Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s)). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated.
The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25?C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR).
Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca-montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d-spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2for 24 hours at 25?C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
Energy demand has been escalating and is predicted to increase further in the coming decades. The dialogue on global climate change has the world abuzz on the primary green house gas, carbon dioxide. Both of these factors have created a perfect storm for the use of carbon dioxide for enhanced oil recovery. The petroleum industry is ideally suited for disposing of this green house gas. Each oil company (and others) has therefore stepped up its efforts in carbon dioxide utilization, either for EOR or sequestration. The injection of CO2 into a reservoir is not new. Indeed CO2 injection has established itself as a very efficient mechanism for increasing oil recovery.
To design a CO2-EOR or CO2 sequestration project, one requires a large set of appropriate experimental data for a given reservoir/fluid system. Where does one start? Even if the data have to be generated in a service lab, a good design requires some thought and effort. A search of the literature reveals no best practices for generating this dataset. This paper presents a comprehensive experimental design for conducting a CO2 laboratory study.
The essential components of a laboratory study for CO2 injection include measuring fluid-fluid interactions and fluid-rock interactions. Fluid-fluid studies include miscible displacement tests, measurement of minimum miscibility pressures, fluid properties of CO2-oil or CO2-brine mixtures including viscosity and density, asphaltene precipitation, and swelling. Fluid-rock interaction studies typically include coreflooding tests for determining the oil recovery potential, three-phase relative permeability, critical gas saturation, gas trapping and wettability changes. Each of these sets of experiments will be described in light of their best practice. The ultimate goal is to establish a procedure for generating a reliable and accurate dataset.
Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR)
operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated.
The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR). Additionally, environmental scanning electron microscope (ESEM) analysis was used to explore the effect of liquid-like CO2 on clay structure of both dry and hydrated Ca and Na- montmorillonite clays.
Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Camontmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) dspacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical
CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
Dehghan Khalili, Ahmad (U Of New South Wales) | Arns, Christoph Hermann (University of New South Wales) | Arns, Jiyoun (U. of New South Wales) | Hussain, Furqan (U. of New South Wales) | Cinar, Yildiray (U. of New South Wales) | Pinczewski, Wolf Val (Australian National University) | Latham, Shane (Saudi Aramco) | Funk, James Joseph
High-resolution Xray-CT images are increasingly used to numerically derive petrophysical properties of interest at the pore scale, in particular effective permeability. Current micro Xray-CT facilities typically offer a resolution of a few microns per voxel resulting in a field of view of about 5 mm3 for a 20482 CCD. At this scale the resolution is normally sufficient to resolve pore space connectivity and transport properties. For samples exhibiting heterogeneity above the field of view of such a single high resolution tomogram with resolved pore space, a second low resolution tomogram can provide a larger scale porosity
map. The problem then reduces to rock-typing the low resolution Xray-CT image, deriving viable porosity-permeability transforms from the high resolution Xray-CT image(s) for all rock types present, and upscaling of the permeability field to derive a plug-scale permeability.
In this study we characterize spatially heterogeneity using overlapping registered Xray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38mm diameter carbonate core is studied in detail and imaged at low resolution - and at high resolution by taking four 5mm diameter subsets, one of which is imaged using full length helical scanning. Fine-scale permeability transforms are derived using direct porosity-permeability relationships, random sampling of the porosity-permeability scatter-plot as function of porosity, and structural correlations combined with stochastic simulation. A range of these methods are applied at the coarse scale. We compare various upscaling methods including renormalization theory with direct solutions using a Laplace solver and report error bounds.
We find that for the heterogeneous samples permeability typically increases with scale. Conventional methods using basic averaging techniques fail to provide truthful vertical permeability due to large permeability contrasts. The most accurate upscaling technique is employing Darcy's law. A key part of the study is the establishment of porosity transforms between highresolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.
The Ghawar field in Eastern Saudi Arabia contains the largest accumulation of carbonate reservoirs in the world. The majority of wells in the field produce from the Arab-D reservoir, an Upper Jurassic limestone sealed by anhydrite. Oil production from the field started approximately 55 years ago. Water injection started in the 1970's. Long before water injection was considered for the reservoir, the evaluation of wettability was considered essential.
Our present day evaluation of Arab-D wettability takes into account a long historical record of wettability measurements and production history. The procedures, results and caveats of the original measurements have changed slightly but they also show a strong consistency fifty years later. Wettability indices obtained from initial tests, Amott, and USBM methods generally indicate neutral to slightly oil-wet character for cores processed and tested in a preserved state. Comparisons with restored state cores did not indicate major differences. Over the years fluids used in coring operations and core preservation have shown little impact on the observed results.
Local variations in wettability indicating mixed wettability and oil-wet tendencies can be observed when tar is present in a significant amount and in areas high on structure. The combination of methods from advanced SEM observations, to qualitative contact angle measurements, to relative permeability results all point to a common wettability value.
Core analysis data determined in the laboratory are often treated as ground truth in processing logs. Experimentally, core data is procedurally dependent. For special applications, a laboratory core analysis program needs to be designed fit-for-purpose. For example, oil migrating into a water saturated reservoir is a drainage process while waterflooding an oil reservoir is a water imbibition process. Due to the combined effect of pore structure and wettability, hysteresis exists between drainage and imbibition. To mimic fluid flow and distribution in reservoirs, hysteresis of laboratory determined petrophysical properties have to be considered in processing logs across oil and water flushed zones.
In this study, a fit-for-purpose laboratory core analysis program for reservoir saturation monitoring was designed. Scanning curves of capillary pressure and resistivity index were generated in the laboratory and used in formation evaluation and reservoir saturation monitoring of a carbonate reservoir. Petrographic studies were also conducted to aid in understanding the effect of pore structure on rock properties. Two field examples are shown to demonstrate the added value of integrating the resistivity log analysis with fit-for-purpose core analysis data for improved formation evaluation and reservoir saturation monitoring.
The collection of core samples from a reservoir is essential for its proper characterization. Core data play very important roles in the following: log calibration, well treatment and performance prediction, reservoir modeling and simulation, and production and development planning.Coring is time-consuming, expensive and risky.It is difficult, if not impossible, to retrieve whole cores from horizontal and maximum reservoir contact (MRC) wells — which form the bulk of wells being drilled at present. As an alternative to coring, the use of cuttings has been proposed by many, as cuttings are always available from wells. Aside from some loss, contamination and depth-uncertainty (typically within 10 ft), cuttings show strong potential to represent all the formations encountered during the drilling of a well.
This paper discusses the capabilities of various laboratory instruments to extract reliable density and porosity data from cuttings. The methodology used involves full characterization of a carbonate core plug using several laboratory tools followed by crushing the plug into cuttings of different mesh sizes. Samples of different mesh sizes were then scanned with a CT-scanner and bulk densities and porosities were calculated using advanced histogram-based analysis techniques. Results for individual cuttings sizes were compared against those for the whole plug. Additional data on the same cuttings were generated using micro-CT, Environmental Scanning Electron Microscope (ESEM), Nuclear Magnetic Resonance (NMR) spectrometer and APEX (Apparatus for Pore Examination) mercury porosimeter, which were also used for comparison. A set of procedures was developed for generating porosity data based on image processing of SEM and micro-CT generated images. The work helped establish the size of about 2.5 mm as the limit of detectability of medical-based CT-scanners to generate reliable density and porosity data from drilled cuttings. Comparison between the micro-CT and ESEM data showed the range of application for each tool in determining porosities from cuttings.Comparison between the pore size distributions generated by the NMR and APEX mercury porosity instruments and their visual comparisons with ESEM images provide important insights for the pore network modeling efforts.
Saudi Arabia has a variety of carbonate reservoirs of different geologic ages. Such reservoirs are characterized by heterogeneous rock properties. These heterogeneities are caused by wide spectrum of environments in which carbonates are deposited and subsequent alteration of original rock fabric.
Extensive SCAL work was carried out on preserved core plugs recovered from two distinct carbonate reservoirs. The first reservoir is a Late Jurassic Arab-D offshore carbonate reservoir (Abu Safah field).The second one is Shu'aiba reservoir (Lower Cretaceous) located in Rub' Al-Khali in southeastern Saudi Arabia. The purpose of this study is to provide and evaluate waterflood recovery efficiency and residual oil saturations of the two distinct Arabian reservoirs.
Variation of oil recovery and residual oil saturation between the two distinct reservoirs is due to variations of rock characteristics especially the relationship of textural and diagenetic features which affect the size and distribution of pore throats. Shu'aiba reservoir rock could be classified as wackstone which demonstrates a higher ratio of lime mud to detrital grains (pore sizes ~ 0.27 to 1.5 microns). On the other hand, Arab-D reservoir is classified as grainstone and consists of oolitic limestone and dolomitic limestone with larger pore sizes (0.5 to 5.5 microns).
The results indicated that pore structure, pore size distribution, rock fabric, and environment of deposition are important factors that affect microscopic oil and water flow in porous media and the development efficiency of an oil field developed by water injection. Oil recovery from Arab-D reservoir is slightly higher than that of Shu'aiba reservoir.The residual oil saturations values for Arab-D reservoir were also found to be slightly higher than those of Shu'aiba reservoir. Arab-D reservoir showed less permeability dependence for both (Swir and Sor) end point saturations.