, the current sonic-imaging workflow consists of iteratively testing migration parameters to obtain a 2D image representing a plane in line with the desired receiver array. The image is then interpreted for features, which is often subjective in nature and does not directly provide quantitative results for the discrete reflections. The technique presented here, besides providing appropriate parameter values for the migration workflow, further complements the migration image by providing dip and azimuth for each event that can be used in further downstream boundary or discontinuity characterization.
A field example from the Middle East is presented in which a carbonate reservoir was examined using this technique and subsequently integrated with wellbore images to provide insight to the structural geological setting, which was lacking seismic data due to surface constraints. Structural dips were picked in the lower zone of the main hole and used to update the orientation of stratigraphic formation tops along the well trajectory. 3D surfaces were then created and projected from the main hole to the sidetrack to check for structural conformity. One of the projected surfaces from the main hole matched the expected depth of the formation top in the sidetrack but two were offset due to the possible presence of a fault. This was confirmed by parallel evaluation of the azimuthal sonic-imaging data acquired in the main hole that showed an abrupt change in the relative dip of reflectors above and below the possible fault plane using the 3D STC and ray tracing. Dip patterns from both wells showed a drag effect around the offset formation tops, further confirming the presence of a fault. A comparison of the acquired borehole images pinpointed the depth and orientation of the fault cutting both wells to explain the depth offset of the projected 3D formation top surfaces.
Wettability is a key parameter in the development of an oilfield as it strongly affects oil saturations, capillary pressures, electrical properties, relative permeabilities and oil recovery. Despite attempts made to evaluate wettability downhole, the standard methods to quantify it are still laboratory based; the two most commonly used are Amott-Harvey (AH) and US Bureau of Mines (USBM). These techniques are expensive and very time-consuming, requiring a sample to be retrieved from the well and analyzed in the laboratory. In several cases, the results are obtained late and only after several decisions regarding the reservoirs had to be made, without this important piece of information.
It is ubiquitously recognized that nuclear magnetic resonance (NMR) is very sensitive to the strength of the fluid-rock interactions, and therefore has been considered as a good candidate for wettability determination since the 1950s. The NMR signal, however, is also sensitive to several other fluid and rock properties, for example viscosity and pore-size distribution, making the practical extraction of wettability information from NMR data not straightforward. NMR has, however, two considerable advantages compared to AH and USBM: it is much faster, allowing much faster turnaround of laboratory measurements, and can be measured in-situ downhole, with the result of the measurement being available in real time. These extreme advantages fueled the research on the topic of NMR wettability despite the above-mentioned difficulties.
There are at least three main NMR parameters measurable downhole: T1, T2 and diffusion; with additional information extractable from the correlation between these three. Wettability affects all of these parameters, and the correlation between them. This means that there is not a single way to extract wettability information from NMR data, but there are different options.
Here, we review 60 years of literature on the topic of NMR and wettability, from the first experimental observations in the 1950s to the most recent advancements. Also, this work aims at presenting strengths and limitations of the techniques being developed nowadays, to help the audience make the best choice for each specific case. In this paper, we discuss both laboratory- and log-based applications, although we place greater emphasis on laboratory-based applications.
Specic experiments have been designed and the experimental measurements obtained show that, not only the absolute permeability but also the gas relative permeability are sensitive to connement and that the residual gas saturation (through permeability "jail") increases with loading. This observation represents an additional source of complexity in the evaluation of low-permeability sandstone gas reservoirs. INTRODUCTION Low-permeability sandstone gas reservoirs, also called tight reservoirs, are generally considered stress-sensitive reservoirs. Numerous laboratory tests under single-phase ow have shown that the absolute permeability of these reservoir rocks decreases strongly with connement. This dependence on connement is attributed to the existence of joints and interfaces in tight rocks, which close when loading increases, as pointed out by Walsh and Brace (1984) and Warpinski and Teufel (1992).
Capillary desaturation experiments are combined with high-resolution microtomography imaging to understand the impact of wettability on the global and local distribution of fluids in the pore space of sandstone outcrops. Small cylindrical rock samples are cored, imaged in dry state then successively prepared at irreducible water saturation before steps of waterflood. Several samples also go through a wettability-alteration phase in order to expand the range of wettability conditions: namely, oil-wet to mixed-wet. Waterflooding is done at various capillary numbers and injected brine volumes, depending on the case. The entire rock is imaged at voxel resolutions of typically 2 or 4 µm, to ensure a high-quality segmentation.
Global oil saturation results show how the wettability impacts the shape of capillary desaturation curves, in particular, the existence of a critical capillary number. In the nonwater-wet experiments, oil saturation is controlled by a large, highly-connected oil cluster percolating from the inlet to the outlet of the sample. Such results are important for pore-scale flow modeling strategy and validation. We demonstrate that the wettability is not always uniformly distributed along the core despite of the use of classical wettability-alteration protocols, highlighting potential biases in traditional SCAL tests.
A novel method of measuring steady-state relative permeability, called the intercept method (IM), was recently introduced. The IM entails a modification of a standard steady-state procedure that incorporates multiple total flow rates at each fractional flow rate. The objective of the method is to measure data at each fractional flow rate that will permit simple analytical calculations to correct differential pressure (hence relative permeability) and saturation data for the effects of capillary pressure. The IM is intended to provide a corrective technique without the need for additional supportive analyses, such as capillary pressure and in-situ saturation monitoring (ISSM), or as an alternative approach to the current considered best practice of numerical coreflood simulation, which generally requires the specified additional data.
Consequently, the IM is of interest to the global industry in regions and/or laboratories that do not possess state-of-the-art equipment, or for its cost-saving potential. However, before employing this new method, it was important to the authors to investigate its validity across a wider range of rock properties, sample dimensions and wetting states experienced in commercial special core analysis laboratory (SCAL) coreflood experiments. This study thus draws on a variety of relative permeability curves (and supporting data) from various global core studies, originally derived by typical relative permeability methods plus coreflood simulation. From these data, we use SCORES (an open-source coreflood simulation software) to simulate the expected results of multiflow-rate steady-state experiments and use the IM to derive and compare the corrected relative permeability curves. Results highlight criteria under which the method does not provide fully corrected data. The paper explores these criteria in more detail.
In-situ saturation monitoring (ISSM), using X-rays or gamma rays, has become a common method to determine fluid saturations in commercial coreflood experiments. The most common method in commercial laboratories entails 1D saturation measurements as a function of core-plug length and of experimental time. Laboratories often employ ISSM as the only method of determining fluid saturations, assuming an almost infallible accuracy of 1 to 2 saturation units (s.u.). However, as for all measurement methods, there are possible sources of uncertainty in ISSM data. Previous papers have discussed some of these uncertainties, such as X-ray drift, and inappropriate calibration scans or changes to core or fluid properties during testing. Despite this evidence, some laboratories continue to use ISSM measurements alone, assuming negligible uncertainty.
In the authors’ experience, uncertainties not only exist in measurement errors, but also may be introduced by inappropriate processing and interpretation methods. This paper first considers the stipulated 1 to 2 s.u. accuracy and the necessary signal-to-noise ratio, i.e., counts required, to achieve this; as well as providing a suggested approach, where plausible, to correct saturation data compromised by incorrect calibration scans. It also considers the uncertainties in use of ISSM production volumes in determining unsteady-state relative permeability; specifically, pre- and post-breakthrough data and the assumptions surrounding selection of breakthrough from flood-front scans. In addition, ISSM profiles are often used in coreflood simulation of relative permeability to aid correlation of the capillary end effect; incorrect data processing may compromise this correlation. The paper considers several sources of error in ISSM data and provides a recommended approach to acquisition, processing and interpretation of ISSM data for calculation of fluid saturations.
While distributed temperature sensing (DTS) has become a commonly used tool in reservoir studies, the technology has not seen widespread use in SCAL projects. Most core-scale experiments attempt to control temperature at a constant value rather than monitor temperature changes within a sample during a test. High-resolution temperature arrays are available that measure changes in temperature of 0.1°C at 1-mm resolution. The optical backscatter reflectance (OBR) fiber senses both temperature and strain that can be separated through experiment design and signal processing. These OBR fibers are sensitive enough to monitor temperature changes associated with endo- and exothermic chemical reactions associated with mineral dissolution/precipitation, or fluid-front movements in steam-assisted gravity drainage of heavy-oil tests. An example of the use of a distributed temperature array is in the monitoring of natural-gas-hydrate formation and dissociation in a sandpack as CO2 is exchanged with the naturally occurring CH4 in the hydrate structure. A fiberoptic array was placed within a narrow-diameter PEEK tube as the sandpack was constructed. The PEEK tube held the fiber optic in place so that the sensed signal was temperature only and did not include any strain effects. The OBR was set up to acquire a temperature array every 30 seconds during the test at 5-mm spacings. The core holder was placed in a MRI instrument that provided additional spatial information on hydrate formation during the test that was compared with the OBR results. Initial hydrate formation resulted in a several degrees increase in temperature at the inlet end of the cell that with time, progressed down the length of the cell. The temperature array and MRI images both showed the nonuniform nature of hydrate formation and subsequent dissociation of the hydrate when N2 was injected into the cell as a permeability enhancement step. The faster response of the OBR array compared to the time required to acquire MRI images provided additional detail in the sequence of hydrate formation and dissociation during CH4-CO2 exchange. The limitation to the OBR array was that it only sensed temperature fluctuations proximal to the fiber as a function of the hydrate system’s thermal conductivity.
Lin, Qingyang (Imperial College London) | Bijeljic, Branko (Imperial College London) | Krevor, Samuel C. (Imperial College London) | Blunt, Martin J. (Imperial College London) | Rücker, Maja (Imperial College London) | Berg, Steffen (Imperial College London / Shell Global Solutions International BV) | Coorn, Ab. (Shell Global Solutions International BV) | van der Linde, Hilbert (Shell Global Solutions International BV) | Georgiadis, Apostolos (Shell Global Solutions International BV) | Wilson, Ove B. (Shell Global Solutions International BV)
In the context of digital rock analysis, pore-scale imaging of multiphase flow experiments using X-ray microtomography can be used to obtain fundamental insights into pore-scale displacement physics. This provides a basis to better calibrate numerical pore-scale simulators, or it can be used to understand local fluid distributions, while simultaneously measuring average properties, equivalent to a traditional SCAL experiment. Imaging studies in the literature have historically been conducted on small water-wet plugs, using kerosene, or another refined oil, as the non-wetting phase. Prior to conducting waterflood experiments, the initial water saturation has been established by dynamic flooding. The disadvantage with this is that a nonuniform saturation profile is established due to the capillary end effect. This will result in a higher average initial water saturation compared with, for instance, standard SCAL techniques, such as the porous-plate method or centrifugation.
In this paper, a methodology for initializing multiple small rock samples to the same connate water saturation and wettability state has been developed by adopting best SCAL practices, namely the porous-plate method or centrifugation using crude oil, followed by aging. We drill multiple small plugs from a full-size SCAL core sample, without losing capillary continuity with the base of the original sample. In the example presented, for Bentheimer sandstone, the initial saturation was established using centrifugation. The experiment is designed to prevent a nonuniform saturation profile in the small plugs. We use in-situ imaging to determine the water saturation after primary drainage and show that it is indeed uniform across the sample with a value consistent with larger-scale SCAL measurements and the measured mercury-injection capillary pressure. We also show that a significant wettability alteration had occurred by measuring in-situ contact angles.
In a conventional formation evaluation process, the mud-filtrate invasion in the near-wellbore region is considered a bias that requires a well-log correction before any petrophysical evaluation. The developments presented in this paper show that the invasion zone is a valuable source of information to estimate dynamic properties that generally come only from core measurements, such as permeability, relative permeabilities, capillary pressure curves and formation factor.
In this approach, the invasion process is not simulated in itself, as it would lead to a very unstable inverse problem within the time frame of the logging. On the contrary, it considers the fluids in the invaded domain as radially equilibrated and solves the fluid distribution governed at first-order by capillary pressures. Due to the multimodality of the inverse problem and the uncertainties related to the mud-filtrate parameters, the invasion zone is jointly inverted with the vertical capillary equilibrium at field-scale describing the vertical water saturation profile in the reservoir for each facies. The following workflow is then used: First, the invasion is solved in the water intervals while inverting the resistivity logs. The resolved parameters are the local volume of filtrate, pseudopermeabilities and cementation factors at each depth. At the end of this step, we get an insight of the number of petrofacies and the correlation between permeabilities and porosities inside each of these. Second, the inversion in itself is carried out in the hydrocarbon zone by exploiting the grouping from the first step. The vertical capillary equilibrium is added and updates permeabilities (absolute and relative) as well as capillary pressure models for each facies.
In the context of this paper, we present a vertical well and consider a radial oil-based mud invasion. We also assume isotropic petrophysical parameters. The final results are compared to all available sources of data, such as NMR, WFT and cores for permeabilities, formation factor and capillary pressure curves.
The ultimate added value of such an approach is to bridge static and dynamic petrophysical parameters from a single source of data: logs. It provides a reliable first guess of petrophysical and reservoir parameters at an early stage of the well evaluation. It also ensures an overall consistency of the formation model for the whole range of facies and fluid configurations. The technique can even help in the formation heterogeneity and petrophysical upscaling when run in a multiwell configuration.
The standard model for relating bulk formation resistivity to porosity and water saturation was introduced to the petroleum industry in 1941; it remains the industry standard to this day. The model was discovered empirically by means of graphical analysis. Basically, G.E. Archie discovered that when the logarithm of formation resistivity factor was plotted against the logarithm of porosity the resulting trend could be fitted by a straight line. A similar relationship was discovered connecting the logarithms of resistivity index and water saturation. When these two power laws are combined into a single equation, it can be solved for water saturation (which is not observable from a borehole) in terms of bulk formation resistivity, interstitial brine resistivity, and porosity (all of which can be estimated from observations made in boreholes). This revolutionized log interpretation. There has always been a problem with the model in terms of its “explainability”. That is, it cannot be derived in any straightforward way from accepted first principles of physics. It does not contradict any first principle, but neither does it seem to follow ineluctably from them. However, since the model works, most formation evaluators have memorized the relationships that follow from the model and simply “get used to them”. That remains the situation to this day. However, there is a path around this obstacle to understanding formation resistivity at a fundamental level, and that way forward is to abandon the resistivity formulation in favor of its reciprocal, conductivity. It is surprising that such a seemingly trivial change could open a new vista into the relationships among formation electrical properties. A conductivity formulation permits the asking of questions about how a formation’s conductivity should respond to changes not only in brine conductivity, but also in the fractional amount of brine in a formation, and its geometrical configuration. By answering these questions in an obvious way, and with some analysis of data taken in the laboratory, an intuitively obvious model explaining bulk formation conductivity emerges. The model is not the same as the Archie model. However, when certain parameters are taken to their limiting values, and the model is converted into resistivity space, Archie’s power law model is revealed as an approximation to the limiting cases. Thus, from the conductivity formulation, an intuitive understanding of the Archie model emerges. Moreover, the conductivity model can be derived in at least three different ways, each yielding different insights into formation conductivity.