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Petrophysical rock properties are the crucial point of any reservoir characterization project and represent fundamental input parameters for any simulation. To obtain reservoir characterization data such as porosity, absolute and relative permeabilities, typically core analysis tests are needed. Unfortunately, there are cases where these tests cannot be accomplished. In these situations, digital rock physics (DRP) techniques are useful and may represent a powerful approach to obtain these parameters. Fluid flow at the pore scale can be simulated by DRP. To compare DRP results (micrometric scale) and laboratory tests (centimetric scale), the implementation of an upscaling method is required. In this context, this work aims to propose a novel methodology to allow the digital characterization of rock properties at the plug scale. In particular, the developed workflow exploits and combines different technologies: micro-CT scan, advanced image processing, machine learning, CFD numerical simulation. The first step of the methodology consists of acquiring micro-CT low-resolution scan of the entire core plug; then, machine learning techniques are applied to decompose the digital plug (derived by image processing on micro-CT scan) in reference element of volume (REV)-type equivalent blocks, determining the optimum number of REV type and their locations. One or several high-resolution 3D fine-scale images are used to derive the petrophysical properties of each REV type from individual fluid flow simulations at the pore scale. The resulting REV-type properties are then scaled up to the core plug scale. Finally, the scaled up results are compared to the results of core analysis tests. The overall methodology is validated on a heterogeneous carbonate rock.

Estimation of mechanical and physical rock properties is an essential issue in applications related to reservoir geomechanics. Carbonate rocks have complex depositional environments and digenetic processes which alter the rock mechanical properties to varying degrees even at a small distance. This study has been conducted on seventeen core plug samples that have been taken from different formations of carbonate reservoirs in the Fauqi oil field (Jeribe, Khasib, and Mishrif formations). While the rock mechanical and petrophysical properties have been measured in the laboratory including the unconfined compressive strength, Young's modulus, bulk density, porosity, compressional and shear -waves, well logs have been used to do a comparison between the lab results and well logs measurements. The results of this study revealed that petrophysical properties are consistent indexes to determine the rock mechanical properties with high performance capacity. Different empirical correlations have been developed in this study to determine the rock mechanical properties using the multiple regression analysis. These correlations are UCS-porosity, UCS-bulk density, UCS-Vs, UCs-Vp Es-Vs, Es-Vp, and Vs-Vp. (*). For example, the UCS-Vs correlation gives a good determination coefficient (R2= 0.77) for limestone and (R2=0.94) for dolomite. A comparison of the developed correlations with literature was also checked. This study presents a set of empirical correlations that can be used to determine and calibrate the rock mechanical properties when core samples are missing or incomplete.

An experimental and numerical study was carried out to investigate matrix-fracture thermal transport in fractured rock. Two different synthetically fractured core plugs were used during the flow-through experiments while core plugs’ outer surface was maintained at two different constant temperatures. To investigate the matrix-fracture thermal transport, cold water was injected through the single fracture core plugs at different flow rates. A film type heat flux sensor was used in the fractured core plug to measure the fracture temperature and heat flux over the matrix-fracture interface. Experimental results showed that fracture temperature decreases with increasing flow rate while heat flux increases. At high flow rates, temperature difference over matrix-fracture interface increases due to large volume of water contacting the fracture at a given time. Water temperature decreased more in the case of fracture surrounded by rock matrix with low volumetric heat capacity and thermal conductivity. A numerical model calibrated using experimental values of the fracture temperature was developed to estimate thermal properties of rock matrix and to identify their importance on the matrix-fracture thermal transport. Using the calibrated numerical model, it has been shown that temperature in the fracture and fracture surface temperature are different contrary to previous studies assuming the same values for these two temperatures. Local and transient convective heat transfer coefficients were introduced with respect to local values of temperature difference and transient values of heat flux along matrix- fracture interface enabling accurate representation of matrix-fracture thermal transport.

The reservoir heterogeneity is the major cause of poor volumetric sweep efficiency in sandstone and carbonate reservoirs. Displacing fluids (water, chemical solution, gas, and supercritical CO2 (sc-CO2)) flow toward the high permeable zone. A significant fraction of oil remains in the low permeable zone due to the permeability contrast. This study used in situ sc-CO2 emulsion as a conformance control agent to plug the high permeable zone and improve the low permeable zone's volumetric sweep efficiency in carbonate formation. We investigated the effect of two types of conformance control patterns and the size of sc-CO2 emulsion on tertiary oil recovery performance by sc-CO2 miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are achieved using two different approaches. In the first approach, the low permeable zone was isolated, and the diverting gel system, a 0.4 pore volume slug, was injected into a high permeable zone. In the second approach, the simultaneous injection of the diverting gel system, a 0.2 pore volume slug, was done on both the low and high permeable zones. The first sc-CO2 injection was conducted as a tertiary oil recovery mode to recover the remaining oil after water flooding. The diverting gel system was injected after the first sc-CO2 flood for the conformance control. The second or post sc-CO2 injection was conducted after the diverting gel system injection. The diverting gel system used in this study consisted of a polymer and a surfactant. An in situ emulsion was generated when the injected diverting gel system interacts with the sc-CO2 in the core plug. Results obtained from dual-core core flooding experiments suggested that the in situ sc-CO2 emulsion was generated successfully in the formation based on the different pressure increases and observation of the dual-core core flooding experiments. The volumetric sweep efficiency and oil recovery in both conformance control patterns were improved. The production performances were also compared for both conformance control models before and after the diverting gel system injection. The conformance control model 2 (simultaneous injection of the diverting gel system into low and high permeability cores) has a better choice to be applied in field application due to high recovery with a small sc-CO2 emulsion easy operation in the field.

The promotion of enhanced gas recovery (EGR) and CO2 storage is still shrouded in contention and is not well accepted, due to the excessive in situ CO2 mixing with the nascent natural gas. This adulterates the recovered CH4 and thus results in a high sweetening process cost thereby making the technique impractical. This has not only limited the field application of EGR in actual projects to a few trails but renders it uneconomical. This study aims to present, experimentally, alternating N2 injection as a potential technique for EGR and CO2 storage in sandstone rock cores. A laboratory core flooding experiment was carried out to simulate a detailed process of unsteady-state methane (CH4) displacement using Bandera grey core plug. This was carried out at 40 °C, 1500 psig, and 0.4 ml/min injection rate by alternative injection of N2 and CO2 in succession designed to suit the application based on optimum operating conditions. The results show that both CO2 storage capacity and CH4 recovery improved significantly when gas alternating gas (GAG) injection was considered. The best results were observed at lower N2 cushion volumes (1 and 2 PV). Therefore, the GAG injection method with N2 as cushion gas can potentially increase both CO2 storage and CH4 recovery of the gas reservoir. This technique if employed will assert the current position and provide vital information for further researches aimed at promoting environmental sustainability and economic viability of the EGR and CO2 sequestration processes.

These paper contains a highlight of laboratory experiment to evaluate the work of chemical for sand consolidation to strengthen the bonding between grains of rock while do not cause permeability reduction significantly. This experiment used reservoir rock and fluids to understand the interaction between the chemical solution and the reservoir rock and fluid. Firstly, the reservoir rock and fluid were analyzed their properties. The rock has been analyzed using CT Scan to drill the best representative core plug for the experiments, using SEM to identify the pore throat and pore geometry of the rock, using XRD to determine the minerals composition which mostly quartz. While the fluids have been analyzed for the anions and cations content, viscosity and other important properties. The brine particle content and also particle size distribution of the rock have been also over lied in the graph in order to know the possibility of bridging particle in the pore throat, but the graph looks good that no problem may arise from the bridging particle. Chemical for Sand Consolidation has been used in this experiment. Sand consolidation chemical normally contain plastic resin that has a property of bonding between solid materials. It sticks on the surface of solid materials and bonding together.The core flooding experiments have been run for 4 times, 2 times using synthetic cores and the other two using native cores. The experiments used synthetic cores reduce the permeability significantly. However, after cutting both ends of the core the permeability has indicated improvement. The other 2 experiments using native cores have reduced the permeability approximately 4 times down. The last two experiments have no cutting the ends of core for further experiments, so they cannot be compared to the first two experiment. So, the experiment procedures must be improved for the next evaluation, such as during curing time the rate of injected oil may be increased to reduce the adsorption of chemical to the surface area of the pore and also to hinder the flocculation of chemical in the pore space.

Several researchers employed N2 to augment CH4 recovery efficiency and CO2 sequestration during the Enhanced Gas Recovery (EGR) process in consolidated rocks. To our knowledge, there has been limited data backing the reason why CO2 experienced a more extended breakthrough during the EGR process in the presence of N2 gas. This study inves-tigated CO2 and N2 behaviour during the core flooding experiment by CO2 injection in Bentheimer core plug. N2 was used as the continuous phase during the core flooding process, while CO2 was the dispersed phase. The experiment was designed with varying injection rates at 30 and 40 0C temperature points. The experimental findings showed that the dispersion and diffusion coefficient, CO2 storage, concentration profile and breakthroughs were highly influenced by temperature change, especially at lower injection rates. However, at high injections, those properties are less sensitive to change in temperature, with most of the curves overlapping in the concentration profile. The highest and most negligible dispersion and diffusion coefficients were recorded at the highest and lowest injection rates respec-tively. These results agree with those reported by several researchers for sandstone rocks. Thus, higher temperatures have a more substantial effect on dispersion and diffusion coefficient, which eventually led to higher mixing between CO2 and N2. The breakthrough time decreases with an increase in reservoir temperature, confirming the diffusion and dispersion coefficients are temperature dependent. The experiment at 30 0C recorded an extended breakthrough time over that at 40 0C. The maximum breakthrough time at 0.52 PV was recorded at 30 0C at the lowest injection rate. The concentration profile highlighted the trend between the displacing and displaced gas during the core flooding experiment. From the range of injections and temperatures tested, the CO2 PV stored decreases as the rate of injection increases from 0.4 – 1.2 ml/min. However, the CO2 stored was more promising at higher rates, corresponding with high differential pressure, due to flow resistance within the tortuous flow channels in the porous medium.

The low permeability conglomerate rock has a strong heterogeneity with a wide range of pore radius from submillimeter to nanometer. The traditional digital rock technology is based on micro-CT image with a resolution up to 0.5 µm, which leads to a lower porosity and higher permeability than the laboratory measurements. This paper proposed a new image upscaling method to capture the heterogeneity, and the conglomerate rock in the southern margin of Junggar, Xinjiang Oilfield, was used for validation. The micro-CT scan of the core plug was carried out to obtain the submillimeter porosity (with a resolution of 10-20 μm), and subsamples with a physical size of 1-3 mm3 were taken to obtain the micro-porosity (with a resolution of 1-2 μm). Then a small amount of samples was analyzed with a magnification of 500×, 5000× using scanning electron microscope (SEM) to obtain the nano-porosity image (with a resolution of 20-200 nm). The features of four-scale porosities are integrated to obtain the total porosity of the core plug, and the Brinkman method is used to calculate the permeability based on the multi-scale model. The results obtained by the image upscale method match the experimental data very well, which improves the digital rock technology for the industry practice.

Klinkenberg-corrected permeability (k∞) or water permeability (kw) is an important input parameter for hydrocarbon reservoir simulation studies. The theoretical concept that a core sample’s k∞ is comparable to its kw is flawed and has to be verified, since experimental evidence indicates that k∞ and kw are clearly different. Thus, a series of gas and water permeability measurements were conducted on eight carbonate core plug samples from Sarawak, Malaysia to develop a correlation between both permeability values. The new k∞ vs. kw correlation clearly proved the differences between both permeability values for all samples. The findings were in agreement with FESEM-EDX and total suspended solids (TSS) analysis, which proved the migration of fines and clay particles that blocked the pore throats, thus reducing kw values. The new k∞ vs. kw correlation was validated using four different samples from the PETRONS-2 well using its k∞ values and comparing them with the respective measured kw values. The new correlation will reduce the amount of time and cost needed to obtain absolute liquid permeability values but may be further improved by conducting permeability measurements on more samples from the PETRONS field, which will improve the accuracy of hydrocarbon reservoir simulation of the PETRONS field.

The North India's lowlands consist of soft alluvial deposits, which are saturated throughout the year. The construction of the conventional shallow foundation is very difficult in this area due to high groundwater table. A short open-ended steel pipe pile with soil plug is being proposed for this region. By using shear stress–displacement response for alluvial deposits, the proposed foundation is analyzed. Parametric studies are carried out to study the effects of length to diameter ratio (L/do), diameter ratio (d/do), and angle of shearing resistance of core plug (φsp) on the load sharing and the settlement of the proposed foundation.

Wettability controls the location, distribution, and flow of fluids in a pore network. Obtaining a uniform core scale wettability distribution is therefore a necessary condition for reliable special core analysis (SCAL). In the present work, dynamic and static aging procedures were used to alter the wettability of outcrop Edwards limestone, and Amott-Harvey cycles were performed on whole and split core samples to evaluate wetting distribution and stability. Dynamic aging was observed to be more efficient and produced a more uniform and reproducible wettability distribution compared to static aging. Rock-fluid and fluid-fluid interactions, evaluated by Isothermal Titration Calorimetry (ITC) experiments, confirm that supplying fresh crude oil during the aging procedure to a core plug causes the greatest wettability change. Synergy between ITC and simple core scale experiments provide an improved understanding of the wettability alteration at microscopic and macroscopic levels in heterogeneous Edwards limestone.

The efficiency of the dimethyl ether (DME) enhanced oil recovery (EOR) technique in a fractured chalk reservoir core plug was investigated. The coreflood experiment showed that DME EOR could lead t...

The inherent heterogeneity of carbonate rocks suggests that carbonate-hosted fault zones are also likely to be heterogeneous. Coupled with a lack of host–fault petrophysical relationships, this makes the hydraulic behaviour of carbonate-hosted fault zones difficult to predict. Here we investigate the link between host rock and fault rock porosity, permeability and texture, by presenting data from series of host rock, damage zone and fault rock samples from normally faulted, shallowly buried limestones from Malta. Core plug X-ray tomography indicates that texturally heterogeneous host rocks lead to greater variability in the porosity and permeability of fault rocks. Fault rocks derived from moderate- to high-porosity (>20%) formations experience permeability reductions of up to six orders of magnitude relative to the host; >30% of these fault rocks could act as baffles or barriers to fluid flow over production timescales. Fault rocks derived from lower-porosity (

In an attempt to characterize a reservoir in a field, importance is given to living models as it serves critical function in estimating if the reservoir under study is economically viable. Having a good knowledge of electrical response to reservoir rocks is important in characterizing and modeling the behavior of fluids at the subsurface. In this study, core plugs extracted from core barrels in a Niger Delta oil field were analyzed in the laboratory in order to determine the electrical properties of the samples and their relationship with each other and formation fluid. This was achieved by using a brine of a known concentration for simulation of core plugs. Results obtained show that for the unconsolidated sandstone, Formation resistivity factor increases with an increase in confining pressure. This characteristic depends on the porosity of the Formation and type of fluid present. Resistivity values in a reservoir will increase with an increase in capillary pressure and decrease with water saturation. The decrease in cementation exponent increases the rate of permeability in reservoir sand. However, resistivity values decrease with clay presence in reservoir sand.Keywords: Core plug, reservoir, resistivity, water saturation DOI 10.35180/gse-2019-0015

This article considers upscaling of polymer adsorption. Input to adsorption values employed in reservoir simulation models are typically obtained from core plug measurements. There are several orders of magnitude in scale difference between core plugs and grid cells in reservoir simulation models, which foster a need for upscaling of the adsorption values. Polymer concentration distribution on the lithofacies scale is investigated in this article. The effect of diffusion on concentration distribution is investigated analytically. The slow diffusion of polymer molecules retards mixing even at the lithofacies scale. We introduce a formula to estimate the redistribution of polymer due to capillary forces in a layered model, and this formula is validated through numerical simulations. From our considerations we conclude that it is questionable to assume a constant polymer concentration in lithofacies models. This impedes applying steady-state upscaling techniques. Such upscaling techniques will over-predict polymer adsorption. Different methods for upscaling adsorption are presented in this paper, and applied to a simplified layered model and to more realistic fine-scale numerical models based on the SPE10 model. These numerical models were populated with adsorption values obtained from published experiments conducted on samples from the Brent sequence modeled in SPE10. Simulations of tertiary polymer flooding on the upscaled models were compared to simulations of the same flooding sequences on the original fine scale models. The tested upscaling methods include a volume averaging technique employed by other authors, and a method were we distribute the adsorption values by the same functional relationship as in the fine scale model. In addition we introduce upscaling methods were we assign zero adsorption to fine scale grid cells with permeability below a given cut-off value. The cut-off value is obtained from a single phase simulation on the fine scale model. In our models the cut-off value methods yield the best match between the coarse scale and fine scale simulation results. The volume averaging technique over-predict the polymer adsorption. Results from both the lithofacies and geomodel scale indicate a tendency to over-predict polymer adsorption, which could lead to conservative estimates for the effect of polymer flooding.

Two extensive core flooding experiments along with supplementary tests were conducted to investigate the effect of bicarbonate as a potential determining ion for improved oil recovery from Danish North Sea reservoir chalk samples. Different sequences of brines were injected to see the impact on tertiary oil recovery. The core flooding experiments were conducted using two kinds of core plugs, homogeneous and heterogeneous (fractured). As injection of bicarbonate solutions leads to increase in pressure drop across the homogeneous core plug during injection, it was inferred that permeability reduction may be caused by fines production. The same flooding scenario was repeated for a fractured core plug. The difference in recovery from homogeneous and heterogeneous core plugs was observed: a significantly higher additional recovery was obtained for the heterogeneous core plug. This effect cannot be explained just by changing the chemical interactions between oil and rock surface. Adding bicarbonate to the injection brine changed the equilibrium and caused the sulfate ion in seawater to precipitate. Mixing injection brine with seawater from secondary injection caused the fines migration in the porous space, while high pH of bicarbonate solutions causes emulsification. In the accompanying crude oil/bicarbonate brine contact tests, formation of dynamically stable emulsions was observed. It was hypothesized that the fines migration and emulsification are causes for the microscopic flow diversion to the oil saturated regions and additional recovery from the heterogeneous rocks.

To examine the effect of pressure on pore structure and petrophysical properties of carbonate rock, the porosity, permeability, CT scanning, SEM and elastic wave velocity of two carbonate core plug samples from an oilfield in Southwest Iran were analyzed under cyclic pressure. One of the plugs was calcite and the other was dolomite with anhydrite nodules. The cyclic pressure exerted on the samples increased from 13.79 MPa to 27.58 MPa in six steps, and the variations in petrophysical properties of the two samples at different pressure loading and unloading steps were counted and analyzed. The results show that the calcite sample decreases in porosity and permeability with the increase of pressure, which is consistent with the results from compression and shear wave velocity tests. In the dolomite sample, the decreasing trend was not observed; fluctuations of compressive and shear velocities were observed during the loading stage, which may be due to different geometries of the pores and the porosity variation in the sample. Understanding the variation of carbonate petrophysical properties with pressure is helpful for optimizing reservoir development scheme. Key words: cyclic pressure loading, petrophysical property, carbonate reservoir, CT scan, rock physical property, structure deformation

Recent reports have demonstrated that gas injection can improve oil recovery of tight reservoirs after natural depletion, with major projects in progress worldwide. There is however a lack of understanding of the gas displacement behaviors at pore-scale especially under reservoir conditions. Herein we conducted an experimental investigation of CO2 and N2 flooding in the Lucaogou tight formation at 35.0 MPa and 80 °C. The flooding dynamics were continuously monitored by use of low-field nuclear magnetic resonance (NMR) to map the displacement processes at pore-scale and quantify the reduction of oil saturation in-situ. We observed that the overall oil recoveries of CO2 and N2 flooding were 38.4% and 35.1%, respectively. Due to the interactions between the oil phase and CO2, a uniform displacement along the core plug was yielded by CO2 flushing, indicated by the 1D spatial distribution of local oil saturation and 2D transverse images. Interestingly, during CO2 flooding, the major reduction of NMR T2 signals occurred in the large pores (4.2 ms

Accurate and routinely applicable methods to determine porosities and permeability coefficients are needed in order to ensure effective hydrocarbon recovery in shale and tight sandstone plays. In this study 129 gas uptake measurements (“GRI method”, “inflow” experiments) were performed on core plugs from three unconventional reservoir lithotypes (oil shales, gas shales and tight gas sandstones) under elevated effective stress conditions. The results were compared to those from “flow-through” tests (standard pulse decay) under similar experimental conditions, e.g. the same gas type and pore pressure range. The samples covered a porosity range from 1.3% to 12%. Equilibration times ranged from 102 s to 104 s and permeability coefficients from 10−18 to 10−21 m2. In order to successfully determine apparent gas permeability coefficients and porosities and to reliably interpret fluid dynamic effects from gas uptake data it is necessary to ensure a sufficiently high excess pressure drop during the uptake tests. This can be controlled by adjustment of the reservoir to pore volume ratio and initial differential pressure. Permeability coefficients derived from uptake tests on all six samples do not show any systematic deviations from those obtained from flow-through measurements. Best results were achieved for a core plug from the Lower Palaeozoic Alum Shale (Djupvik, Oland, Sweden), where Klinkenberg regressions of inflow and flow-through differ only by 4% (slope) and 10% (y-axis intercept). Here, the gas storage capacity ratio was ≈2.5 and excess pressure drops ranged from 0.1 to 1.2 MPa. Generally, measurement errors were lowest when excess pressure drops during uptake were at least 0.05 MPa for all samples. Excess pressure drops of less than 0.05 MPa resulted in coefficients of variance of single apparent gas permeabilities of ≈10%–100%, whereas excess pressure drops of >0.05 MPa resulted in coefficients of variance of ≈2%–15%. We show that it is possible to adjust the initial conditions of inflow measurements such, that Klinkenberg-corrected permeability coefficients and gas slippage factors can be readily determined. This will contribute significantly to a better understanding of the effects of anisotropy and/or the pore structure on the transport properties of unconventional lithotypes under elevated stress conditions. However, standard deviations of single apparent permeability coefficients derived from inflow experiments are higher by up to one order of magnitude than for those obtained from flow-through tests under all tested conditions.

Since the dynamic process of drilling operation often cannot be duplicated realistically in laboratory environment, the methodology to evaluate drilling induced formation damage using the core plug is still open to question. By using a multifunctional physical simulation system of drilling mud invasion, this paper introduces a novel experimental methodology which organically combines large-sized model flow experiment and NMR measurement to investigate drilling induced formation damage in sandstone reservoir. A large-sized sandstone formation module (55.9 cm in radial depth, and 10 cm in thickness) instead of the conventional core plug is proposed. This new type of experimental aliquot is able to provide enough space for observing a relative greater damage depth in a long-term drilling mud invasion. The effects of formation permeability and overbalance pressure on the damage are analysised. The patterns of permeability impairment and pore structure change caused by the fresh water-based mud invasion are summarized. The results show that the formation permeability plays a negative leading role in both the damage depth and the damage degree. The damage depth of the drilling mud in the sandstone reservoir with a lower permeability is greater than that with a higher value. The former formation damage degree is also more severe than the latter one. For the same sandstone reservoirs, a higher overbalance pressure results in a greater damage depth and a more severe damage degree at the same radial depth. The decrease ratio of movable water based on NMR T2 distribution is an excellent index for describing the relationship between macroscopic performance and microcosmic essence of the formation damage. An obvious positive correlation between the permeability damage rate and the decrease ratio of movable water is observed. With the variation of decrease ratio of movable water, the permeability damage rate changes faster in the sandstone reservoir with a lower permeability. The results obtained in this paper provide some helpful insights for enlightening new laboratory evaluation methodologies, improving numerical simulation of drilling induced formation damage and researching formation damage caused by any other working fluids, such as completion, workover, and stimulation fluids.

Summary The stress-dependent permeabilities of split shale core plugs from Eagle Ford, Bakken, and Barnett Formation samples are investigated in the presence of microproppants. An analytical permeability model is developed for the investigation, including the interactions between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure-pulse-decay measurements of the propped shale samples in the laboratory. The analysis provides the propped-fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant-placement quality can be used as a measure of success of the delivery of proppants into microfractures and to design stimulation experiments in the laboratory.

In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.

Low-field Nuclear Magnetic Resonance (NMR) is a non-invasive method widely used in the petroleum industry for the evaluation of reservoirs. Pore structure and fluid properties can be evaluated from transverse relaxation (T2) distributions, obtained by inverting the raw NMR signal measured at subsurface conditions or in the laboratory. This paper aims to cast some light into the best practices for the T2 data acquisition and inversion in shales, with a focus on the suitability of different inversion methods. For this purpose, the sensitivity to various signal acquisition parameters was evaluated from T2 experiments using a real shale core plug. Then, four of the most common inversion methods were tested on synthetic T2 decays, simulating components often associated with shales, and their performance was evaluated. These inversion algorithms were finally applied to real T2 data from laboratory NMR measurements in brine-saturated shale samples. Methods using a unique regularization parameter were found to produce solutions with a good balance between the level of misfit and bias, but could not resolve adjacent fast T2 components. In contrast, methods applying variable regularization – based on the noise level of the data – returned T2 distributions with better accuracy at short times, in exchange of larger bias in the overall solution. When it comes to reproducing individual T2 components characteristic of shales, the Butler-Reeds-Dawson (BRD) algorithm was found to have the best performance. In addition, our findings suggest that threshold T 2 cut-offs may be derived analytically, upon visual inspection of the T 2 distributions obtained by two different NMR inversion methods.

Heterogeneities within core samples affect the accuracy of the laboratory measured core plug interconnected porosity. The laboratory measures the volume averaged porosity of the interconnected pores, . For homogeneous cores this is the correct porosity ± any experimental error. However for heterogeneous cores when any embedded material (unknown or ignored) has a differing porosity, ϕi, to that of the containing outer shell, ϕo, there will be increased uncertainty. We show that the difference between the measured volume averaged porosity, , and the porosity of the outer shell of the core, ϕo can be quantified by our Heterogeneity Factor, H. H is defined as ( - ϕo)/ϕo and given by H = F(R-1), where F is the ratio of the bulk volume of the embedded material to the total core bulk volume (measured), VBi/VBm, and R is the ratio of the embedded and the host outer porosity, ϕi/ϕo. The core plug homogeneous model can create increased error bounds in porosity for heterogeneous plugs. When H is zero there is no error in the porosity measurement due to heterogeneity, but when H≠ 0 then the differences can be significant and increases the experimental error bound. We present graphs for relevant industry scenarios to demonstrate the effect of any inclusions in the measured porosity. We find that when F is ∼0.1 i.e., inner included porosity is 10% of bulk volume, the relative error between and ϕo can reach ∼30% and even larger differences when F > 0.1. We then give a real example from a faulted vuggy outcrop carbonate which demonstrates extra porosity uncertainties, even for a very small vug. Finally we discuss the possible effect of embedded clay intrusions emitting adsorbed gas on grain/pore volume determinations of porosity using gas expansion, a common laboratory method of porosity determination. Appreciation of core heterogeneity on the precision of the laboratory porosity measurements is essential to improve the confidence in the error bounds for the quality control of laboratory core porosity measurements, and of the porosity distribution frequency for inputs to statistical methods such as Monte Carlo analysis for oil-in-place estimations, STOIIP.

Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.

This paper presents a multi-scale modeling of gas transport in shale where techniques from micro- to macro-scale (Molecular dynamic simulations, lattice Boltzmann and multi-continuum) are integrated to achieve more accurate and robust simulation and prediction results. The formulation is then applied to pulse decay experiment to obtain shale core plug transport and storage parameters such as inorganic permeability and organic porosity and effective diffusion coefficient. The formulations governing gas transport and storage in dual porosity, single permeability shale model is validated in wide range of Knudsen number and flow regimes. In this new approach, shale organic matter is modeled using four different 3D molecular structure of type II Kerogen A, B, C, and D and a type III Kerogen A, with different Kerogen porosities and densities. The Equilibrium Molecular dynamics (EMD) simulations and Grand Canonical Monte Carlo (GCMC) are used to obtain the gas transport and adsorption parameters in different Kerogen structures, respectively. Meso-scale Lattice Boltzmann simulation is used to obtain gas transport parameters in inorganic matter of shale samples and the regularized 13-moment method is used for both inorganic matrix and natural fractures transport parameters and compared with LBM simulations. Next, the multi-continuum approach is used to integrate and describe gas transport and storage in multi-scale shale samples. The multi-continuum model developed is then used to history-match and predict Marcellus shale sample transport and storage parameters using pulse decay technique. The average parameters obtained from experiments and GCMC and EMD simulations will be used as external knowledge in our simulation based history-matching algorithm of pulse decay experiment to obtain shale organic and inorganic transport and storage parameters. Shale matrix permeability will be corrected for gas slippage using LBM and R13 AP results. The new formulation is compared with the previously published models simulating the gas dynamics in shale reservoirs. In this study, we show that gas transport and storage in micro-scale organic pores of shale matrix are nontrivial and significantly impact cumulative gas recovery from these unconventional reservoirs. Our unique integrated multiscale study (i.e., micro-scale molecular dynamics, meso-scale lattice Boltzmann simulation and multi-continuum macro-scale approach) showed the importance of developing external knowledge on different scales to obtain realistic parameter domains for gas transport and storage in shale reservoirs. This study is an important step for development of integrated multi-scale shale gas reservoir flow simulators and it has a practical importance on shale reservoir characterization specially quantifying the shale transport parameters using pulse decay technique.

Unconventional reservoirs such as shales (mudrocks) and coals may exhibit an ultra-low matrix permeability ( Rate-transient analysis (RTA) is a technique used to quantitatively analyze production data from wells drilled into unconventional reservoirs to extract reservoir (e.g. permeability, hydrocarbons-in-place) and hydraulic fracture (conductivity, fracture length) properties. Multi-fractured horizontal wells (MFHWs) producing from low-permeability reservoirs commonly exhibit the flow-regime sequence of transient linear flow, where hydrocarbons flow through the reservoir orthogonal to hydraulic fractures or the horizontal well, followed by boundary-dominated flow caused by pressure interference between adjacent hydraulic fractures or wells. Transient linear flow may be analyzed using RTA methods to extract fracture or well-length (if permeability is known); the end of linear flow can be used to estimate permeability of the reservoir, and boundary-dominated flow to estimate hydrocarbons-in-place. In this work, a new experimental procedure and set-up, applied to core plugs under stress conditions, is developed to mimic well operating conditions encountered in the field (i.e. producing from a subsurface unconventional reservoir). After injection of methane gas into one end of the core plug, and pressure stabilization, the gas is flowed out of the same end of the core plug at constant pressure (with the aid of a backpressure regulator), and flow rates are measured with a flow meter. This procedure is applied to a core plug extracted from a low-permeability siltstone of the Montney Formation (western Canada). Repeated testing consistently demonstrated a transient linear flow period, as the gas pressure transient propagated along the core plug, followed by boundary-dominated flow after the pressure transient reached the end of the core plug; this sequence is identical to what is commonly observed in the field. Permeability was estimated using both the slope of a square-root of time plot (a common RTA method used to analyze transient linear flow), and the time at the end of linear flow combined with the linear flow distance of investigation (DOI) equation. Permeability from both techniques is in good agreement (±5% for both experiments performed), providing an important redundancy to the analysis procedure. Pore volume (and hence porosity, with bulk volume known) may be estimated from the time at the end of linear flow and the slope of the square-root of time plot – the calculated value is in excellent agreement (±2% for both experiments performed) with that obtained from pore volume/porosity estimates using a helium pycnometer (combined with calipered dimensions). Finally, test times for the ∼0.0007 md core plug sample, after the initiation of the production phase, are on the order of only a few minutes to obtain the two independent estimates of permeability and pore volume, which is faster than that achievable from a PDP test. The new innovative experimental procedure is successful in reproducing the physics of flow in unconventional reservoirs, with the results being analyzable with the same techniques applied to field data.

Carbon capture and storage (CCS) technologies can help manage current emission levels of greenhouse gases while enhancing energy security and diversifying energy economy. For a successful and effective CO2 geological storage, a comprehensive understanding of the multiphase flow properties of the CO2/water system in permeable rocks is crucial because they control the engineering design and management of industrial CO2 storage projects. In this study, we conducted multiphase flow tests at a core-scale to understand the migration behaviors of CO2 and water in a stratified geologic media (sandstone interbedded with silt). A core-flooding apparatus combined with an X-ray scanning system provided high-resolution experimental dataset of continuous data on the differential pressure ( Δ P ) across a core plug and CO2 saturation maps over time. During the multiphase flow tests, we captured dynamic fluctuation in Δ P as CO2 front advanced by displacing water through different geologic media. The spatio-temporal evolution of CO2 saturation in each geologic media revealed two increasing stages, implying that the capillary pressure of the downstream geologic media affects the upstream CO2 saturation. In addition, multiphase transport simulations were conducted to assess the sensitivity of model parameters. Permeability and porosity were respectively sensitive to pressure and CO2 saturation. Overall, the parameters of the silt layer were more sensitive to the pressure and CO2 saturation build-up compared to those of the sand layer. Additionally, history matching was conducted to validate the model by sequentially matching Δ P and CO2 saturation within the stratified system. Finally, we extended the core-scale modeling work further to field-scale and investigated the impact of boundary conditions and heterogeneity on both pressure and CO2 saturation distribution.

Fluid storage and transport in shale and clay formations is important in many areas of application, including hydrocarbon recovery from, and waste fluid storing in, these reservoirs. The multiscale heterogeneous nature of shales is largely responsible for these rocks being considered unconventional and complicated. Researchers often rely on imaging methods to provide spatial information to characterize their heterogeneity. SEM and nano-CT are powerful methods that have been used to give images of shale nanopores with fields of view (FOV) of 100 μ m . However, this limited FOV has raised questions about the validity of simulations based on these methods to scale up and represent macroscopic shale properties. Here, we have used, for the first time, SPRITE Magnetic Resonance Imaging (MRI) methods to give core plug size shale images. The imaging method resolves water and oil signals to give separate images of each in shales. “As received” shale samples were used to acquire 1D and 3D oil and water images to characterize natural fluid distribution. Water uptake experiments were conducted to probe fluid displacement in shales. Measurements included gravimetric, Magnetic Resonance (MR) T 1 - T 2 ∗ relaxation correlation, and SPRITE imaging methods. Water and oil images showed that sample scale heterogeneities are imposed by the shale beddings. Water uptake experiments (1) showed the capability of the T 1 - T 2 ∗ method to identify MR signals from shale fracture water and matrix pore water, and (2) illustrated wettability control of spatial water distribution in shales during spontaneous imbibition.

Summary Excess permeability in carbonate reservoirs is often associated with the presence of karst features such as vugs, and caves. Understanding the processes controlling the formation of these non-matrix features is critical for predicting their distributions and provides context for assigning them petrophysical properties. In this study, we investigate the factors controlling the formation of vuggy and cavernous porosity in San Salvador Island Bahamas. We use field observations, airborne LiDAR, cores, image logs, temperature profiles, and core plug data to characterize non-matrix pore types. Our analysis results in new concepts for vug and cave formation linked to the position of aquifers which are ephemerally perched on low permeability exposure surfaces.

To ensure storage security, it is vital we understand, and can effectively model, the physical and chemical trapping mechanisms for CO2 storage. A key trapping mechanism underpinning storage security and immobilising a significant proportion of the CO2 plume is capillary trapping. Capillary trapping is considered to be responsible for 90% of the storage capacity in saline aquifers in the US, the largest potential CO2 storage resource. The ability to model and predict capillary trapping over large spatial scales in complex geological systems is essential to minimise risks and evaluate capacity. This paper investigates the effect of natural rock heterogeneities on capillary trapping across spatial scales in the Captain D Sandstone, from the Goldeneye formation, North Sea. That is, how heterogeneities affect CO2 saturation and distribution within rock core samples, and how those effects manifest, as a pseudo residual trapping, when upscaled to the field. A comprehensive dataset of 48 core plugs over a 65m interval have been studied. The location has industrial application as a target injection site for the discontinued Peterhead CCS project, with the aim to store 10 Mt CO2 over 10 years. These results are also applicable to other storage sites of similar geology. We have carried out steady-state core flooding experiments using medical x-ray CT, providing a detailed characterisation of continuum multiphase flow properties, including residual trapping characteristics, over cm scales. The results show that individual core plugs exhibit a large range in apparent residual trapping at the centimetre scale which averages out over scales of 10s of cm’s or greater. The average Land trapping value at the deca-centimetre scale is 1.7, however, at the cm scale, it varies between 0.8 and 2.8, representing a very large variation in locally trapped CO2. Consequently, at the plug scale for large initial saturations, approaching 1, the apparent residual saturation may vary between 0.2 and 0.5, given the variations in Land trapping parameter. At lower initial saturations, the variations are not as great in absolute terms, but the relative variation is just as large. Continuum numerical models are constructed from observations of residual trapping in heterogeneous rock cores using characterisation methods developed by Jackson et al. (2018, 2020). The trapping stage of a CO2 injection and migration project is simulated over a 65m region, while retaining the impact of heterogeneities at the cm-scale. Results from these models indicate that great care should be taken when upscaling the Land trapping parameter for use in field simulations, to estimate the long-term trapping of CO2 by capillary heterogeneities. Through quantifying the proportion of trapping resulting from capillary heterogeneities, the implications of modelling the system with the average and maximum experimental Land trapping parameter are evaluated. Modelling the system with the maximum experimental core plug Land trapping parameter results in the proportion of trapping caused by capillary heterogeneities to approximately double compared to that obtained using the average experimental core plug Land trapping parameter.

We review scale dependence of hydraulic conductivities and effective porosities for prediction of contaminant transport in four UK karst aquifers. Approaches for obtaining hydraulic parameters include core plug, slug, pumping and pulse tests, calibration of groundwater flow models and spring recession curves. Core plug and slug tests are unsuitable because they do not characterize a large enough volume to include a representative fracture network. Pumping test values match regional-scale hydraulic conductivities from flow modelling for the less intensively karstified aquifers: Magnesian Limestone, Jurassic Limestone and Cretaceous Chalks. Reliable bulk hydraulic conductivities were not available for the intensively karstified Carboniferous Limestone due to dominance of flow through pipe conduits in Mendips. Here, the only hydraulic conductivity value found from spring recession is one order of magnitude higher than that indicated by pumping tests. For all four carbonate aquifers, effective porosities assumed for transport modelling are two orders of magnitude higher than those found from tracer and hydrogeophysical tests. Thus, a combination of low hydraulic conductivities and assumed flowing porosities resulted in underestimated flow velocities. The UK karst aquifers are characterized by a range of hydraulic behaviours that fit those of karst aquifers worldwide. Indeed, underestimation of flow velocity due to inappropriate parameter selection is common to intensively karstified aquifers of southern France, north-western Germany and Italy. Similar issues arise for the Canadian Silurian carbonates where the use of high effective porosities (e.g. 5%) in transport models leads to underestimation of groundwater velocities. We recommend values in the range of 0.01–1% for such aquifers.

In this work, we have investigated the wettability of Bazhenov Formation rock samples using a nuclear magnetic resonance (NMR), the methods of vapor adsorption, and wetting contact angle. We have conducted the petrographic description of rocks using ultra-thin sections and scanning electron microscopy (SEM). In addition, we used data on the organic content (TOC) obtained by the Rock-Eval method and the results of lithological typing on thin sections for detailed analysis of NMR and contact angle methods results. Thus, for target rock, the groups with a similar rock wettability were highlighted by the lithological description of thin sections. The calculation of the wetting angle provided an initial assessment of the surface wettability of the rock and made it possible to establish the relationship between the wetting angle and the TOC, which is relevant for rocks of the Abalak-Bazhenov group. The NMR method described the core plug wettability proved to be less sensitive to the rock lithotype and organic matter (OM) texture in the rock and, therefore, used for the integral characterization of core plugs. Correlations of calculated wetting angle and adsorption wettability index vs. TOC and OM texture illustrated the dependence of rock wettability behavior on both the lithological specifics and the OM properties.

Despite the several kinds of literature on the dispersion behaviour of supercritical CO2 in CH4 at conditions relevant to enhanced gas recovery (EGR), studies have so far limited in keeping this parameter as low as possible. This study aims to highlight, experimentally, to determine the effect of N2 as cushion gas on the dispersion coefficient in consolidated sandstones core plug under reservoir conditions applicable to EGR. A laboratory core flooding experiment was carried out to simulate a detailed process of an unsteady state methane displacement in Bandera gray and Bentheimer core plugs at reservoir conditions of 40oC temperature, 1500 psig of pressure, the optimum injection rate of 0.4ml/min, and at varying N2 cushion volumes (8-36 cm3). Further experimental runs were carried out to investigate the effect of high CO2 injection rates (0.6-1.2 ml/min) on the longitudinal coefficient of dispersion as it plumes transverses into the core plugs during the EGR process. The coefficient of longitudinal dispersion declines with raises in cushion gas volume, hence the higher the amount of N2 cushion volume the less the dispersion of CO2 into CH4. This is due to the high shielding barrier inhibited by nitrogen, making it difficult for the CO2 to dispersed itself and mixed with the nascent natural gas resulting in delayed breakthrough as it plumes transverses into the CH4 during the displacement process. The inclusion of N2 as cushion gas prior to CO2 injection recorded the highest decline at 36cm3 cushion volume, presenting a 48 and 28% reduction in longitudinal dispersion coefficient for Bandera and Bentheimer core samples respectively, compared to that of conventional/traditional CO2 injection (with zero cushion volume). Recording lower nascent CO2-CH4 mixing resulting in less natural gas contamination and more storage volumes. Also, a reverse phenomenon was observed when the CO2 injection rate was increased from 0.6-1.2 ml/min due to the high diffusion rate of CO2 at higher interstitial velocities, resulting in a rapid increase in dispersion coeffient and indirectly high widespread contamination of the remaining natural gas.

Although the application of microfluidics is not new in the petroleum industry, the upscaling of fluid flow behavior from micromodels to reservoir rocks is still challenging. In this work, an attempt to close the gaps between micromodels and reservoir rocks was performed by constructing micromodels based on the X-ray micro-computed tomography (μCT) images of a Bentheimer core plug. The goal of this work was to build a digital 3D model of reservoir rocks and transfer its rock properties and morphological features such as porosity, permeability, pore and grain size distribution into a 2D microfluidics chip. The workflow consists of several steps which are (1) rock property extraction from aμCT image stack of the core plug, (2) micromodel pore structure design, (3) lithographic mask construction and (4) fabrication. Flooding experiments, including single- and two-phase flow experiments, were performed to confirm the micromodel design. As a result, the real structure micromodels show similar rock properties, as well as a comparable fluid flow behavior, to those of the Bentheimer core plug during typical water flooding and EOR polymer application. This framework demonstrates the potential for the general applicability of micromodels to support EOR studies on a larger scale, such as those on sandpacks or core plugs before field implementation.

Shale matrix permeability is one of the most important parameters for characterizing a source rock reservoir and for predicting hydrocarbon production. The low permeability value and the presence of induced fractures during core retrieval and transportation make the accurate measurement of the true permeability values for source rocks a significant challenge for the industry. The steady state flow method and the transient pressure pulse decay method on core plug samples mainly measure the permeability of fractures when fractures are present. While the Gas Research Institute (GRI) method that uses pressure decay on crushed rock samples was designed to overcome this difficulty associated with the induced fractures, its measurement results are reported to be sensitive to the particle size of crushed rock samples and also need correction of Knudsen diffusion effect. Moreover, the GRI method is limited to the unconfined stress condition. This work develops a practical method to measure the matrix permeability values from fractured source rock samples by extending the commonly used pressure pulse decay method. A source rock sample with fractures can be more accurately described by a dual-continuum system consisting of a fracture continuum and a matrix continuum. During the pulse decay test, the initial flow across the source rock sample is dominated by the fracture continuum because it has much higher permeability values than those for the rock matrix. Thus, the initial gas pressure signals from the test are used to estimate the fracture permeability. During the late-stage of a pulse decay test, the flow process within the rock sample is controlled by the rock matrix. The observed pressure signals at this stage are used for estimating matrix permeability. The method is based on the analytical solution to gas flow in the fractured rock sample and relatively simple to apply in practice. Both fracture and matrix permeability's dependence on the effective stress can be assessed with this method.

Aiming at the stress sensitivity problem of tight reservoirs with different microfractures, the cores of H oilfield and J oilfield with different microfractures were obtained through the fractures experiment, so as to study the change of gas permeability in tight sandstone core plug during the change of confining pressure. Besides, we use the nuclear magnetic resonance (NMR) spectra of the core before and after saturation to verify whether the core has been successfully fractured. Based on Terzaghi’s effective stress principle, the permeability damage rate (D) and the stress sensitivity coefficient (Ss) are used to evaluate the stress sensitivity of the core, which show consistency in evaluating the stress sensitivity. At the same time, we have studied the petrological characteristics of tight sandstone in detail using thin section (TS) and scanning electron microscope (SEM). The results show that the existence of microfractures is the main factor for the high stress sensitivity of tight sandstone. In addition, because of the small throat of the tight reservoir core, the throat closes when the overlying stress increases. As a result, the tight sandstone pore size is greatly reduced and the permeability is gradually reduced. Therefore, in the development of tight reservoirs, we should not only consider the complex fracture network produced by fracturing, but also pay attention to the permanent damage of reservoirs caused by stress sensitivity.

We describe a study focused on the absolute permeability of reservoir carbonate rocks from the Middle East and involving comparison of experimental data and numerical estimates obtained by combining digital-rock and Lattice-Boltzmann Methods (LBM). The question of the “representativeness” of the site at which the simulation is performed is addressed as follows. First, a low-resolution, CT X-ray scan of the core plug is performed to identify regions of large porosity (millimeter-sized vugs, etc.). These regions are then avoided to postselect smaller sites (site volume ~ 1 mm3) which are to be scanned at higher resolutions (voxel size R-measure) is used to eliminate those sites for whichR > b, wherebis an upper bound (typically,b = 1). Essentially, the measure estimates how well the postselected sites capture the experimental porosity and the dominant pore-throat size of the core plug. This leads to a small set of sites for which the simulations are both computationally manageable and yield a reasonable estimate of the permeability: the experimental and predicted values differ by a factor of about 3 on average, which is a particularly significant result given the challenging heterogeneous pore space of carbonate samples. We believe the suggested methodology to be an adequate and practical way to circumvent upscaling.

This study aims to investigate the controls on reservoir heterogeneity and quality of Miocene Bhuban Formation of the Neogene Surma Group at the Srikail Gas Field, Bengal Basin, Bangladesh. The study integrates wireline log data from two wells with core description as well as petrophysical and petrographic data obtained from 24 core plug samples retrieved from three gas bearing zones. The three zones, namely (from shallower to deeper): D-upper, D-lower, and E-sands, were identified from wireline log interpretation. Based on the extracted cores, the sandstones are classified into three main facies association: 1) coarse grained facies association (CFA) composed of sandstone with parallel lamination, trough, and planar cross bedding; 2) medium grained facies association (MFA) comprises of wavy and flaser bedded sandstone; and 3) fine grained facies association (FFA) consisting of siltstone and shaly sandstone. CFA sandstones, mostly abundant in D-lower and E-sands, were deposited in a high energy distributary channel environment with strong tidal influence while the finer-grained sandstones, mainly present in D-upper sand, were deposited in a low energy distributary channel. The results obtained by integrating core plugs and wireline logs show that best reservoir quality rocks are associated with CFA sandstones which are characterized by GR below 105 API, 15-25% porosity, 30-100 mD permeability. In contrast, FFA sandstones have lower porosity ( 125 API). The high energy and strong tidal influence on sandstones of CFA resulted in coarser grain size (and thus larger pores), better sorting and less clay content than the finer-grained, high clay bearing, low energy sediments of FFA. Additionally, petrographic and core plug analyses revealed that mechanical compaction is an important factor that reduces the porosity and permeability with increasing proportions of ductile mineral grains. Other less important diagenetic factors include quartz overgrowth and cement. The findings of this study show that the reservoir quality of the studied field is principally controlled by both depositional environment and mechanical compaction.

Optimal injection conditions are important for carbonate acidizing design. Both experimental and theoretical work have been carried out for studying optimal injection rates, but rarely the optimal wormhole propagation velocities. In this study, we developed a mathematical model that can describe wormhole propagation at optimal conditions. This model incorporates rock pore size distribution and acid-rock reaction characteristics, which essentially includes every factor that affects optimal conditions. Before developing our model, we studied the static pressure and flow field when a wormhole propagates to a certain length in a core plug through numerical simulations. Also, we carried out lab acidizing coreflood experiments to explore wormhole propagation behavior. The results show that when a wormhole reaches a certain length, the wormhole propagation velocity keeps the same. This is because a stable fluid loss profile is established after this length. Based on this finding, we focus on the wormhole tip. By incorporating an optimal tip flux model to a mechanistic model of wormhole growth, our new propagation model presents more fundamental mechanisms. Our model shows that the wormhole propagation velocity depends on the rock pore size distribution and the overall reaction rate coefficient at optimal conditions. Particularly, if the reaction is fully diffusion-limited, it depends on the rock pore size distribution and the diffusion coefficient. These are verified by acidizing coreflood experiments at different acid concentrations and temperatures. The findings of this study illustrate the importance of the overall reaction rate and diffusion rate. This model can be incorporated into an acidizing simulator for engineering design.