Low Water Saturation Research Articles

Prediction of Cretaceous reservoir zone through petrophysical modeling: Insights from Kadanwari gas field, Middle Indus Basin

This study involved an interpretation of wire-line logs in assessing the hydrocarbon capacity of the sandstone reservoir within the gas fields of Kadanwari, Sindh, Pakistan. Wire-line logs from four wells (KD-01, KD-03, KD-10 and KD-11) were used in our research and provided interpretation for thirteen reservoir zones. Reservoir analyses were done for effective porosity (ϕeff), shale content (Vsh), net pay thickness variations, water saturation, and hydrocarbon (Sw and Shc). Hydrocarbon-bearing zones consist of high values of resistivity, permeability, porosity, low water saturation content, and less shale content, indicating the presence of clean sand. The Thomas Stieber model findings show that in lower Goru sand, the laminated form of shale distribution persists. Sub-reservoirs’ petrophysical parameters were analyzed and ranked into a good sand reservoir quality (having ϕeff ∼0.11-0.44%), permeability (∼10.539-477.76 mD), hydrocarbon saturation (having Shc ∼0.59-0.86%), and water saturation (having Sw ∼0.18-0.45%). In the current research Indonesian model has been used to test for water saturation over a shaly-sand reservoir situated in a heterogeneous zone. It was observed that each well exhibited Sw at values lesser than 60%. This is indicative the selected zone has a hydrocarbon potential, and the hydrocarbons are of good quality. Isoparametric maps and crossplots of litho-saturation results reveal variations in the horizontal and vertical petrophysical parameters of the reservoir. The subsurface reservoir geographical distribution is visualized employing isoparametric maps. The fuel treasure in the southwestern section of the study area is enormous, as revealed by the petrophysical investigations, suggesting more well-drilling prospects in the gas fields of the lower Goru Formation situated in Kadanwari. Our research identified a quality hydrocarbon hotspot zone of immense economic value in Southern Kadanwari. In contrast, more research is needed regarding the northeastern section though our present findings suggest the northeastern section should be avoided because of excess shale and high-water concentrations.

Integrated AVO inversion and seismic attributes for tracing hydrocarbon accumulation in Kafr El-Sheikh Formation, South Batra field, Nile Delta, Egypt: A case study

Utilizing advanced seismic techniques for delineating hydrocarbon accumulations in HST (High Stand System Tract) turbidite channel of Kafr El-Sheikh (KS) formation (Pliocene Age) located in the western part of South Batra field (SBF), Nile Delta – Egypt is investigated. 3D seismic data and four well logs helped in studying the properties of the channel. Three wells encountered the central part of the channel and showed thicker reservoir thickness than the fourth well, which encountered the levee. The channel is characterized by high porosity (25–30%) and relatively low water saturation (27–50%). The structural map showed that the channel is dipping towards the NE–SW. AVO analysis, scaled Poisson's ratio, post-stack seismic inversion, and seismic attributes confirmed the presence of Class III gas sand. Variance attribute helped in imaging the channel and faults. Maps generated from spectral decomposition showed that the dominant frequency is around 15 hertz. Results of integrating different techniques were consistent and successfully helped in determining the geometry of the channel, discriminating between different lithologies and fluids, in addition to delineating the sweet spots and recommended locations for drilling.

Coreflood-on-a-Chip Investigation of Oil Bank Formation in Low Interfacial Tension Chemical Floods at Favorable and Unfavorable Viscosity Ratios

Summary An efficient tertiary chemical flood involves the chemicals displacing the oil in a stable manner, so the initially disconnected trapped oil ganglia coalesce into a bank as the flood progresses. However, the location of surfactants and polymers in the core during a chemical flood is difficult or impossible to determine at very fine time and space resolutions. In this work, we bridge this gap by visualizing saturation profiles in a coreflood-on-a-chip, a micromodel that is the same length as a core, and monitoring fluorescent aqueous injectant as displacements occur. We visualize, for the first time, surfactants in and around oil banks at the pore and Darcy scales during low-tension displacements. We present 12 chemical floods in the coreflood-on-a-chip, imaged at the centimeter scale, including six surfactant and six alkali-surfactant-polymer (ASP) floods at low, intermediate, and high initial water saturations. Additionally, we present a micron-scale visualization of an ASP flood under UV light to observe the distribution of surfactant around an oil bank at the pore scale. We found that oil banks formed even during very unfavorable displacements, when surfactant solution (1 cp) displaced oil (80 cp) in a micromodel at intermediate and residual oil saturations. Although our results show saturation profiles are mostly well described by fractional flow theory, the distribution of injected aqueous phase is not. Significant aqueous injectant, including surfactant, flows within and ahead of oil banks.

Bitumen Recovery Performance of SAGD and Butane- and Hexane-Aided SAGD in the Presence of Shale Barriers.

Oil and gas formations are commonly found to be heterogeneous, and one of the most common occurrences of reservoir heterogeneity is the presence of shale barriers. Shale barriers typically have very low permeability and high initial water saturation. Due to low permeability, these barriers obstruct the oil drainage path, specifically in thermal recovery methods such as steam-assisted gravity drainage (SAGD). In addition to flow assistance, they also lead to heat losses due to absorption by the high initial water saturation. Expanding solvent steam-assisted gravity drainage (ES-SAGD) is a hybrid technique comprising solvent co-injection along with steam. Solvent being in the vapor phase can potentially overcome the restricted path due to the presence of shale barriers. This paper presents a numerical simulation study on comparison between SAGD and ES-SAGD in the presence of shale barriers. SAGD and ES-SAGD with hexane and butane are numerically simulated for 240 lognormally generated shale realizations. First, both recovery processes are analyzed over the whole simulation period. Additionally, they have also been evaluated at multiple cumulative steam oil ratio cut-offs at 2, 2.5, 3, and 3.5. Transition points are defined and explained to cluster the shale density/fractions based on similar behaviors. It was shown that the oil that cannot be mobilized and produced by SAGD because shale barriers can be reached by the vaporized solvent through tortuous paths and recovered. Also, thermal losses are reduced because of lower steam chamber temperature. This led to efficient results for ES-SAGD over SAGD in heterogeneous formations.

Analytical Solution for Predicting Salt Precipitation During CO2 Injection Into Saline Aquifers in Presence of Capillary Pressure

AbstractSalt precipitation within pores of the reservoir is an important phenomenon occurring during CO2 injection into saline aquifers. The phenomenon results in permeability reduction and injectivity impairment. Salt precipitation mainly happens because of water vaporization inside the CO2‐saturated (dry‐out) region. For water‐wet systems, the capillary pressure acts toward the lower water saturation regions in the reservoir, thereby displacing a film of brine backward to the dry‐out region. This results in more precipitation. Overlooking this phenomenon, referred to as capillary‐driven backflow, results in over‐estimations of injectivity in the dried region. Here, we have developed an analytical solution based on fractional flow theory and shock waves for CO2‐brine systems considering the effect of capillary pressure. The validity of the solution is verified by comparing the outputs of our model with those of numerical results from a commercial numerical simulator for a hypothetical reservoir. An equation is derived to calculate the distance at which capillary pressure is most influential, and also the injectivity impairment at injection well due to salt precipitation was reasonably accurately estimated. The results emphasize that effects of capillary pressure should not be ignored.

Estimation of reservoir properties based on core plugs, lithofacies, and well logs for Nahr Umr Formation in Noor oilfield, southern Iraq

The Nahr Umr Formation, one of the most important Cretaceous formations and one of the main generating reservoirs in southern Iraq and neighboring regions, was chosen to study and estimate its petrophysical properties using core plugs, lithofacies, and well logs from five wells in the Noor oilfield. Reservoir properties and facies analyses are used to divide the Nahr Umr formation into two-member (limestone in the upper part and main sandstone in the lower). Limestone members are characterized by low reservoir properties related to low effective porosity and permeability while the main sandstone member is considered as a reservoir. Four lithofacies were recognized in the main sandstone member of the Nahr Umr Formation according to petrographic observation with gamma-ray. They are well-sorted quartz arenite sandstone, poorly sorted Quartz arenite sandstone, Sandy shale, and Shale Lithofacies.
 Calculation of the various reservoir properties (shale volume, effective porosity, permeability, and water saturation) using the (Interactive Petrophysics v3.5) program and linking them with the lithofacies by computer processed interpretation (CPI) of available of the available wells. Divided the sandstone member into three units are A, B, and C. Each unit consists of many reservoir sandstone subunits separated by shale and streaks of limestone. Average reservoir properties of units A and B are good to very good related to high porosity, permeability, and economy hydrocarbon saturation (low water saturation). While these properties are decreased in unit C. The Sandston member of borehole No-5 was the best reservoir characterization, especially in the thickness of the reservoir units and the low shale content.

Microscopic Seepage Mechanism of Gas and Water in Ultra-Deep Fractured Sandstone Gas Reservoirs of Low Porosity: A Case Study of Keshen Gas Field in Kuqa Depression of Tarim Basin, China

To study the microscopic seepage mechanism of gas and water in fractured sandstone gas reservoirs of low porosity, this kind of reservoir in the Keshen gas field, Kuqa depression of Tarim basin in China, was taken as an example. Based on rock samples and microscopic visualization technology, nuclear magnetic resonance experiments of saturated water–gas drive and CT scanning experiments of saturated gas–water drive were conducted. The seepage mechanism of water invasion during the gas development were simulated. Subsequently, the distribution of irreducible water saturation and the influence factors on the efficiency of drive were analyzed. The results show that the distribution of gas and water is mainly related to structures of matrix pores, fracture development pattern, and density. The main factors resulting into good reservoirs include large matrix pores and high angle fractures, low irreducible water saturation, and high separation between gas and water. The efficiency of water drive is positively correlated with fracture porosity and dip angle. High angle fractures can effectively improve the seepage capability and then increase the efficiency of water drive. Besides, the great proportion of large pore size in matrix, high fracture dip, porosity, and density can also improve the efficiency of water drive. Therefore, for the development of fractured sandstone gas reservoirs of low porosity, the study of matrix pores and fractures is quite important since it can provide guidance for the efficient deployment of wells. The increase of fracture density is significant by large-scale sand fracturing in order to improve the efficiency of water drive. It is necessary to strictly control the gas production rate of the gas reservoir and delay the water invasion rate as far as possible. In case of serious waterlogging, shut-in all wells in gas reservoirs is a choice to strengthen the gas–water imbibition between fractures and matrix, which can improve the recovery of the gas reservoir.

Determination of Petrophysical Parameters using Well Logs for Mishrif Formation in F Oil Field Southern Iraq

This research aims to identify and analyze the Mishrif Formation's reservoir units and subunits in the F oilfield, located north of the Nasiriya using mostly well-logging data and other accessible geological data. The Petrophysical and lithological parameters of each unit of the Mishrif Formation are determined using data from the F-X1, F-X2, and F-X3 wells to evaluate the water saturation for each unit. GEOLOG8 software was used to interpret output data. High reservoir potential is found in units M1.2, L1.1, L1.2 and L2 due to the high effective porosity and low water saturation. The reservoir units are separated by cap units including marl key beds and units M1.1, M2.

Numerical Simulation of Hydrate Decomposition during the Drilling Process of the Hydrate Reservoir in the Northern South China Sea

The process of drilling in natural gas hydrate reservoirs in sea areas involves problems such as hydrate decomposition and wellbore instability. To study the response behaviors of a reservoir during the drilling process, a two-dimensional numerical model of drilling fluid invading a hydrate reservoir in a cylindrical coordinate system was established to simulate the processes of heat and mass transfer, gas–liquid two-phase flow, and hydrate formation and decomposition in the hydrate reservoir during the drilling process. Based on the hydrate reservoir at station W17, Shenhu area of the South China Sea, the physical property response of the hydrate reservoir under different drilling fluid temperatures and salinity values was studied. The simulation results showed that during the drilling process, the temperature and pressure of the reservoir respond rapidly in a large area, further promoting the hydrate decomposition in the reservoir around the wellbore and leading to secondary hydrate formation. Moreover, a high hydrate saturation zone appears near the decomposed hydrate area in the layer without free gas, which corresponds to the low water saturation and high salinity zone. The hydrate decomposition area in the layer with free gas is larger than that without free gas. The increase in the drilling fluid temperature significantly enhances the hydrate decomposition in both layers of the reservoir. The hydrate decomposition near the wellbore under the high drilling fluid temperature will cause a sharp increase in the pressure in the reservoir, leading to the flow of pore fluid into the wellbore. The increase in drilling fluid salinity has little effect on the range of the hydrate decomposition in the reservoir but significantly increases the salinity of the pore water in the layer with free gas. As the drilling fluid temperature increases, the possibility of the gas invasion from the reservoir into the wellbore will be greatly increased at the early stage.

Characterization of Two-Phase Flow from Pore-Scale Imaging Using Fractal Geometry under Water-Wet and Mixed-Wet Conditions

High resolution micro-computed tomography images for multiphase flow provide us an effective tool to understand the mechanism of fluid flow in porous media, which is not only fundamental to the understanding of macroscopic measurements but also for providing benchmark datasets to validate pore-scale modeling. In this study, we start from two datasets of pore scale imaging of two-phase flow obtained experimentally under in situ imaging conditions at different water fractional flows under water-wet and mixed-wet conditions. Then, fractal dimension, lacunarity and succolarity are used to quantify the complexity, clustering and flow capacity of water and oil phases. The results show that with the wettability of rock surface altered from water-wet to mixed-wet, the fractal dimension for the water phase increases while for the oil phase, it decreases obviously at low water saturation. Lacunarity largely depends on the degree of wettability alteration. The more uniform wetting surfaces are distributed, the more homogeneous the fluid configuration is, which indicates smaller values for lacunarity. Moreover, succolarity is shown to well characterize the wettability effect on flow capacity. The succolarity of the oil phase in the water-wet case is larger than that in the mixed-wet case while for the water phase, the succolarity value in the water-wet is small compared with that in the mixed-wet, which show a similar trend with relative permeability curves for water-wet and mixed-wet. Our study provides a perspective into the influence that phase geometry has on relative permeability under controlled wettability and the resulting phase fractal changes under different saturations that occur during multiphase flow, which allows a means to understand phase geometric changes that occur during fluid flow.

Intensification of proton conductivity through polymer electrolytic membrane using novel electrode pattern

The performance of a polymer electrolyte membrane fuel cell is contingent on the focal property of the protonic conductivity to accelerate the electrochemical reaction based on the membrane activity or on the uniform and even distribution of the reactants. For the even distribution, novel Flow Fields (FF) of the electrode pattern are obligatory to maintain the distribution for a long period for the conversion of protons from the anode reactant. In this study, a novel X Flow Field (XFF) electrode pattern is developed and compared with the conventional serpentine Flow Field (SFF) electrode pattern numerically and experimentally. The performance of the cell through the XFF electrode pattern has shown an improvement of 14.89% numerically and 14.61% experimentally as it distributes the reactants evenly to accelerate the electrochemical reaction, and induce a lower pressure drop and lower water saturation. The effect of pressure and Mass Flow Rate (MFR) of the reactants on the cell performance is discussed and it is found that the increment in Power Density (PD) of the cell is proportional to the increment of the MFR and the pressure because of the even distribution of the reactants, better membrane protonic conductivity, enhancement of the electrode kinetics and improvement in the mass transfer.

Application of 3D Static Modelling in Reservoir Characterization: A Case Study from the Qishn Formation in Sharyoof Oil Field, Masila Basin, Yemen

AbstractThree‐dimensional (3D) static modelling techniques are applied to the characterization of the Qishn Formation (Fm.) in the Sharyoof oil field locating within the Masila basin, southeastern Yemen. The present study was initiated by the seismic structural interpretation, followed by building a 3D structural framework, in addition to analysing well log data and from these, 3D facies and petrophysical models are constructed. In the Sharyoof oil field, the Qishn Fm. exhibits depth values within the range of 400–780 m below sea level, with a general increase towards the SSE. A set of high dip angle normal faults with a general ENE–WSW trend dissect the rocks. The strata are also folded as a main anticline with an axis that is parallel to the fault trend, formed as a result of basement uplift. According to the facies models, the Qishn Fm. comprises 43.83% limestone, 21.53% shale, 21.26% sandstone, 13.21% siltstone and 0.17% dolomite. The Qishn Carbonates Member has low porosity values making it a potential seal for the underlying reservoirs whereas the Upper Qishn Clastics S1A and C have good reservoir quality and S1B has fair reservoir quality. The Upper Qishn Clastics S2 and S3 also have fair reservoir quality, while the Lower Qishn Clastics zone has good reservoir quality. The water saturation decreases towards the west and east and increases towards north and south. The total original oil in‐place (OOIP) of the Upper Qishn clastics is 106 million STB within the S1A, S1C and S2 zones. Drilling of development wells is recommended in the eastern study area, where good trapping configuration is exhibited in addition to the presence of a potential seal (Upper Qishn Carbonates Member) and reservoir (Qishn Clastics Member) with high porosity and low water saturation.

Accelerating gas production of the depressurization-induced natural gas hydrate by electrical heating

Natural gas hydrate (NGH) will be one of the major future energy sources due to its properties of clean energy and large reserves. Depressurization is proposed as an effective method to extract natural gas from hydrate, however, the gas production from hydrate dissociation may be interrupted by ice generation and hydrate re-formation due to insufficient heat supply in the single depressurization process. To solve this issue, this work conducted simulation on accelerating gas production from the depressurization-induced methane hydrate by electrical heating. The continuous heating and intermittent heating modes were employed and then the electrical heating scheme was optimized for the comprehensive effect of high energy efficiency and high gas production rate. The results show that electrical heating is conducive to gas production from hydrate dissociation at a rapid rate. In the continuous heating, a high initial hydration saturation, low initial water saturation, low specific heat capacity, and high thermal conductivity result in the high gas generation rate and efficient electrical energy utilization (a large energy efficiency ratio). The intermittent heating has a higher efficient utilization of electrical energy than continuous heating. The optimal scheme is determined as the first-half heating type with the optimized electrical heating power of 25.6 W and the heating time of 12.5 min by the gradient descent method of AdaGrad. Compared to the baseline continuous heating case, the energy efficiency ratio (10.70) of the optimal scheme is enhanced by 24.7% with the average gas production rate (2.55 SmL/s) enhanced by 18.2%. It's hoped that the findings of this work can provide some insights into extracting natural gas from gas hydrate deposits. Electrical heating is employed to provide heat for the endothermic dissociation of methane hydrate induced by depressurization for accelerating natural gas production in this work. The electrical heating scheme is optimized to achieve high-efficient utilization of electrical energy for the fast extraction of natural gas from hydrate dissociation. • Electrical heating accelerates the depressurization induced dissociation of hydrate. • The effects of phase components and porous media properties are analyzed. • Intermittent heating has higher efficiency of energy utilization than continuous heating. • The electrical heating power is optimized by the gradient descent method of AdaGrad. • The optimal scheme is first-half heating with the optimized electrical heating power.

How petrophysical heterogeneity controls the saturation calculations in carbonates, the Barremian–Aptian of the central Persian Gulf

Water saturation calculations are among the most important aspects of reservoir characterization. Despite this importance, the effects of these calculations on the resulted oil in place remain unclear. Extreme heterogeneity in most of the carbonate reservoirs strongly affects the coefficients of the Archie equation and resulted water saturation. Therefore, a practical method to evaluate and manage the heterogeneity of such reservoirs, greatly improves the reliability of the final results. In this study, porosity, permeability, thin sections data, well logs and saturation tests of Barremian–Aptian carbonate Dariyan Formation in the central Persian Gulf have been used. Both core and reservoir scale techniques including flow zone indicator, Winland R35, electrofacies and stratigraphically modified Lorenz plot were used to evaluate the heterogeneity. Archie coefficients were arranged in different rock types. Results show that flow zone indicator is the most accurate technique to manage the heterogeneity of the reservoir with higher R2 value between porosity and permeability. The cementation factor was measured for each unit and the amounts of water saturation was calculated using deterministic analysis. Water saturation also calculated with the constant coefficients, which are routinely used in formation evaluation. The average Sw amount for constant Archie coefficients method was determined as 0.62, whereas it is 0.73, 0.80, 0.70, and 0.77 in flow zone indicator method, Winland R35 technique, stratigraphically modified Lorenz plot and electrofacies determination, respectively. The results demonstrate that calculating water saturation with constant Archie coefficients leads to slightly lower water saturation values, resulting in higher oil saturations and overestimating the oil in place.

New prospective gas plays in pliocene sands, offshore Nile Delta Basin: A case study from Kamose-1 well at North Sinai Concession, Egypt

The Pliocene sands in the offshore parts of the Nile Delta Basin represent significant gas reservoirs. Several targets have been recently discovered in different places along the offshore Nile Delta Basin. The present work focuses on the possibility of discovering new natural gas resources at North Sinai Concession through an integrated method between seismic and well logs data interpretations. A case study from Kamose-1 Well at Kamose Field, North Sinai Concession has been examined. The quantitative explanation for the well log data of Kamose-1 Well has revealed two zones expected to be gas-bearing zones. These intervals are located between depths; 1174–1186 m (zone I) and between 1429 and 1503 m (zone II). The calculated petrophysical parameters for these zones exhibit low water saturation (24–43%), high effective porosity (30–31%), low shale volume (21–26%), high total porosity (37–38%) and low bulk volume of water (0.07–0.12). Zone II (74 m thick) shows a clear bright spot on the seismic profiles covering the study area, while, zone I is beyond seismic resolution (12 m thick). Several seismic bright spots have been outlined on the seismic data nearby Kamose-1 Well. The comparison between the newly outlined seismic bright spots with the drilled one in Kamose-1 Well exhibited a great similarity. Accordingly, these prospects are expected to be new targets for gas exploration in the Pliocene succession at North Sinai Concession.

Competitive adsorption between CO2 and CH4 in tight sandstone and its influence on CO2-injection enhanced gas recovery (EGR)

CO2 flooding is a new promising way of achieving enhanced natural gas recovery (EGR) and CO2 sequestration in tight gas reservoirs. CO2 adsorption is a reality that cannot be ignored during CO2 flooding process. However, the adsorption behavior of CO2 in tight cores remains unclear. Here, the CO2CH4 competitive adsorption characteristics in tight sandstone were experimentally investigated. The results indicate that the CO2 show significantly higher adsorption capacity in the tight cores compared to CH4 and that competitive adsorption occurs after CO2 is injected into tight core preadsorbed with CH4, with over 30% of the CH4 being replaced by the injected CO2 under an ambient pressure of 24 MPa. Further, the results of sensitivity experiments demonstrated that CO2CH4 competitive adsorption is more significant in tight cores with lower permeability, higher rock fragment content, and lower water saturation, while experiments on CO2-EGR and CO2 storage showed that for tight cores with lower permeability or higher rock fragment content, the higher degree of competitive adsorption resulted in greater EGR efficiency and CO2 storage capacity. For water saturated cores, however, the dissolution of CO2 in water has a greater impact on EGR and CO2 storage compared to competitive adsorption, resulting in better EGR and CO2 sequestration efficiency at higher water saturation.

Performance Enhancement of PEM Fuel Cells with an Additional Outlet in the Parallel Flow Field

The design of bipolar plates is critical for improving the performance of proton exchange membrane fuel cells (PEMFCs). In this research, a new additional outlet based on a PEMFC’s parallel flow field was proposed, and three different positions of outlet were designed on the target side of gas flowing in parallel channels. The results revealed that the additional outlets are able to increase the gas speed through channels near the additional outlets, which results in a lower water saturation and a more uniform distribution of oxygen concentration at the interface between the catalyst layer (CL) and gas diffusion layer (GDL). With the variation of the outlet position in the target side, it was found that the additional outlet set in the middle of the target side exhibits the highest increase of peak power density, namely, 13%. Furthermore, the optimal position of the additional outlet was proved to be suitable for PEMFCs with various active surface areas, indicating the universality of the present results in the study.

Advanced understanding of gas flow and the Klinkenberg effect in nanoporous rocks

Gas flow in nanoporous rocks is closely relevant to several globally important energy and environmental issues, such as shale-gas production and CO2 subsurface sequestration. The Klinkenberg effect is critical to an understanding of gas flow, yet many specifics are unclear for nanoporous rocks. Here we investigated gas flow and the Klinkenberg effect in nanoporous rocks on the basis of a systematic study of gas permeability and diffusivity under a range of pore pressures and varying water saturations. We invalidated the use of the Klinkenberg equation for determination of intrinsic permeability and the Klinkenberg slippage factor on the basis of measurements in current laboratory conditions and propose a modified Klinkenberg equation for a more reliable determination of the slippage factor. We show that gas relative permeability is higher at higher pore pressures and that the Klinkenberg effect is more important in lower water saturations than in higher ones. The underlying mechanism of increased pore size after saturation was elucidated through neutron imaging on water distribution. In addition, we demonstrate that gas diffusivity better characterizes the diffusive gas flow than gas permeability and can be higher at higher pressures in either dry or partly saturated conditions. Finally, a characteristic pore-diameter index was derived on the basis of a new form of porosity–permeability relationship and was found to have a good correlation, which was previously lacking, with the Klinkenberg slippage factor for nanoporous rocks. Collectively, these new insights can advance the understanding of gas flow in nanoporous rocks and will have important implications on industrial applications.

An Integrated Microfacies and Well Logs-Based Reservoir Characterization of Yamama Formation, Southern Iraq

The Yamama Formation includes important carbonates reservoir that belongs to the Lower Cretaceous sequence in Southern Iraq. This study covers two oil fields (Sindbad and Siba) that are distributed Southeastern Basrah Governorate, South of Iraq. Yamama reservoir units were determined based on the study of cores, well logs, and petrographic examination of thin sections that required a detailed integration of geological data and petrophysical properties. These parameters were integrated in order to divide the Yamama Formation into six reservoir units (YA0, YA1, YA2, YB1, YB2 and YC), located between five cap rock units. The best facies association and petrophysical properties were found in the shoal environment, where the most common porosity types were the primary (interparticle) and secondary (moldic and vugs) . The main diagenetic process that occurred in YA0, YA2, and YB1 is cementation, which led to the filling of pore spaces by cement and subsequently decreased the reservoir quality (porosity and permeability). Based on the results of the final digital computer interpretation and processing (CPI) performed by using the Techlog software, the units YA1 and YB2 have the best reservoir properties. The unit YB2 is characterized by a good effective porosity average, low water saturation, good permeability, and large thickness that distinguish it from other reservoir units.

A Laboratory Approach to Measure Enhanced Gas Recovery from a Tight Gas Reservoir during Supercritical Carbon Dioxide Injection

Supercritical carbon dioxide injection in tight reservoirs is an efficient and prominent enhanced gas recovery method, as it can be more mobilized in low-permeable reservoirs due to its molecular size. This paper aimed to perform a set of laboratory experiments to evaluate the impacts of permeability and water saturation on enhanced gas recovery, carbon dioxide storage capacity, and carbon dioxide content during supercritical carbon dioxide injection. It is observed that supercritical carbon dioxide provides a higher gas recovery increase after the gas depletion drive mechanism is carried out in low permeable core samples. This corresponds to the feasible mobilization of the supercritical carbon dioxide phase through smaller pores. The maximum gas recovery increase for core samples with 0.1 mD is about 22.5%, while gas recovery increase has lower values with the increase in permeability. It is about 19.8%, 15.3%, 12.1%, and 10.9% for core samples with 0.22, 0.36, 0.54, and 0.78 mD permeability, respectively. Moreover, higher water saturations would be a crucial factor in the gas recovery enhancement, especially in the final pore volume injection, as it can increase the supercritical carbon dioxide dissolving in water, leading to more displacement efficiency. The minimum carbon dioxide storage for 0.1 mD core samples is about 50%, while it is about 38% for tight core samples with the permeability of 0.78 mD. By decreasing water saturation from 0.65 to 0.15, less volume of supercritical carbon dioxide is involved in water, and therefore, carbon dioxide storage capacity increases. This is indicative of a proper gas displacement front in lower water saturation and higher gas recovery factor. The findings of this study can help for a better understanding of the gas production mechanism and crucial parameters that affect gas recovery from tight reservoirs.