Dernaika, Moustafa (Ingrain Inc) | Kalam, Mohammed Zubair (Abu Dhabi Co. Onshore Oil Opn.) | Dawoud, Ahmed Mohamed (Abu Dhabi Co. Onshore Oil Opn.) | Basioni, Mahmoud Ali (Abu Dhabi Co. Onshore Oil Opn.)
Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends due to variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.
A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRT) were selected based on whole core and plug X-ray CT, NMR T2, MICP, porosity, permeability and thin-section analyses. Primary drainage and imbibition water-oil relative permeability (bounding) curves were measured on all the five rock types by the steady state technique using live fluids at full reservoir conditions with in situ saturation monitoring. Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone by varying connate water saturations.
Hysteresis effects were observed between primary drainage and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e. wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual energy CT scanning and high resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves which were explained by different pore level fluid flow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate water. Relative permeability to oil was explained based on the occupancy of the oil phase at varying connate water saturations. The change in water relative permeability trend was addressed based on the connectivity of water at the varying connate water saturations. These results and interpretations introduced improved understanding of the hysteresis phenomena and fluid flow behavior in the transition zone of a cretaceous carbonate reservoir which can assist in the overall reservoir modeling and well planning.
This paper describes the work undertaken to build a 3D static model of a Lower Cretaceous Carbonate Reservoir located in Kazakhstan called X-Field. This reservoir has been pervasively dolomitized, and presents several challenges for development optimization. This model will be used to support further appraisal and development activities, in order to tackle key uncertainties, such as reservoir quality distribution.
All of the available data were quality controlled, analyzed and interpreted (including data from logs and cores), to produce porosity, permeability and RRT (reservoir rock type) models. These are believed to be representative of the reservoir's behavior and connectivity.
In order to identify the main flow zones and understand the reservoir's complexity, Reservoir Rock Typing (RRT) was performed on two cored wells by analyzing CCAL and SCAL data, including thin sections, MICP measurements, porosity and permeability. A comprehensive RRT methodology using Winland R35 method and poro-perm plot was followed, which resulted in defining five rock types. The outcome from the RRT study was confirmed by poro-perm plot, which showed the presence of five flow units.
The 3D model was built by using corner point grids (CPG), and contains a total of 2,380,050 cells. Several models of porosity and RRT were generated, representing "low??, "mid??, and "high?? case scenarios of reservoir quality distribution. Finally, permeability models were created for each scenario, conditioned to their respective Winland R35 porosity-permeability relationships per RRT.
Comparison between the different porosity (F), permeability (k), and RRT models and scenarios, will allow a better management of the reservoir uncertainties during the appraisal and development stages for this reservoir.
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
More than 30 years of experience in Middle-East carbonate reservoirs has allowed TOTAL to propose an original integrated workflow to characterize sedimentary and petrophysical properties from core and log data in order to populate, propagate and consequently predict the reservoir behavior within a geomodel.
An onshore field from Abu Dhabi has been recently studied with focus on the Upper Kharaib formation. Based on a detailed sedimentology and diagenesis investigation on cores, Petro-Geological Groups (PGG) are defined from both sedimentology, petrophysics, and associated logs responses. Comparison of PGG with Petrophysical Groups (PG), built from discriminant CCA and Pc data through objective statistical contingency and non-linear loops, strengthens the geological significance of the PG which can be considered as static rock-types.
Saturation laws defined from Pc plugs are thenafter compared with Sw resulting from preliminary quantitative interpretation as additional control of consistency between coresand log data.
Supervised facies modelling allows for the vertical distribution of these PGG throughout the non-cored intervals.
Permeability modelling is also an important step in order to deliver a permeability field within the geomodel. This small scale permeability (issued from the cores and logs) is compared with large scale permeability (from well tests) to insure reconciliation between the two scales.
PGG maps are delivered for each reservoir layer, associated petrophysical properties can be consequently propagated in 3D.
This powerful integrated workflow, relying on a comprehensive integration of all available data at different scales, has been successfully applied for geomodelling issue, allowing for both the understanding and the prediction of petrophysical properties distribution, with a strong relationship between Petrophysics and Geology at core and log scales. This approach gives significant support for the defining and capturing of key flow units heterogeneity and distribution.
GENERALITIES ON FIELD
The structure is an elongated faulted NE-SW anticline of about 25km long and 6km wide on Onshore Abu Dhabi (UAE). The field has been producing for more than 40 years. It is composed of 3 units which are in pressure communication across crestal normal faults. These 3 reservoirs thicknesses are respectively 60, 140 and 80 ft. Each zone is bounded at top and bottom by a dense limestone. Faulting (mainly NW-SE faults) is important and marked by vertical throws often higher than reservoirs thickness. The field geometry is controlled by more than 190 wellbores and a full-field 3D seismic acquired in 2007. The dip of the reservoir is about 1 to 5°. Reservoir permeability is low to moderate, but porosity is locally well developed.
The studied reservoirs belong to Upper Kharaib formation of Barremian to Aptian age. The present study is focused on the second unit presenting a moderate permeability level. This reservoir can be divided into two sub-units : Lower reservoir (low permeability mud-supported facies dominated ) and Upper reservoir (with grainy facies occurrences resulting in higher permeability).
Hydrocarbon gas injection has proven to be one of the most efficient Enhanced Oil Recovery (EOR) methods, especially for tight and heterogeneous reservoirs with light to medium API oil, where water flooding is expected to be inefficient. Asphaltene precipitation and deposition, however, might occur due to pressure and fluids compositional changes with the gas injection. This complex phenomenon requires experimental and numerical investigation to understand the conditions at which flow impairment due to asphaltene formation damage may occur, resulting in lowering well flow capacity and in turn lower ultimate oil recovery.In this experimental study, low permeability carbonate rock core samples were flooded with hydrocarbon gas under reservoir conditions. The floods were conducted on core samples of two different lengths representing two different rock types based on average rock permeability and Pore Throat Size Distribution (PTSD). Additionally, these core samples were flooded at two different operating conditions to mimic the average reservoir and the wellbore flowing pressure conditions. As a prelude to these experiments, Asphaltene Onset Pressure (AOP) and Asphaltene Onset Concentration (AOC) of the oil under study with the injection gas were established through NIR, SARA and Titration analysis.Flow impairment due to formation damage by asphaltene precipitation and deposition was analyzed through permeability measurements before and after gas flooding. In all cases permeability reduction was observed. Permeability reduction was found to be function of rock types, reservoir pressure, and length of composite core samples. We assume that pore throat bridging by the larger size asphaltene particles caused higher permeability reduction in the samples of poorer rock types. Experiments conducted at lower pressures showed more damage. This is consistent with the lower AOC at lower pressure. Longer core samples give more time for asphaltene flocculation resulting in more asphaltene formation damage and more permeability reduction. Scanning Electron Microscopic (SEM) images of core plugs before and after the gas flooding process were found to be not conclusive with respect to direct detection of asphaltene deposition in the core samples and further work is planned to positively identify asphaltene deposition in the rock samples.
Asphaltene are the polar, polyaromatic and heaviest hydrocarbon fraction of crude oil that are soluble in light aromatic hydrocarbons and solvents such as benzene and toluene but insoluble in low molecular weight
parafins1-4. As a result of reservoir fluid depressurization, asphaltene particles may deposit on the formation rock surface and/ or to plug the rock pore throats. Another practical reason reported in the literature is the injection of different solvents for oil displacement during Enhanced Oil Recovery (EOR) processes, which often leads towards the reservoir fluid composition alteration and hence results in the Asphaltene flocculation and deposition.
Our studies of the underlying fundamental gas-recovery mechanisms from shale gas are motivated by expectations of the increasing role of shale gas in national energy portfolios worldwide. We use pore-scale analysis of reservoir shale samples to identify critical parameters to be employed in a gas-flow model used to evaluate well-production data. We exploit a number of 3D-imaging technologies to study the complexity of shale pore structure: from low-resolution X-ray computed tomography (CT) to focused ion beam and scanning electron microscopy (FIB/SEM). We observe that heterogeneity is present at all scales. The CT data show fractures, thin layers, and density heterogeneity. The nanometer-scale-resolution FIB/SEM images show that various mineral inclusions, clays, and organic matter are dispersed within a volume of few-hundred µm3. Samples from different regions differ sharply in the shape, size, and distribution of pores, solid grains, and the presence of organic matter. Although the samples have clearly distinguishable signatures related to the regions of origin, extremely low permeability is a common feature. This and other pore-scale observations suggest a bounded-stimulated-domain model of a horizontal well within fractured shale that accounts for both compression and adsorption gas storage. Using the method of integral relations, we obtain an analytical formula approximating the solution to the pseudopressure diffusion equation. This formula makes fast and simple evaluation of well production possible without resorting to complex computations. It ss a decline curve, which predicts two stages of production. During the early stage, the production rate declines with the reciprocal of the square root of time, whereas later, the rate declines exponentially. The model has been verified by successfully matching monthly production data from a number of shale-gas wells collected over several years of operation. With appropriate scaling, the data from multiple wells collapse on a single type curve. Pore-scale image analysis and the mesoscale model suggest a dimensionless adsorption-storage factor (ASF) to characterize the relative contributions of compression and adsorption gas storage.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157031, "Application of Nanotechnology in Drilling Fluids," by Katherine Price Hoelscher, SPE, Guido De Stefano, SPE, Meghan Riley, SPE, and Steve Young, SPE, M-I SWACO, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
In this paper, techniques have been developed to experimentally and numerically evaluate performance of waterflooding and CO2 flooding for unlocking oil resources from tight formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.081-0.790 mD are used to conduct a series of coreflooding experiments. The performance of four flooding schemes, i.e., waterflooding, near-miscible CO2 flooding, miscible CO2 flooding, and water-alterneating-CO2 flooding, are evaluated by the coreflooding experiments. The continuous CO2 flooding processes under either miscible or near-miscible condition lead to a superior oil recovery performance in comparison with the waterflooding process. Furthermore, the miscible water-alternating-CO2 flooding in tight cores leads to a higher recovery efficiency with less CO2 consumption compared to the continuous CO2 flooding processes. Most importantly, in the miscible water-alternating-CO2 flooding process, it is found that the pressure drop increases rapidly when water is injected, but decreases dramatically when CO2 is injected. This indicates that CO2 injection is able to significantly improve the fluid injectivity in tight formations. In general, the miscible water-alterneating-CO2 flooding process is found to be the most favorable flooding scheme for tight formations in terms of both recovery efficiency and fluid injectivity. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different flooding schemes. There exists a generally good agreement between the experimental measurements and simulated results for all the flooding schemes examined. The tuned numerical model is then employed to optimize the production pressure in the continuous CO2 flooding process and the water-alternating-gas (WAG) ratios in the miscible water-alternating-CO2 (CO2-WAG) flooding process, respectively. It is found that the optimum producing pressure in the continuous CO2 flooding process can be set as the minimum miscibility pressure (MMP) of the tight oil sample, while the optimum WAG ratio falls in the range of 4:1 to 8:1.
Proper characterization of reservoir quality of tight shales is critical for evaluating reservoir potential. These reservoir quality properties typically include hydrocarbon filled porosity, permeability, organic content and maturation, and pore pressure. Of these, permeability measurements are among the most complex to obtain, and have been subject to much discussion. Key concerns are the lack of analytic modeling, poor reliability, poor consistency, and ignoring stress sensitivity in the measurements. This paper reviews the pressure decay permeability method using crushed rock, and includes laboratory test results to validate the findings. Part of the review is a numerical model for the pressure decay method. This model includes significant processes of pipe flow in the equipment, thermal effects, diffusion into rock fragments, Klinkenberg effects, and size, shape and anisotropic permeability of the fragments.
The paper shows that the measured permeability stress dependence, in tight shales, arises from coring induced microcracks. These result from failure of weak contact planes that are naturally occurring within tight shales and fail during coring and core retrieval. Permeability stress dependence in-situ is slight, as is show by compression test measurements to greater than thirty thousand psi. Crushing the rock to create small fragments for permeability measurements effectively removes these microcracks, and allows evaluation of real in-situ properties. Alternatively, closing microcracks by applying confining stress on plug samples, as routinely done for steady state and pulse decay measurements, is possible, but problematic because the critical stress required for microcrack closure changes from rock to rock facies.
The pressure decay permeability method on crushed rock is shown to provide very consistent results that agree with other measurement techniques. The numerical model relates specific ranges of fragment sizes and testing conditions, to measured ranges of permeability. This allows permeability measurements and numerical model analysis for a broad range of variability in permeability that can be measured in heterogeneous tight shales. With some exceptions (e.g., Cui et.al. 2009), the fundamental understanding of the petrophysical properties of tight shales have not previously included rigorous confirmation of experimental measurements by analytical methods.