Some coreflood literature points to the initial wettability state undergoing change during waterflooding, usually towards water-wetness. The current study aimed to directly probe the adsorbed/deposited oil components on model silicate substrates prior to and after flooding. Bare glass and kaolinite-coated glass in the initial brine were drained with crude oil and aged, after which the oil was displaced with the flooding brine. For a matrix of initial and flood brines (comprising sodium and calcium) of varying salinity and/or pH, the oil remaining on the substrates was analyzed by high-resolution scanning electron microscopy, contact angle and spectroscopy. On glass, the oil layer contacting it in the initial (aged) state retracts and detaches during flooding, to typically leave individual oil nanodroplets separated by clean substrate. Brines less able to overcome the oil-glass adhesion displayed a higher coverage of more irregularly shaped, semiretracted drop-lets and a higher frequency of larger microscopic residues. On kaolinite-coated glass, the added porosity and roughness increased the presence of these adhering, stranded residues. On bare glass, the residual deposit after high salinity floodingis generally least at intermediate flood pH 6, while residues decrease with decreasing pH of low salinity floods. However, on kaolinite-coated substrates, residual deposit is greatest after flooding at intermediate pH 6, and also increases on reduction of flood salinity
This paper presents a method for determining the Archie saturation exponent, n, from a single, nonequilibrium centrifuge step. The input measurements include detailed 3D saturation distributions from magnetic resonance imaging and the DC conductivity of the sample under examination. The latter is obtained by making use of a patented 4-contact cell. The sample is modeled as a 3D conductivity network and a specially developed algorithm based on random walk (RW) is used to compute its overall conductivity in a very short time. The value of the n exponent is determined by matching the measured conductivity to the calculated one. The entire analysis takes one day. Examples demonstrate the method and details of the impedance cell and the RW algorithm are provided.
Profice, Sandra (I2M–TREFLE - Universite de Bordeaux) | Lasseux, Didier (I2M–TREFLE - Universite de Bordeaux) | Jannot, Yves (LEMTA - Nancy-Universite) | Jebara, Naime (TOTAL – CSTJF) | Hamon, Gerald (TOTAL – CSTJ)
Permeability estimation of poor permeable formations like tight or gas-shale reservoirs using a pulse-decay experiment performed on crushed samples has been shown in earlier works to be an interesting alternative for it is faster and less expensive than traditional transient tests performed on carefully prepared core plugs, although it is restricted to measurement in the absence of overburden pressure. Due to reservoir depletion during production, sample characterization over a wide range of pore-fluid pressure is essential. If the Darcy-Klinkenberg model is thought to be a satisfactory gas-flowmodel for these tight formations, the full characterization can be achieved by determining both the intrinsic permeability, kl, and Klinkenberg coefficient b.
In this work, the conditions under which reliable estimates of kl, b and porosity, ø can be expected from this type of measurement are carefully analyzed. Considering a bed of monodisperse-packed spheres and a complete physical model to carry out direct simulations and inversion of the pressure decay, important conclusions are drawn opening wide perspectives for significant operational improvement of the method. In particular, it is shown that:
i) The particle size of the crushed sample must be well selected for a reliable pressure-decay signal record.
ii) The simultaneous determination of both kl and b by inversion of the pressure-decay signal is very difficult because the sensitivities of the pressure decay to both coefficients are correlated
iii) The porosity of the particles can be accurately estimated when the experimental setup has been properly calibrated (volumes of the chambers and of the porous sample). The precision on the estimation of this parameter is however strongly dependent on a bias on the crushed sample volume.
iv) When identification of kl and b is possible, a very significant error may occur in the determination of the intrinsic permeability due to a bias on the porous sample volume. Errors on the estimated values of ø and kl due to a bias on the chamber volume are not very significant Moreover, b remains insensitive to bias on both the chamber and porous sample volumes.
Relative permeability to formation fluids is an essential input into reservoir characterization, dynamic modeling, and production prediction. In this work, a method combining evaporation and unsteady-state pressure-falloff technique is developed to measure gas-phase relative permeability on tight-gas cores for both drainage and imbibition cycles. Toluene is used to mimic formation water and its saturation is varied by evaporation and determined by mass balance. Nitrogen gas is used to imitate the hydrocarbon fluid, and the gas effective permeability at certain toluene saturations is measured by the pressure-falloff technique.
The method greatly reduces the measurement duration, and provides a relatively simple and effective way to characterize the gas-phase relative permeability for tight-gas cores. It has been applied on ~30 tight-gas cores from various fields. Results show that the gas relative permeabilities follow the Corey model with a Corey exponent of ~2 for the drainage cycle and ~3 for the imbibition cycle. The assumptions are studied by both numerical modeling and separate experiments.
Over the last two decades there has been an increase in activity on the pore-scale modeling of multiphase flow in porous media. Excellent progress has been made in many areas of pore-scale modeling, particularly in (1) the representation of the rock itself and (2) our description of the pore-scale displacement physics (in model pore geome-tries). Three-dimensional voxelized images of actual rocks can be generated either numerically (e.g. from 2D thin sections) or from micro-CT imaging. A simplified network involving more idealized nodes and bonds can then be extracted from this numerical rock model and this can be used in modeling pore-scale displacement processes. Much progress has also been made in understanding these pore-scale processes (i.e. piston-like displacement, snap-off events, layer formation/collapse, pore-body filling draining). These processes can be mathematically modeled accurately for pores of non uniform wettability, if the geometry of the pore is sufficiently simple. In fact, in recent years these various pore-level processes in mixed and fractionally wet systems have been classified as "events" in an entire capillary-dominated "phase space" which can be defined in a thermodynamically consistent manner. Advances in our understanding and ability to compute several two- (and three-) phase properties a priori have been impressive and the entire flooding cycle of primary drainage (PD), aging/wetting change, and imbibition can be simulated.
In this paper, we review the successes of pore-scale network modeling and explain how it can be of great use in understanding and explaining many phenomena in flow through porous media. However, we also critically examine the issue of how predictive network modeling is in practice. Indeed, one of our conclusions on pore-scale modeling in mixed-wet systems is that we cannot predict two-phase functions reliably in "blind" tests. Interestingly, we make this statement not because we do not understand the pore-scale physics of the process, but because we do understand the physics. It is hoped that our comments will stimulate a more critical debate on the role of pore-scale modeling and its use in core analysis.
In the last 25 years there have been significant advancements in the use of well-logging tools to acquire detailed information on the occurrence of gas hydrates in nature: whereas wireline electrical resistivity and acoustic logs were formerly used to identify gas-hydrate occurrences in wells drilled in Arctic permafrost environments, more advanced wireline and logging-while-drilling (LWD) tools are now routinely used to examine the petrophysical nature of gas-hydrate reservoirs and the distribution and concentration of gas hydrates within various complex reservoir systems. Resistivity- and acoustic-logging tools are the most widely used for estimating the gas-hydrate content (i.e., reservoir saturations) in various sediment types and geologic settings. Recent integrated sediment coring and well-log studies have confirmed that electrical-resistivity and acoustic-velocity data can yield accurate gas-hydrate saturations in sediment grain-supported (isotropic) systems such as sand reservoirs, but more advanced log-analysis models are required to characterize gas hydrate in fractured (anisotropic) reservoir systems. New well-logging tools designed to make directionally oriented acoustic and propagation-resistivity log measurements provide the data needed to analyze the acoustic and electrical anisotropic properties of both highly interbedded and fracture-dominated gas-hydrate reservoirs. Advancements in nuclear magnetic resonance (NMR) logging and wireline formation testing (WFT) also allow for the characterization of gas hydrate at the pore scale. Integrated NMR and formation testing studies from northern Canada and Alaska have yielded valuable insight into how gas hydrates are physically distributed in sediments and the occurrence and nature of pore fluids(i.e., free water along with clay- and capillary-bound water) in gas-hydrate-bearing reservoirs. Information on the distribution of gas hydrate at the pore scale has provided invaluable insight on the mechanisms controlling the formation and occurrence of gas hydrate in nature along with data on gas-hydrate reservoir properties (i.e., porosities and permeabilities) needed to accurately predict gas production rates for various gas-hydrate production schemes.
Experimental measurements of capillary pressure, resistivity index and relative permeability display hysteresis manifested through the dependence of these properties on the saturation path and saturation history whenever fluid saturations undergo cyclic processes. At the pore scale, hysteresis is typically influenced by contact-angle hysteresis, trapping of one phase by another and wettability changes.
A laboratory study was conducted to investigate hysteresis effects measured on reservoir core plugs for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering reservoir rock types (RRT) were selected based on whole-core and plug X-ray CT, high-pressure mercury injection, porosity, permeability and thin-section analyses.
Primary drainage and imbibition capillary pressure and resistivity index (PcRI) were measured by the porous-plate method using stock tank oil and simulated formation brine at reservoir temperature and overburden conditions. Large hysteresis effects were obtained between primary drainage and imbibition for both Pc and RI curves. Low residual oil saturations (Sor) were measured at the end of forced imbibition indicating oil-wet to mixed-wet characteristics. Nonlinear RI curves were found during imbibition which could not be described by conventional Archie equation. Water-oil relative permeability curves were measured on similar reservoir core samples by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. Hysteresis effects on both oil and water curves were observed between primary drainage and imbibition, and appear to be influenced by the sample rock type involved (i.e. wettability and pore structure).
The strong hysteresis in RI was explained by a fluid invasion behavior at the pore level, and was attributed to varying displacement mechanisms between primary drainage and imbibition. Conventional assumption of Archie behavior is therefore not always valid for such carbonate rock types. This RI hysteresis, together with the variation of K hysteresis trends with different rock types, may help improve the current hysteresis models and provide better understanding of the hysteresis phenomena in natural porous media.
Much has been written about methods for estimating and interpreting log measurements. These methods are highly dependent on the quality of the original acquired data sets. Wireline and logging-while-drilling (LWD) technologies have advanced to a level where today’s analysts frequently assume the acquired measurements are correct, unless problems are encountered when integrating the data. The assumption is generally valid, but starts to fail when conditions within the borehole being surveyed degrade to the point of falling outside the physical measurement limitations of the instruments.
When wellbore conditions reach a point where data degradation occurs, the information must be corrected for the environmental and borehole effects or, in extreme cases, the data must be reconstructed. Data reconstruction/estimation can take many forms, including translation applications of regional trends, transformation of one type of measurement into another type, extrapolation of offset well data to the well of interest, use of offset openhole data combined with cased-hole data in predicting the measurements on adjoining wells when only the cased-hole data are available, extraction of measurements from seismic, etc.. Methods involved in these endeavors vary from empirical algorithms to regional trend analysis, to statistical inference, and to neural nets. Successful application of any method requires data that are representative of the formations when acquired under optimal conditions.
Interpretation algorithms applied to the data are no different, in that data quality is assumed for the analysis models to function correctly. Proprietary internal and third-party external interpretation packages have problems when the data quality suffers.
Proper data reconstruction requires an understanding of the quality of the acquired data (calibrations, accuracy, etc.), the instrument configuration in the tool string, the acquisition methodology and the condition of the wellbore environment when the data were acquired.
We examine the application of several methods used in data preconditioning and data reconstruction, along with some novel statistical methods the authors employ, with examples in various environments. Validation of the reconstructed data sets is also demonstrated.
Recent advances in neutron-induced elemental spectroscopy (NIES) tools have provided quantitative measurements of a wide range of elements. These advances are welcome as they can enhance petrophysical analysis and provide important geological and engineering data. Enhancements in tool design and improvements in characterization and interpretation algorithms have increased the accuracy and precision of the measurements. These advances are especially important for the petrophysical analysis of heterogeneous reservoirs. In these reservoirs, detailed mineralogical quantification with deterministic methods is problematic. In comparison, probabilistic methods, using elemental data and error-minimization modeling can, if the input data are accurate, significantly improve the overall petrophysical interpretation of formation lithology and also porosity and water saturation. As a consequence, a study was conducted in a Middle East clastic field to evaluate and compare the accuracy and precision of different NIES tools in a controlled environment.
Three NIES tools, ECS™ (Schlumberger), FLEX™ (Baker Hughes), and GEM™ (Halliburton) were run back-to-back in the same well with the same borehole and mud conditions. In addition, a conventional core was also taken over the logged interval. Each company ran a natural gamma spectroscopy tool in combination with their NIES tools. The companies were provided the same baseline set of density, neutron, sonic and resistivity logs but were not given access to each other’s elemental spectroscopy log. The core was veneered and 1-ft long samples were crushed and homogenized. Each 1-ft sample was analyzed using X-ray fluorescence(XRF) for elemental composition and X-ray diffraction (XRD) for bulk and clay mineralogy.
The same methodology was used to analyze the data output from each tool. First, the elemental output from each logging tool was overlaid with the similar data from the other tools and compared to XRF core measurements. Second, the results of probabilistic mineral analyses of the NIES data and the baseline logs were compared to the XRD core data.
This paper presents the study results and compares elemental and mineralogical core data with data from the three NIES tools. The accuracy of each tool is reviewed and the effects of borehole and mud conditions on tool output are presented. Finally, recommendations are provided on job planning and effective use of NIES tools.
Machado, Vinicius (Petrobras Research Center (CENPES)) | Frederico, Paulo (Petrobras Research Center (CENPES)) | Netto, Paulo (Petrobras) | Bagueira, Rodrigo (Fluminense Federal university) | Boyd, Austin (Schlumberger Brazil Research and geo-engineering Center) | Souza, Andre (Schlumberger Brazil Research and geo-engineering Center) | Zielinski, Lukasz (Schlumberger-Doll Research) | Junk, Elmar (Schlumberger)
Existing carbonate classification schemes are based on quantifying rock texture by grain size or pore-throat size. They were developed from visual inspection of cores and cuttings, thin-section microscopy or mercury porosimetry. Recent advances in NMR log and core analysis, complemented by more quantitative use of borehole image logs, have led to the application of log-based porosity partitioning based on some of these earlier models. The foundation of this approach is the link between NMR T2 distributions and pore-size distributions obtained from special core analysis. Several case studies record the success of this approach in carbonate formations drilled with water-based mud, where the NMR response is well characterized and has been validated by core analysis.
The recently discovered carbonate reservoirs off-shore Brazil are typically drilled with oil-based mud to avoid drilling and completion problems in the 2000 m of salt overlying the reservoir. NMR logs are routinely run in the reservoir section and the interpretation methods developed for carbonates drilled with water-based mud have been adapted for evaluating reservoir quality, when oil-based mud is used. These carbonates tend to be oil-wet to the 28-30° API reservoir oil and to the oil-based mud filtrate; this ensures that surface relaxivity is the dominant relaxation mechanism in the NMR response, which enables the correlation of T2 distributions with the variety of pore sizes in the reservoir zones. Interpreting NMR logs in such conditions requires detailed knowledge of the oil-based mud filtrate and reservoir oil properties, and of the wettability of the formation at downhole conditions. One of the key requirements for correctly interpreting the NMR log data are to perform the lab NMR measurements of fluids and core samples at the same pressure and temperature conditions as the lab PVT measurements.
When compared with downhole NMR log data, lab measurements performed on native-state, restored-state, brine-saturated and partially-saturated cores at PVT conditions show that many of the existing carbonate classific-tion schemes can be applied to the presalt carbonates. The common features of these schemes will be examined, and the relevance of these various models to formation evalua-tion in the presalt carbonates will be reviewed. Options for analyzing borehole image logs in carbonates drilled with oil-based mud will also be presented as an aid to porosity typing with NMR. The key considerations for core analysis and for acquiring, processing and analyzing NMR and logs in carbonates drilled with oil-based mud are summarized.