Особенности реализации инъекционных технологий составами на полимерной основе с регулируемыми параметрами в подземном строительстве. Часть II

The gas content in shale reservoirs is often determined by the micro storage and sealing capacities of the reservoir. Deep shale reservoirs are in the high- or over-thermale maturity stage and have complex pore structure and connectivity, which are highly heterogeneous in vertical distribution. Research on the gas-bearing property of deep shale reservoirs is limited by these complex microscopic conditions. To analyze the gas-bearing characteristics of deep shale reservoirs, this work collected and summarized data on total organic carbon content, mineral composition, porosity, water saturation, and gas content measured on-site for the Longmaxi Formation in the Sichuan Basin in southern Sichuan, China. Then, experimental methods, such as X-ray photoelectron spectroscopy, transmission electron microscope, low-pressure N2 adsorption, spontaneous imbibition, and high-pressure methane adsorption, were used to analyze the micro storage and sealing capacities of the deep shale reservoirs. The results show that, different from shallow shale reservoirs (<3500 m), deep shale reservoirs have a higher graphitization degree and water saturation. An abundance of graphite structures often leads to weak resistance of organic matter to compression, deformation, or even collapse of pores in organic matter and severe damage to the gas storage space. However, a higher degree of graphitization can enhance the ability of the shale reservoirs to adsorb gas and self-sealing. The high water saturation in the reservoirs can interact with clay minerals and negatively affect the gas accumulation, storage, and transmission capacities of the shale reservoirs. However, the upper shale reservoirs with higher water saturation can seal the lower shale reservoirs, helping it preserve shale gas. Based on the vertical distribution of graphite structure, clay minerals contents, lithofacies, and water content in deep shale reservoirs, the essential microscopic conditions for deep shale reservoirs to have high gas content were proposed. This paper provides a detailed explanation and evaluation of deep shale’s storage and sealing capacities at the microscopic scale and can serve as a reference for further identifying the patterns for high-yield and rich shale gas reservoirs and improving deep shale gas exploration technologies.

Sweet gas accumulations in Permian-Triassic Khuff reservoirs are key players to meet growing gas demand in Abu Dhabi. In the study green field, thickness of seven Khuff reservoir units ranges between 100 ft to 500 ft with high variation in reservoir quality and productivity. Besides the pervasive faults and fractures related to salt-dome tectonics, complex pore systems play a major role in reservoir heterogeneity that impacts fluid distribution and flow behavior. The first whole well section cores recovered from the Upper Khuff in the study field were integrated with log data to establish a sequence framework and lithofacies scheme. Routine core analysis (RCA), thin section description and mercury injection capillary pressure (MICP) results were used to define pore systems and rock types at the core scale. Afterwards integrated with petrophysical log evaluation and well test results, secondary pore system with bimodal rock types were differentiated and distributed in sequence frame at well and field scale. The layer-cake sequence of Khuff Formation is composed of aggradation cycles of lagoonal and tidal to supra-tidal deposition across the study field. Primary reservoir rocks were developed in grainy facies with intergranular macro pores from shoals and moderate-energy lagoon settings. During later diagenesis, non-selective dissolution, dolomitization and late-stage cementation in these facies resulted in tortuous pore throat and low-connected secondary micro-meso pores. In low content of these secondary pores, it retains unimodal reservoir rocks dominant by macro-meso pores. With increasing complexity in these secondary pores, it develops bimodal reservoir rocks where low-connected to isolated micro vugs form the second peak on pore size distribution and shows a stair-step on saturation-pressure curve. On the other hand, increase of the meso pores leads to a gradient change in a wide range of pore size without obvious second peak, it tends to develop multimodal reservoir rocks that can be simplified by pseudo-unimodal pressure curve with a larger transition zone. Because of the isolated pores, some reservoirs of the secondary pore system are characterized by high irreducible water saturation (Swirr) and featured as low-resistivity pay zones, where high gas rates were achieved in high water saturation (Sw) intervals without water recovery. For these reservoirs, permeability estimation from cores and logs is biased by connected macro pores, high reservoir quality index (RQI) is reserved in high Sw. But water saturated in isolated secondary pores is immovable. As such secondary pore system can be differentiated from unimodal reservoirs on J-Function with high J values and high Sw high above contact. With the seismic data constrain and statistics analysis, secondary pore reservoirs can be stochastically modelled. And its contribution to reserve can be quantified. In summary, this case study provides a method to mimic the process and impact of secondary porosities in Khuff reservoir from core to field scale.

Poroperm characteristics of high-rank coals from Southern Qinshui Basin by mercury intrusion, SEM-EDS, nuclear magnetic resonance and relative permeability analysis

The growing economy and rapid urbanization have accelerated the generation of municipal solid wastes (MSW) in Singapore. Incineration is an effective method to deal with the increasing amount of MSW because it can largely reduce the mass and volume of MSW by 70-90%. However, MSW incineration also produces incineration bottom ash (IBA), which is currently landfilled in Singapore. Since IBA, especially fine fraction of IBA, contains a certain amount of heavy metals, it may pose a threat to the environment and human beings without proper treatment. The lack of space for waste disposal is another arising problem in Singapore, which makes the land-shortage problem even worse. Land reclamation is one of the solutions for enlarging the territories, which requires a huge amount of filling materials. However, Singapore is now short of conventional filling materials such as sand and gravel. Marine clay (MC) is a common geological material in Singapore, but it is not preferred as a filling material due to its high water content and compressibility. Nevertheless, the combination of IBA and MC (IBA-MC) may complement each other’s limitations, e.g., leaching of heavy metals from IBA and poor engineering properties of MC. To further improve the strength and reduce the leaching of heavy metals of IBA-MC, the stabilization/solidification (S/S) method can be used. Ordinary Portland cement (OPC) was the main binder to stabilize/solidify the mixture of IBA and soil. However, the production of OPC is associated with high-energy consumption and enormous CO2 emissions. To substitute OPC, this research uses an industrial byproduct, ground granulated blast furnace slag (GGBS), to stabilize/solidify IBA-MC. Moreover, in practical applications, IBA-MC and stabilized IBA-MC may be immersed in groundwater or even seawater. However, despite its importance, the stability of IBA-MC and stabilized IBA-MC in water environments has not been studied. Therefore, this research aims to investigate the feasibility of using fine IBA and excavated MC treated by GGBS as filling materials for land reclamation, focusing on its stability in water environments. The first part of this study (Chapters 3 to 5) investigates the utilization of air-cured mixture of fine IBA, MC, and GGBS as filling materials in three steps. The properties of the mixture of IBA and MC are firstly investigated ( Chapter 3) to evaluate the effect of the IBA/MC ratio on the compactability, strength, and leaching of heavy metals of IBA-MC. The results show that IBA reduces the water content of MC, improving the compactability and strength of MC, while MC reduces the leaching of heavy metals from IBA. Afterward, GGBS is used to treat fine IBA for the first time and compared with OPC (Chapter 4). The results show that GGBS-IBA achieves better strength and lower leaching of heavy metals than OPC-IBA. IBA and GGBS complement each other, i.e., GGBS binds IBA and reduces the leaching of heavy metals, and IBA activates the GGBS hydration and increases the strength. Based on the findings from Chapters 3 and 4, Chapter 5 investigates the properties of IBA-MC stabilized by GGBS (GGBS-IBA-MC) and OPC (OPC-IBA-MC) cured in the air for the first time. The results show that for a relatively high IBA/MC ratio, GGBS-IBA-MC has better strength and lower leaching of heavy metals than OPC-IBA-MC. The second part of this study (Chapters 6 to 7) investigates the stability of IBA-MC and stabilized IBA-MC in water environments for the first time. As a further work of Chapter 5, Chapter 6 investigates the stability of compacted IBA-MC, GGBS-IBA-MC, and OPC-IBA-MC soaked in distilled water and seawater. The results show that after soaked in water environments, especially seawater, IBA-MC and OPC-IBA-MC tend to generate cracks on the surfaces and have much lower strength compared with GGBS-IBA-MC. The decreasing suction force inside specimens and formation and growth of ettringite were two possible reasons for the instability of IBA-MC and OPC-IBA-MC in water environments. In Chapter 7, IBA-MC, GGBS-IBA-MC, and OPC-IBA-MC are made as pumpable filling materials to further examine their stability mechanism in water environments. IBA-MC and OPC-MC-IBA soaked in water environments, especially seawater, exhibit instability and higher strength reduction compared with GGBS-IBA-MC. The stability of GGBS-IBA-MC was significantly higher than OPC-IBA-MC with the same binder content. These findings were consistent with those for the compacted specimens. Since the pumpable specimens had a high water content and saturation degree, the suction inside was negligible. Moreover, no weak interfaces were generated during specimen preparation. Therefore, formation and growth of ettringite was deemed as the primary cause for the differences in the stability of OPC-IBA-MC and GGBS-IBA-MC.

The peculiarity of alkali-activated slag cements (further, AASC’s) is increased proper deformations, which can cause increased cracking and reduced durability of structure. The paper is devoted to manage AASC’s proper deformations. The main task was to determine the composition of complex additives (further, CA’s) in system «ordinary portland cement (further, OPC) clinker - mineral compound of different anionic type - surfactant» in presence of sodium metasilicate (further, MS) to affect on hydrated AASC performance while ensuring effective structure of artificial stone by criterion of shrinkage deformations. Comparative analysis of hydrated cement systems "OPC clinker - MS", "OPC clinker - mineral compound - MS" and "OPC clinker - mineral compound - MS - surfactant" showed that the greatest effect on reduction of proper deformations occurs when the mineral compounds relate to electrolytes, i.e. Na2SO4 and NaNO3. Hydrated system is characterized by expansion (+0,062 mm/m) in presence of Na2SO4. Almost no shrinkage is supplied by application of NaNO3 (-0,062 mm/m). The obtained CA’s were tested in AASC. CA in the system “OPC clinker - NaNO3 - surfactant” provides the initial setting 43 min, the end - 65 min with accelerated strength. Investigated AASC can be classified as non-shrinking cement. This phenomena is ensured by increasing density, homogeneity and monolithicity of hydrosilicate formations, as well as due to formation of hydroaluminosilicate structures with different morphology by inclusion of nitrate anions.

The uncertainty of two recently proposed methods, “new fluid factor” and “delta K”, is analyzed under different water saturation and noise conditions through Monte Carlo modelling. The new fluid factor performs reliably (all metric parameters are above 0.9) when the water saturation is up to 95%. The delta K has better performance (all metric parameters are close to 1) such that it is able to distinguish hydrocarbon from brine without the interference of high water saturation. The results prove the performances of the two methods are stable in a high water-saturation scenario. The analysis of noise indicates the methods are sensitive to noise in the input data in that the performance is excellent when the noise is relatively low (−20 dB) and decreases with increasing noise energy. The new fluid factor, which is in the interface domain, is more sensitive than delta K in the impedance domain. The metric parameters of the new fluid factor and delta K are in the range of 0.5 to 0.8 when the noise is high (−7 dB). High-quality input data and integration with other geophysical methods can effectively reduce these risks. In addition, two widely used traditional methods (fluid factor and Lambda-Rho) are analyzed as comparisons. It turns out the new fluid factor and delta K have better performance than traditional methods in both high water saturation and noise conditions.

Accurately determining the relationship between water saturation and recovery factor, as well as elucidating the underlying action mechanisms, is of critical importance for the selection of water drive development approaches in tight reservoirs and for maximizing the ultimate recovery factor. In this study, commencing with the relationship between various water saturation and the recovery factor, a comprehensive exploration of the relationship between water saturation and the recovery factor, along with the influencing mechanisms, is carried out. This is achieved by integrating displacement and imbibition experiments with molecular dynamics simulations. The experimental results indicate that as the water saturation increases, the displacement recovery decreases, whereas the imbibition recovery increases. The molecular dynamics simulations results reveal that when the initial water saturation is relatively high, the displacement process is difficult to initiate, and the imbibition rate is relatively fast. For reservoirs with high water saturation, a relatively high recovery factor can be achieved by choosing the imbibition development approach. For reservoirs with low water saturation, the displacement development approach can be adopted in the early stage of exploitation, and a combined displacement–imbibition development approach is more suitable for the middle and late stages. This study provides novel insights into the action mechanisms of different water saturation on the recovery and offers new perspectives on the selection of water drive development strategies for tight reservoirs.

Determination Of Irreducible Water Saturation Using Magnetic Resonance Imaging Logs (MRIL): A Case Study From East Texas, USA Abstract Control of water production and identification of pay zones with high irreducible water saturation are two formation evaluation problems in the United States, the Middle East, and other fields around the world. These problems have delayed completion decisions and have burdened field management with additional expenses. This paper discusses a case study from East Texas where key field problems such as these could not be solved with conventional logs alone. In the subject field, water production is almost impossible to predict from conventional openhole logs. Some zones with relatively low water saturation, as calculated from the logs, produce with a relatively high water cut, primarily because much of the water is movable. However, other zones with high calculated water saturation produce water free hydrocarbons. The difficulty in predicting water production arises from the petrophysics of the producing formations, which are low-permeability, medium- to fine-grained shaly sands. Where grains are small, the formations have high surface-to-volume ratios that result in high irreducible water saturation and, thus, lowered bulk resistivities. Hence, the use of resistivity logs as pay indicators can cause low-resistivity pay zones to be overlooked and, consequently, net field pay to be underestimated. In the last few years, nuclear magnetic resonance (NMR) logs have shown great promise in solving problems of formation evaluation that could not be directly resolved with conventional logs. The capability of NMR logs to differentiate between the immovable and movable water has added reserves of up to 10% in many fields where, although water saturation was high, much of the water was immovable. NMR logs have also been capable of providing better formation permeability than conventional logs, a feature that can save time and expense in well-completion decisions. Because of these two capabilities, it seemed appropriate to apply NMR technology to the subject field. The tool selected for use in the field was an improved version of a mandrel-type, centralized, magnetic-resonance imaging device known as the MRIL@ C-type tool. A series of logs were run in several wells. Accurate determination of movable water from these logs allowed operators to (1) better select pay zones to minimize water production and (2) eliminate the expense of unnecessary conventional logs. The MRIL tool is now run as a regular service in this field. This paper includes examples of MRIL logs, discusses possible applications in the Middle East, and presents recommendations derived from NMR logging experience. Introduction In formation evaluation, induction and resistivity logs are the main hydrocarbon identifiers because of the resistivity contrast between high-resistivity hydrocarbons and low-resistivity formation brine and clay minerals. If, however, a clean zone exhibits low resistivity because of formation brine, these two logs are incapable of indicating water mobility. Because of this limitation, many potentially productive hydrocarbon zones with high irreducible water saturation are bypassed because of fear of excessive water production. A major problem in East Texas is identification of low-resistivity pay zones. Because of the very fine sand grains in this area, formation surface-to-volume ratios are large; thus, formations can hold large volumes of water. P. 155^

It’s difficult in identifying hydrocarbon bearing formation from conventional logs in tight sandstone reservoirs due to the low resistivity contrast caused by the complicated pore structure and high water saturation in north Ordos basin. The experiment of relative permeability illustrates that the water saturation of the target Chang 6 Formation mentioned in this study reach to 58%. To identify hydrocarbon bearing formations from water saturated layers, a method, which is the minimal resistivity method is introduced. To obtain the minimal resistivity of hydrocarbon bearing reservoir, two novel methods, which are formation simulation and rock resistivity experiments, are proposed in this paper. The results shows that the minimal resistivity of hydrocarbon bearing layer in Chang 6 Formation is 40Ω.m. Field examples shows that the proposed methods are effective in obtaining the minimal resistivity and identifying hydrocarbon bearing formations with high water saturation, they can be extended widely in other tight sandstone reservoirs.

Analysis of a gas-phase partitioning tracer test conducted in an unsaturated fractured-clay formation

The reservoir characterization and rock typing is a significant tool in performance and prediction of the reservoirs and understanding reservoir architecture, the present work is reservoir characterization and quality Analysis of Carbonate Rock-Types, Yamama carbonate reservoir within southern Iraq has been chosen. Yamama Formation has been affected by different digenesis processes, which impacted on the reservoir quality, where high positively affected were: dissolution and fractures have been improving porosity and permeability, and destructive affected were cementation and compaction, destroyed the porosity and permeability. Depositional reservoir rock types characterization has been identified depended on thin section analysis, where six main types of microfacies have been recognized were: packstone-grainstone, packstone, wackestone-packstone, wackestone, mudstone-wackestone, and mudstone. By using flow zone indicator, four groups have been defined within Yamama Formation, where the first type (FZI-1) represents the bad quality of the reservoir, the second type (FZI-2) is characterized by the intermediate quality of the reservoir, third type (FZI-3) is characterized by good reservoir quality, and the fourth type (FZI-4) is characterized by good reservoir quality. Six different rock types were identified by using cluster analysis technique, Rock type-1 represents the very good type and characterized by low water Saturation and high porosity, Rock type-2 represents the good rock type and characterized by low water saturation and medium–high porosity, Rock type-3 represents intermediate to good rock type and characterized by low-medium water saturation and medium porosity, Rock type-4 represents the intermediate rock type and characterized by medium water saturation and low–medium porosity, Rock type-5 represents intermediate to bad rock type and characterized by medium–high water saturation and medium–low porosity, and Rock type-6 represents bad rock type and characterized by high water saturation and low porosity. By using Lucia Rock class typing method, three types of rock type classes have been recognized, the first group is Grain-dominated Fabrics—grainstone, which represents a very good rock quality corresponds with (FZI-4) and classified as packstone-grainstone, the second group is Grain-dominated Fabrics—packstone, which corresponds with (FZI-3) and classified as packstone microfacies, the third group is Mud-dominated Fabrics—packstone, packstone, correspond with (FZI-1 and FZI-2) and classified as wackestone, mudstone-wackestone, and mudstone microfacies.

ABSTRACTThe effect of wettability on oil recovery at higher water saturation is still not fully understood, especially in the case of mixed wettability. This study was conducted to examine the effects of wettability on oil recovery and breakthrough time through experiments for two wettability conditions (water-wet and mixed-wet) and three water saturations (20%, 40%, and 60%). Clashach sandstone core with a porosity of 12.8% and a permeability of 75 md was utilized as the porous media. Immiscible gas flooding was performed by injecting nitrogen gas into the core at room temperature and pressure. The results showed 54.3% and 48.8% of the initial oil in place (IOIP) as the ultimate oil recovery at 40% water saturation from mixed-wet core and water-wet core respectively. In contrast, the water-wet core displayed better results (32.6% of the IOIP) in terms of breakthrough time compared to the results of water-wet core (10.6% of the IOIP) at the same water saturation. In conclusion, oil recovery was found highly dependent on water saturation while breakthrough time was mainly affected by the wettability of the cores.

Certain sands may possess low electrical resistivity and yet may be capable of producing oil. A method for recognizing them involves deriving for each formation an empirical correlation that relates the irreducible water saturation to pore space surface area or formation shaliness. Rock sample analyses and logs are needed to calibrate the interpretation method for any specific application. Introduction Some oil-productive horizons have such low electrical resistivities (generally less than 1 ohm-m) that to distinguish them from water-producing zones is difficult, if not impossible, using standard log interpretation procedures. The reason for the difficulty is that these procedures. The reason for the difficulty is that these procedures normally result in the calculation of high procedures normally result in the calculation of high formation water saturation (50 percent or greater). The accuracy of the calculation may be doubtful or its relevance to the formation irreducible water saturation may be unknown. Experience has shown that the high electrical conductivity (low resistivity) of these formations is due to the combined effects of high-salinity or low-resistivity brine in the pore space, high formation porosities, high content of formation shale or clay, and high interstitial water saturations. A variety of log interpretation procedures have been proposed in the literature to solve this problem of low-resistivity or shaly sand. These procedures have been divided into two broad types. Type I - The water saturation is calculated from resistivities measured in the mud-filtrate-invaded portion of the sand and from resistivities measured portion of the sand and from resistivities measured in the uninvaded sand, and includes corrections for shaliness usually derived from the SP log. Although water saturations are not usually calculated directly for both the mud-filtrate-invaded zones and the uninvaded zones, the interpretation procedures are based upon the change in water saturation resulting from the mud-filtrate invasion. Therefore, if the water saturations calculated for the invaded and the uninvaded zones are about the same, this suggests that the horizon will be water productive since no hydrocarbon was moved by the invading fluid. However, if the water-saturation near the wellbore is higher, then this indicates that the formation contains movable hydrocarbons (which have been displaced by the mud filtrate) and will likely be oil productive. Some of the log interpretation procedures that fall in this group are the Rocky Mountain method and the procedures proposed by Poupon et al. and by Patchett and Rausch. proposed by Poupon et al. and by Patchett and Rausch. A major disadvantage of log interpretation procedures of this type is that retable measurements of the resistivity of the mud-filtrate-flushed or mud-filtrate-invaded zone must be obtained. Since mud-filtrate invasion into shaly intervals is usually quite shallow, these procedures are frequently ineffective. Type II - The second type of log interpretation involves calculating the water saturation from resistivities measured in the formation beyond the zone invaded by mud filtrate and includes corrections for shaliness derived from the response of other logs. The successful application of this approach demands a knowledge of the magnitude of the formation irreducible water saturation. JPT P. 1302

In pot experiments grape vine was grown on a calcareous and on a non calcareous soil with a low and with a high water saturation. During the growing period soil solution samples were collected and analyzed for their pH and for HCO 3 − , phosphate, Fe, and Ca. High water saturation resulted in a pH increase and in an increase of the HCO 3 − concentration in both soils. The level in pH and HCO 3 − , however, was much higher in the calcareous soil than in the non calcareous soil. The Fe concentration varied much throughout the experimental period, but there was no major differences between soils and water saturation treatments. The Ca concentration of the soil solution increased with time in the calcareous soil; for the non calcareous soil rather the reverse was true. The phosphate level in the soil solution of the non calcareous soil was about 10 times higher than in the calcareous soil. After 3 weeks growth all plants of the calcareous soil with the high water saturation showed first symptoms of Fe deficiency. These became more intense from day to day. Plants of the other treatments did not show any chlorotic symptoms. In the treatment with the chlorotic plants the HCO 3 − concentration of the soil solution was the highest, the phosphate concentration the lowest from all treatments. It is therefore concluded that HCO 3 − and not phosphate is the primary cause for lime induced Fe chlorosis. Despite the low phosphate concentration in the soil solution, the P concentration in the chlorotic leaves was more than twice as high as the P concentration in green leaves grown on the same soil. It is thus assumed that the high P content frequently found in chlorotic leaves is the result and not the cause for Fe chlorosis.

Resistivity, an electrical property, was the first rock property logged in a well, and it is still one of the most important properties logged. Recall from Chapter 3 that most water saturation calculations are based on establishing a ratio of resistivities. If we compare a rock’s resistivity to the resistivity it would have at 100% water saturation, we can calculate the water saturation from Archie’s equation. Then we can infer that the balance of the pore spaces are occupied by hydrocarbon. However, we must resist the temptation to draw the apparently logical conclusion that the resistivity curves recorded on a log are saturation curves. A low resistivity does not by itself mean there is a high water saturation. We must still compare the resistivity to the value it would have if saturated with water. This requires knowledge of the rock’s porosity as well as its resistivity.