The structure of the fracture network formed by hydraulic fracturing operation is one of the key parameter in production from unconventional shale reservoirs. The standard approach to obtain such information is usually through well-testing coupled with micro-seismic monitoring. Unfortunately, the micro-seismic mapping is not always carried out and the conventional well-test techniques often fall short in describing the flow in shale reservoir in particular the contact area of the fractures open to flow.
The other alternative technique to get insight into structure of the fracture network is to use chemical tracer tests. In this study, we propose a new simple and cost efficient technique to estimate the fracture contact area by tracking the major exchange cations in shale reservoirs.
The idea behind the proposed technique is to replace the major cations on fracture surfaces in shale by increasing the concentration of one of the major cation in fracturing fluid. The current technique is satisfied the industry standard practice as the high concentrated K+ is part of hydraulic fracturing fluid composition and therefore cation exchange with other major cations (Na+, Ca++ and Mg++) is expected to occur.
In order to test the feasibility of the proposed techniques, a set of laboratory tests were conducted where a shale sample was milled and sieved to three different sizes to have different contact area. They are then placed in a high pressure cylinder (built for this study) and were washed by concentrated NaCl solution under high pressure and controlled temperature. The effluent was collected successively and analysed for major cations using ICP-MS. Correlation relating the cation exchange mass content to contact surface is proposed and calibrated using the data obtained from laboratory tests.
This paper presents experimental observations that delineate co-optimization of CO2 EOR and storage. Pure supercritical CO2 was injected into a homogeneous, outcrop sandstone under various miscibility conditions. A mixture of hexane and decane was used for the oil phase. Three experiments were run at 70oC and different pressures (1,300, 1,700 and 2,100 psi). Each pressure was determined using a PVT simulator to create immiscible, near-miscible and miscible displacements. Oil recovery, differential pressure and compositions were recorded during experiments. A co-optimization function for CO2 storage and incremental oil was defined and calculated using the measured data for each experiment. A compositional simulator was then used to examine gravity effects on displacements and derive relative permeabilities.
Experimental observations demonstrate that an almost similar oil recovery was achieved during miscible and near-miscible displacements whereas about 18% less recovery was recorded in the immiscible displacement. More decane was recovered in the miscible and near-miscible displacements than the immiscible displacement. The co-optimization function suggests that the CO2 storage efficiency was highest in the near-miscible displacement and that the near-miscible displacement displayed the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there were significant gravity effects in the near-miscible and miscible displacements. It was revealed that the near-miscible and miscible recoveries depend strongly on the end-point CO2 relative permeability which increased with miscibility.
Increasing greenhouse gas emissions in the atmosphere is becoming an important concern worldwide. Several methods have been proposed for mitigating CO2 emissions in the atmosphere, among which the sequestration of CO2 in subsurface formations is considered one of the technically feasible options (Bradshaw et al., 2007). CO2 sequestration requires capturing of CO2 from stationary sources, transporting it to an injection site and then injecting it into a subsurface geological formation. The subsurface formation can be a deep saline formation, an oil or gas reservoir and deep unmineable coal deposits. This paper deals with injecting CO2 into an oil reservoir.
Hussain, Furqan (U. of New South Wales) | Zeinijahromi, Abbas (U. of Adelaide) | Bedrikovetski, Pavel (U. of Adelaide) | Badalyan, Alexander (U. of Adelaide) | Carageorgos, Themis (U. of Adelaide) | Cinar, Yildiray (U. of New South Wales)
The paper presents a systematic laboratory study to investigate the underlying physical mechanisms for improved oil recovery as a consequence of low-salinity water injection. Three sister plugs of Berea sandstone were used in the experiments. All three plugs were initially saturated with high salinity water (4 g/L NaCl). Single phase water flow test was performed in the first plug. The salinity of the injected water was decreased gradually (4 g/L to 0 g/L NaCl). In addition to observe the permeability reduction with reducing salinity, the particle concentration was also measured of the effluents at different stages of the experiment. Higher particle concentration was observed during low salinity injection period. The second plug was subjected to primary oil (Soltrol) drainage to the connate water saturation, followed by high salinity (4 g/L NaCl) water injection. After this connate water saturation was restored by a second oil flood. Finally, low salinity (0 g/L NaCl) injection was carried out. For both high and low salinity floods; oil recovery, pressure drop and effluent particle concentration was noted. Numerical modelling was used to interpret the waterflooding data.
Five to ten times decrease in water relative permeability and some decrease in residual oil saturation were observed during the low-salinity waterflood. Treatment of the low-salinity coreflood data by a numerical model reveals the unusual decrease in water relative permeability with increasing water saturation at high water saturations. This observation is explained by the expansion of rock surface exposed to low-salinity water during the increase of water saturation. A reproducibility test was performed on the third sister plug which confirmed the observations of the second sister plug. The proposed laboratory-based mathematical model can be used to design the injected water concentration which is crucial for a low salinity waterflooding project.
Distributed Temperature Sensor (DTS) technology has recently developed to determine the zonal flow rate in gas/oil producing wells using the measured continuous temperature profile along the wellbore. Comapred to convenetial production logging tool (PLT), DTS has many advantages that can provide real time temperature data without any intervention. Temperature logging applications described in early researches included, location of gas entries, detection of casing leaks and fluid movement behind casing, location of lost - circulation zones, and evaluation of cement placement. Temperature logs are still used for these applications and others, but the most common use now is quanitative identification of injection or production zones. Despite the many other logs that have been developed, the temperature log remains the workhorse of the production logging stable. This is primarily because of its reliability; no matter what the wellbore flow conditions, temperature can be measured accurately, also the temperature logs tends to reflect the long term behavior of well, not just the current conditions. This paper presents a new methodology developed to allocate gas rate and associated water of each individual layer using (DTS) and the total surface production of gas and water, also the pressure along the wellbore. The physics behind this model is based on steady-state gas-water flow in the wellbore, friction loss and Joule-Thomson effect in the wellbore, contrast in the thermal and physical properties of gas and water, wellbore heat losses due to unsteady heat conduction in the earth, and the mixing of the fluid streams of contrasting temperature. The methodology allows users to run in two modes: forward simulation and flow profiling.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE EOR Conference at Oil and Gas West Asia held in Muscat, Oman, 16-18 April 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. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The microstructure of carbonate rocks experiences substantial changes under reactive processes, in particular chemical dissolution and deposition including dissolution-released fines migration occurring during acidizing. A better understanding of such changes at the pore scale and their influences on rock properties is of great value for the effective design and implementation of reactive processes in carbonate reservoirs. In this work, we demonstrate the use of X-ray micro-computed tomography (μ- CT) to quantitatively investigate the local porosity changes in a meso/microporous carbonate core sample during chemical dissolution. A reactive flooding experiment in a core sample by a non-acidic solution is designed such that changes in pore space from before to after the reactant injection could be imaged in exactly the same locations using μ-CT at resolution of less than 5μm. This technique allows the incorporation of microporosity into the calculation of the evolution regions including the migration of fines in order to accurately quantify the evolution scenarios. The µ-CT images reveal a quasi-uniform dissolution pattern and allow characterizing the accompanying migration of fines within the core sample. These results can explain why permeability of the sample initially decreases and then increases as injection time increases.
Feali, Mostafa (U Of New South Wales) | Pinczewski, Wolf Val (U. of New South Wales) | Cinar, Yildiray (U. of New South Wales) | Arn, Christoph (U. of New South Wales) | Arns, Ji-Youn (Australian National Univ.) | Francois, Nicolas (Australian National Univ.) | Turner, Michael (Digital Core Laboratories Pty Ltd) | Senden, Tim | Knackstedt, Mark
It is now widely acknowledged that continuous oil spreading films observed in two-dimensional glass micro-model studies for strongly water wet three-phase oil, water and gas systems are also present in real porous media and result in lower tertiary gas flood residual oil saturations than for corresponding negative spreading systems which do not display oil spreading behavior. However, it has not been possible to directly confirm the presence of spreading films in real porous media in threedimensions and little is understood of the distribution of the phases within the complex geometry and topology of actual porous
media for different spreading conditions. This paper describes a preliminary study using high resolution X-ray microtomography to image the distribution of oil, water and gas after tertiary gas flooding to recover waterflood residual oil for two set of fluids, one positive spreading and the other negative spreading, for strongly water wet conditions in Bentheimer sandstone.
We show that for strongly water-wet conditions and a positive spreading system the oil phase remains connected throughout the pore space and results in a low tertiary gas flood residual oil saturation. The residual oil saturation for the corresponding negative spreading system is significantly higher and this is shown to be related to the absence of oil films in this system. The presence of films for positive spreading systems and the absence of such films for negative spreading systems is further confirmed by the computation of the Eurler characteristic for each phase.
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.
At the conclusion of flooding an oil- or gas-bearing reservoir, a significant fraction of the original hydrocarbon in place remains trapped. In addition to determining the amount of residual phase, knowledge of its microscopic distribution within the rock pore space would allow a better understanding of recovery mechanisms, and the design and implementation of improved or enhanced recovery processes. While the importance of the pore scale structure, mineralogy and wettability in dictating the residual phase distribution is widely acknowledged, little quantitative information on these properties and dependencies has been directly available. To this end, we describe an ongoing interdisciplinary study, bridging the core-, pore- and molecular scales using x-ray microtomographic imaging, petrographical imaging and wettability imaging. The experimental techniques used are reviewed, emphasizing the registration technology which enables spatial alignment and integration of 2D SEM-based information with 3D µ-CT images. Application of these techniques to visualization of pore scale oil and brine populations is presented, with a particular focus on characterizing native state carbonate plugs. In parallel, direct visualization of the alteration of rock surface chemistry at the pore- and molecular scales due to oil exposure is presented for macroporous and microporous reservoir carbonates. This interdisciplinary approach provides the foundation for more systematic development of strategies to increase recovery, in particular by tuning wettability.
The amount of residual hydrocarbon phase in a reservoir rock after flooding has obvious importance in determining the completeness of secondary recovery and the target for tertiary recovery. Further knowledge of the distribution of this trapped phase within the rock pore space would facilitate a more transparent and systematic approach to improved or enhanced recovery. In flooding experiments on reservoir core material, the core scale distribution of residual can be quantified (e.g. by magnetic resonance imaging or computerized tomography), however deeper insight into its configurations at the pore scale is necessary to better understand the underlying displacement mechanisms. Most methods previously pursued to characterize the residual oil phase at the pore scale use either idealized 2D micromodels (Lenormand et al. 1983) or destructive techniques on model liquids in rock (pore/blob casts) (Chatzis et al. 1983). The observations from these studies helped to ascribe rules for meniscus advance through connected pores in simple network models of multiphase flow. The enormous advances in x-ray micro-computerized tomography (µ-CT) over the past decade have greatly increased the scope for imaging rock pores and calculating properties from the digitized 3D images. This has allowed network models to more realistically incorporate the geometry and topology of pores in rock cores. However, the corresponding characterization of mineralogy and wettability to specify the pore scale distribution of molecular-scale surface chemistry adorning the pore walls is lacking, and thus the pertinent contact angles to be used in modeling are not known. Further, the ability to 3D visualize with µ-CT the residual phase occupancy in individual pores of rock cores is required to test the predictive power of such models and guide any augmentation of the mechanisms of pore displacement in real rocks to obtain better agreement.