Sealed Coring Research Articles

Research and Application of Sealed coring Technology in In-situ Coal Seam of Directional Long borehole in Coal mine

In order to accurately obtain the gas content of in-situ coal seams in coal mines, a sealed coring technology for in-situ coal seams in coal mines has been proposed. By utilizing the pressure difference generated by high-pressure water at both ends of the piston, the piston is driven to cut off the positioning pin, which in turn drives the ball valve in the coring device to rotate, achieving the goal of cutting off and sealing the in-situ coal core. Performance tests were conducted on the sealing pressure of the coring device by opening the amount of water holes on the piston and using suspension pins of different materials, verifying the working parameters of the piston opening amount and suspension pins of different materials, providing basic data for subsequent industrial underground tests. Finally, during the industrial test underground, it was found that the gas content in the coal seam measured by closed sampling was 1.9-2.5 times higher than that of the coal seam sampled by the hole, which verified the successful design of the closed sampling device.

An Artificial Neural Network Model for Predicting Initial Water Saturation of Petroleum Reservoirs

Initial Water saturation is the water saturation of a reservoir before production commences. It enables the reservoir engineer to properly estimate the correct volume of Oil or gas reserves and to produce without water. And over the years over estimation or under estimation had caused major changes in the decision making of oil companies. New techniques are developed as technology advances to measure water saturation. These are the most widely used techniques for determining water saturation, nevertheless. Measurements obtained directly from a sealed core, which are more expensive, or calculations made using the Archie equation on sample well logs, which are less expensive. In this Project, Artificial Neural Network (ANN) model is the sole purpose of the modelling. The datasets are gathered, processed, trained, tested and validated.

The bitumen development effect on the pore structure and electrical resistivity of carbonate reservoirs in the Sinian Dengying Formation

Abstract In the Sichuan Basin, bitumen widely distributes in the carbonate reservoir, and the bitumen occurrence morphology affects the pore structure and petrophysics. Two types of bitumen, boundary-filled and centre-filled, were reconstructed using a pore morphology-based method based on dolomite carbonate digital cores from X-ray computerized tomography. The pore structures of the reconstructed bitumen-filled digital core models were determined using an extracted pore network model. The finite element method simulated the electrical resistivity of the digital core model. The investigation showed that (i) boundary-developed bitumen increases the pore size whereas centre-developed bitumen decreases the pore size, and bitumen development increases the shape factor while reducing the coordination number; (ii) for electrical resistivity, boundary-filled bitumen increases the porosity exponent with increasing pore size, whereas centre-filled bitumen decreases the porosity exponent. Bitumen development caused a negative correlation between the porosity exponent and pore shape factor, a logarithmic increase between the porosity exponent and coordination number, and a power increase between the porosity exponent and porosity. Subsequently, a new porosity exponent model related to porosity was proposed based on the curve-fitting method. This new porosity exponent combines the Archie equations to calculate the saturation of the carbonate reservoir in the Sinian Dengying Formation in the Penglai gas area on the northern slope of the central Sichuan paleo-uplift, which fits the sealed core plug saturation well and provides the basis for further reservoir evaluation and fluid identification in the Penglai gas area.

Simulation of Rock Electrical Properties in Deep Reservoirs Based on Digital Rock Technology

Deep reservoirs are in a high-pressure and high-temperature (HPHT) environment, while the experimental conditions for rock electrical properties that meet the deep reservoir conditions are harsh and costly. Although digital rock technology can simulate the electrical properties of rocks, it is limited to electrical simulation studies under normal temperature and pressure conditions (NPT), which limits their ability to capture the electrical characteristics of deep hydrocarbon reservoirs. This limitation affects the accuracy of saturation prediction based on resistivity logging. To simulate the rock electrical properties under HPHT conditions, we proposed a low-cost and high-efficiency HPHT digital rock electrical simulation workflow. Firstly, samples from deep formations were CT-scanned and used to construct multi-component digital rocks that reflect the real microstructure of the samples. Then, mathematical morphology was used to simulate the overburden correction under high-pressure conditions, and the changes in the conductivity of formation water and clay minerals at different temperatures were used to simulate the conductivity changes of rock components under high-temperature conditions. To carry out the electrical simulation of digital rock in deep reservoirs, a numerical simulation condition for HPHT in deep layers was established, and the finite element method (FEM) was used. Finally, based on the equivalent changes in the conductivity of different components, the effects of clay minerals and formation water under HPHT conditions on rock electrical properties were studied and applied to predict the water saturation based on well logging data. We found that considering the influence of temperature, salinity, and clay type, the saturation index (n) of the rock depends on the ratio of the clay conductivity to the formation water conductivity. The larger the ratio is, the smaller the value of n. In addition, the average relative error between the predicted water saturation under HPHT conditions and the sealed coring analysis was 6.8%, which proved the accuracy of the proposed method. Overall, this method can effectively simulate the pressure and temperature environment of deep formations, reveal the electrical conductivity mechanisms of rocks under formation pressure and temperature conditions, and has promising prospects for the study of rock physical properties and reservoir evaluation in deep formations.

Research on Gas Content Determination Method of Coal Mine Closed Core

In order to improve the accuracy and expand the measuring range of coal seam gas content, Sihe Mine has introduced a long-distance sealed coring gas content measuring device, which can seal the hole after drilling coal samples, and the sampling depth can reach more than 300m, but no suitable gas content measuring method has been formed yet. Through theoretical analysis, coal sample high pressure adsorption and desorption experiment, gas content measurement and contrast engineering test, the gas content measurement process and loss compensation model of long-distance closed coring were studied, and the gas content measurement method of long-distance closed coring was formed. The gas content in coal seam measured by this method is about 4.71% higher than that measured by core tube on average, which improves the measurement accuracy of gas content in coal seam and is of great significance for promoting gas control in coal mine.

Genetic mechanism of permeability anisotropy in conglomerate reservoir and its controlling factors

Abstract The near-source, multistream, and rapidly changing sedimentary environments of conglomerate reservoirs lead to reservoir characteristics such as strong heterogeneity and complex modal pore structure, which create unique seepage pathways and strong permeability anisotropy, which in turn affect the displacement mode and oil recovery of crude oil in pores and throats. Thus, it is necessary to clarify the genetic mechanism and controlling factors of this permeability anisotropy, providing the basis and premise of sustainable and efficient development of conglomerate reservoirs. In this paper, a typical conglomerate reservoir from the Kexia Formation in the 7th Block of the Karamay oilfield (Xinjiang, China) was selected as the research object to solve the permeability anisotropy problem. According to the sealed coring data, eight conglomerate samples were cut preliminarily in the field and prepared finely in the laboratory to make standard cube samples with side lengths of 4.5 cm, and then these samples were investigated using casting thin section, computed tomography scanning, and constant velocity mercury injection experimental methods to determine the genetic mechanism of permeability anisotropy and its controlling factors at macro- and microscales. The results showed that sedimentation and hydrodynamic conditions controlled the distribution of permeability anisotropy, the separation, rounding, and arrangement of mineral particles, the development of sedimentary structural planes, and the different types of packing textures, which affected the seepage paths and resistance in different directions, resulting in great differences in permeability anisotropy. The permeability in the direction parallel to water flow was the largest, followed by the direction perpendicular to water flow, and the permeability in the vertical sedimentation direction was the lowest because of the combined influences of the tortuosity of seepage, the connectivity of pore throats, and the sedimentary structural planes. In addition, diagenesis in later stages can reduce the absolute value of permeability in different directions and the strength of permeability anisotropy by changing the micropore structure of the conglomerate reservoir, but it will not change the distribution of permeability anisotropy. Based on these observations, a generalized linear mixed model was used to analyze the micropore structure parameters and standard deviation of permeability in different directions from the eight conglomerate samples, and the results showed that the relative sorting coefficient had the greatest influence on the standard deviation of permeability, and the uniformity of pore-throat size distribution was the main microscale controlling factor on the strength of permeability anisotropy. When the pore-throat size distribution was less uniform, the difference in the amplitude of permeability anisotropy was more obvious. The average capillary radius, seepage tortuosity, and maximum pore-throat radius showed less importance than relative sorting coefficient, so they are considered secondary factors. The other micropore structure parameters showed some influence on the permeability anisotropy, but the degree of influence was limited.

A novel method for quantitative analysis of brine and oil saturation in a sealed low permeable core based on one-dimensional (1D) NMR technique

The nondestructive technology for analyzing the in-situ brine and oil distribution is of great significance for laboratory characterization of the sealed core samples. In this paper, a novel method is proposed for quantitative analysis of brine and thin oil saturation in a sealed low permeable core based on one dimensional (1D) NMR technique. Based on the difference of critical phase transition temperature of the two components, the variation of 1H proton spin relaxation signal for oil and water phase could be distinguished and therefore the oil and water saturation could be measured in the nondestructive manner. The proposed method, including the experimental and data analysis procedure was demonstrated and validated in the case on determination of oil/brine composition in a sealed low permeable sandy conglomerate sample. Through comparison of the T2 spectrum at temperature of 25 °C where both brine and oil are in liquid phase and at temperature of −15 °C where the brine freezes to solid phase, the brine and oil saturation in the low permeable core are successfully obtained. It is expected the proposed method could essentially support the laboratory analysis of the in-situ component compositions.

An improved saturation evaluation method of Chang 8 tight sandstone reservoir in Longdong West area of Ordos Basin, China

This study focus on saturation evaluation of Chang 8 tight sandstone reservoir in Longdong West area of Ordos Basin, China. An improved saturation calculation method was proposed based on the equivalent rock capillary bundle theory. Firstly, according to characteristics of reservoir pore structure and rock conductivity, the conductive space of reservoir rock is equivalent to the parallel conductive of micro capillary bundle representing the micro pores and the coarse capillary bundle representing the macro pores. Then, the variable cementation index(m) saturation model was deduced by using Poiseuille flow equation and Darcy's law. During the calculation of model parameters, the T2 spectrum data of nuclear magnetic resonance (NMR) was used to calculate the equivalent radius of reservoir micro pores and macro pores, which ensured the ability of model popularization and application. Finally, the proposed saturation calculation method is applied to reservoir evaluation of the study area, and compared with the classical Archie saturation model. The application effect shows that the calculated saturation from the proposed variable m model is much closer to the sealed coring data than that from classical Archie model, and the average relative error of saturation calculated by the variable m model is within 7%, which proves that the proposed saturation calculation method is applicable and effective.

Tutorial: A Century of Sidewall Coring Evolution and Challenges, From Shallow Land to Deep Water

Due to the high cost of conventional coring operations, rotary sidewall coring has become increasingly important, particularly for deepwater operations. The rig costs, operational challenges, and amount of time involved to core wells below 30,000 ft are considerable, even for wireline operations. As wells get deeper, formation pressures will exceed 30,000 psi, and differential pressures can exceed 10,000 psi, which will eclipse the capabilities of traditional rotary coring tools. New technology has been introduced to enhance the recovery of rotary sidewall cores to improve operations and capabilities on these challenging wells that will be the primary subject of this paper. This new technology can also enhance coring operations and reliability for land and other offshore operations, in addition to deep water. New improvements and challenges include: * Reliable 1.5-in.-diameter core samples, with a 35,000-psi-rated tool * New high-powered coring tools with enhanced energy to address cutting Lower Tertiary wellcemented formations (Wilcox, Lower Miocene, etc.) * Higher torque and horsepower at the bit to enhance cutting and prevent stalling when coring * High-powered surface systems along with highstrength and high-power wireline cables * Upgrades to address high temperatures, highdifferential pressures, high-mud viscosity, large (24 in.) boreholes, and improved reliability * New drill bits and catcher rings to use a high-power system and operate in harsh coring environments * New cutting, retrieval, and core handling advancements for reliability in hard, consolidated formations * Combinability upgrades to reduce wireline trips and reduce rig costs for coring * Dual-coring tools with the ability to have different catcher rings and bits downhole simultaneously on a single run, along with tool redundancy downhole for improved reliability * Combination of rotary coring and formation sampling operations to obtain formation pressures, fluid samples, and rotary sidewall cores on a single run * Downhole monitoring of the coring operation, which includes drilling functions like torque, bit force, penetration rate, core bit penetration, and recovered core length, along with tool orientation * Core recovery information to enable 100% core verification downhole, so extra cores are not cut unnecessarily during the job, with individual core plugs measured and verified downhole * A unique method to seal the cores in a pressurecompensated coring tube downhole to capture all the formation fluids in the rock in downhole conditions * Complete rotary coring downhole operations can be monitored remotely for offsite interaction during the coring operation Besides reviewing historical coring tools and techniques, new technology is also discussed in more detail. The new technology starts with the introduction of the 1.5-in.-diameter rotary sidewall coring tools for deep water over a decade ago. Many applications and technologies are presented to show their effectiveness for deepwater operations. The successful examples include acquiring 1.5-in. cores in large boreholes, hard formations, deep wells, high-differential pressures, and extreme hydrostatic pressure. There are also examples of new technology available for future operations, including dual coring, combination coring, and sealed pressurized coring.

Experimental study on the geomechanical properties and failure behaviour of interbedded shale during SAGD operation

Interbedded shale (IBS) impedes the development of a steam chamber and poses a serious threat to the success of any steam-assisted gravity drainage (SAGD) operation in a heavy-oil reservoir. Breaking up IBS has been a continual challenge for the industry. This study summarizes experimental studies on the geomechanical properties and failure behaviour of IBS during thermal stimulation. IBS cores were collected by means of fully sealed coring in northwestern China. Mineral composition analysis, porosity, and permeability measurement, as well as imbibition tests, were initiated to evaluate the potential of imbibition. First, shear failure behaviour was studied through triaxial compression tests. Second, pore structure and failure processes of IBS were investigated through thermal stimulation experiments. Mudstone IBS was considered as the focus. Its porosity was approximately 7% and permeability was approximately 100 nD while in-situ stress was applied. Although IBS contained considerable smectite components, it didn’t disintegrate under high-effective stress. Last, shear failure behaviour of IBS was observed by computer tomography (CT) scanning when IBS was heated up to 180 °C under constant radial confining pressure and axial constraint of strain. While imbibition causes disintegration of IBS, it is unlikely when under in-situ stress conditions. Fortunately, shear failure can be achieved under uniaxial boundary conditions with rapid heating.

Predicting oil saturation of tight conglomerate reservoirs via well logs based on reconstructing nuclear magnetic resonance T2 spectrum under completely watered conditions

Abstract Due to complex lithology, strong heterogeneity, low porosity and permeability; resistivity logging faces great challenges in oil saturation prediction of tight conglomerate reservoirs. First, 10 typical core samples were selected to measure and analyse the porosity, permeability, nuclear magnetic resonance (NMR) T2 spectrum and mercury injection capillary pressure (MICP) curve. Second, an empirical method was proposed for reconstructing the NMR T2 spectrum under completely watered conditions using MICP curve based on the ‘three-piece’ power function. The parameters of different models were calibrated via experimental data analysis, respectively. The 180 core experimental data from an MICP curve were used as the input database. Porosity and permeability were regarded as the MICP data selection criteria to apply this model in formation evaluation. The comparison results show good application effects. Finally, to reflect oil saturation, the ratio of T2 geometric means of NMR T2 spectra under oil-bearing and completely watered conditions was proposed. Then, the quantitative relation between oil saturation and the proposed ratio was established via experimental data from the sealed cores, which established a quantitative prediction on oil saturation of tight conglomerate reservoirs. This showed a good application effect. The average relative error and the root mean square error (RMSE) of the predicted oil saturation and sealed coring measurement were around 10 and 3%, respectively. As the proposed method is only influenced by the wettability of reservoir and viscosity of oil, it is not only appropriate for the studied area, but also for other water-wet reservoirs containing light oil. It is important for identifying oil layers, calculating oil saturation and improving log interpretation accuracy in tight conglomerate reservoirs.

Origin and formation mechanisms of low oil saturation reservoirs in Nanpu Sag, Bohai Bay Basin, China

Abstract Low oil saturation reservoirs are increasingly encountered in superimposed sedimentary basins, however, the uncertainty about the origin of the low oil saturation becomes a major factor impeding further hydrocarbon exploration. Routine core analysis, (fluorescence) thin section, scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) measurements were used to understand the characteristics and formation mechanisms of the low oil saturation reservoirs in the Paleogene Dongying Formation in the Nanpu sag, Bohai Bay Basin, East China. Irreducible water saturation was determined from sealed coring oil saturation testing and NMR logs. Wide ranges of porosity and permeability were observed, and the samples with moderate reservoir quality have the best oil bearing property. Low oil saturation oil layers are characterized by low oil saturation ( 40%), with only oil being produced whereas no water or only minor amounts of water being produced. The low oil saturation oil-water reservoirs refer to the low oil saturation layers in which both oil and water will be produced during oil testing. Irreducible water saturation increases with total clay content, with the authigenic clays (kaolinite, illite and mixed layer illite/smectite) blocking pore spaces, and resulting in high irreducible water saturations. Fluorescence thin sections combined with NMR measurements show that the NMR T2 (transversal relaxation time) distribution is uni-modal, with large intergranular pores being rare. Almost the entire pore-size range is oil bearing for the low oil saturation oil reservoirs. The large intergranular pores are fluorescence-free, while the intragranular dissolution pores and micropores emit fluorescence in the low oil saturation oil-water reservoirs. The NMR T2 distribution of low oil saturation oil-water reservoirs is bi-modal and right-skewed, and the main oil-bearing NMR pore size distribution ranges from 0.1 to 100 ms. High irreducible water content was encountered in the low oil saturation oil reservoirs and low oil saturation oil-water reservoirs, and only part of the large intergranular pores are oil saturated, and in some cases only the intragranular pores are saturated with oils forming low oil saturation oil reservoirs. The results help improve the knowledge of characteristics and formation of the low oil saturation oil layers, and could provide insights in enhancing oil recovery.

Fault and natural fracture control on upward fluid migration: insights from a shale gas play in the St. Lawrence Platform, Canada

Environmental concerns have been raised with respect to shale gas exploration and production, especially in eastern Canada and northeastern United States. One of the major public concerns has been the contamination of freshwater resources. This paper focuses on the investigation of possible fluid upward migration through structural features in the intermediate zone (IZ), located between a deep shale-gas reservoir and shallow aquifers. The approach provides insights into how such an investigation can be done when few data are available at depth. The study area is located in the shale-dominated succession of the St. Lawrence Platform (eastern Canada), where the Utica Shale was explored for natural gas between 2006 and 2010. Detailed analyses were carried out on both shallow and deep geophysical log datasets providing the structural attributes and preliminary estimates of the hydraulic properties of faults and fractures. Results show that the active groundwater flow zone is located within the upper 60 m of bedrock, where fractures are well interconnected. Fractures from one set were found to be frequently open in the IZ and reservoir, providing a poorly connected network. The fault zones are here described as combined conduit-barrier systems with sealed cores and some open fractures in the damage zones. Although no direct hydraulic data were available at depth, the possibility that the fracture network or fault zones act as large-scale flow pathways seems very unlikely. A conceptual model of the fluid flow patterns, summarizing the current understanding of the system hydrodynamics, is also presented.

A new method of water phase trapping damage evaluation on tight oil reservoirs

Displacement pressure difference and initial water saturation are two key factors of evaluating water phase trapping (WPT) damage under a given reservoir situation. Requiring a high displacement pressure to drive liquid through a tight rock, the conventional method has difficulty in measuring very small liquid flow rates. Besides, it exists a strongly advantageous flow path selectivity phenomenon, causing a situation that the water existing in those thinner pores cannot be moved effectively. As a result, the irreducible water saturation is high after oil displacing water, thus leading to an overestimated oil permeability damage from WPT. This paper would have presented a high back pressure displacement method (HBPD) for the establishment of initial water saturation and measurement of liquid permeability of core samples from tight oil reservoirs. Then the damage of WPT using this new method was compared with the results obtained by the conventional method. According to the reservoir fluid flow situation, pore pressure and downstream pressure were simulated by the operation of back pressure. Results showed that an average initial water saturation (Swi) of 46.2% was established by the conventional method. However, the Swi established with the use of this new method was only 29.9%, which was consistent with the results from sealed core data of the reservoir. The oil permeability damage derived from water phase trapping was estimated as an average of 37.0% with the conventional method while that of 21.8% by the new method respectively. The conventional method overestimated the damage of water phase trapping at 41.4%. Our research appears to have an insight into analyzing oil-water flow behaviors and investigating the reservoir forming process of tight oil reservoirs.

Permeability anisotropy and relative permeability in sediments from the National Gas Hydrate Program Expedition 02, offshore India

Gas and water permeability through hydrate-bearing sediments essentially governs the economic feasibility of gas production from gas hydrate deposits. Characterizing a reservoir's permeability can be difficult because even collocated permeability measurements can vary by 4–5 orders of magnitude, due partly to differences between how various testing methods inherently measure permeability in different directions and at different scales. This study uses a customized flow anisotropy cell to investigate geomechanical and hydrological properties of hydrate-bearing sediments focusing on permeability anisotropy (i.e., horizontal, kh, to vertical, kv, permeability ratio) and relative permeability. Two cores recovered during India's National Gas Hydrate Program Expedition 02 (NGHP-02) are tested in this study. Near in situ effective vertical stress, ∼ 2 MPa, the permeability anisotropy is approximately kh/kv = 1.86 for the “seal core” (from a fine-grained non-reservoir overburden sedimentary section) and kh/kv = 4.24 for the gas hydrate reservoir core with tetrahydrofuran (THF) hydrate saturation Sh = 0.8. Permeability anisotropy increases exponentially with effective vertical stress, as described by kh/kv = α(σv/MPa)β, with α = 1.6, β = 0.22 for seal sediment and α = 3, β = 0.5 for THF hydrate-bearing sediment. Results imply the measured permeability from permeameter tests with vertical flow may underestimate the reservoir's flow performance, which is mainly horizontal (radial) toward a vertical well. Hydrate in sediment increases the gas-entry pressure and residual water saturation, but decreases the water retention curve's shape factor (m), resulting in a steeper curve. Distributions of available pore space sizes for flow in sediment with and without THF hydrate (Sh = 0.8) follow a log-normal distribution. Hydrate formation decreases the apparent mean pore size from ∼10 μm to ∼2 μm, without evidently changing the pore size distribution's standard deviation. Gas hydrate dissociation increases effective permeability and relative permeability to gas.

Authigenic minerals related to wettability and their impacts on oil accumulation in tight sandstone reservoirs: An example from the Lower Cretaceous Quantou Formation in the southern Songliao Basin, China

Oil accumulation, being difficult and complicated, is an important issue in petroleum exploration researches. Authigenic minerals, such as carbonate cements and chlorite, can in certain reservoirs alter the wettability of some pore spaces from water-wet to oil-wet. Generally, these oil-wet pore spaces are favorable for oil accumulation. The alteration of reservoir wettability induced by authigenic minerals and the impacts on oil accumulation in tight sandstone reservoirs were investigated using a suite of mineralogical and geochemical characterization techniques, including thin section observation, SEM-EDS, XRD, QEMSEM, CL, quantitative grain fluorescence (QGF), fluorescence spectral analysis, contact angle measurement and sealed coring oil saturation testing on the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The study shows that the tight sandstone reservoirs are compositionally immature with detrital grains distributed homogeneously. Quartz, carbonates and clay minerals that show heterogeneous distribution characteristics are the major authigenic minerals in some parts of the intergranular pores. The detrital mineral assemblage suggests that the reservoir rocks at deposition and before diagenesis had characterized by strong water-wet properties. With the development of authigenic minerals, carbonate cements and authigenic chlorite tend to alter the wettability of some parts of the existing pore spaces from water-wet to oil-wet. In the K1q4 sandstone reservoirs, oil prefers to accumulate in the cemented residual pore spaces around carbonate cements and chlorite. Reservoirs containing about 4–5% carbonate cements are suggested to be more preferable to oil accumulation. These reservoirs are mainly located between sandstone-mudstone interfaces and central parts of the sand bodies. Chlorites have mainly two effects: on one hand, chlorite alters the wettability of existing pore spaces and provides preferential accumulation sites for oil in the tight sandstone reservoirs, on the other hand it can reduce the adhesion of oil through forming “clay-oil flocs” and promote further migration. Consequently, the reservoirs with moderate amount of carbonate cements or chlorite always show relative high oil saturation in the K1q4 tight sandstones.

Analysis and modeling of fluvial-reservoir petrophysical heterogeneity based on sealed coring wells and their test data, Guantao Formation, Shengli oilfield

The aim of this study is to analyze relationships between lithological heterogeneity and petrophysical properties in fluvial features of the Guantao Formation (Miocene) in view of reservoir water flooding in the Shengli oilfield (Shandong Province, RPC). Black oil simulation models of intermediate scale elements such as point bars and their lateral accretion beds. Using analysis assay data from sealed coring wells demonstrates permeability, rather than porosity, as the determining constraining parameter.The Guantao formation consists of fluvial deposits of braided and meandering river. In the Shengli Oil Field, the target layer of Ng52+3 is mainly composed of well-sorted fine-grain sandstone, and it mainly develops in-channel point bars which are characterized by lateral accretion with graded sand-shale beds showing notable variations in porosity and permeability.Dense well spacing sections were used to identify geometric architectural parameters of the subsurface sandstone interpreted as fluvial point bars. These parameters were used to build the model of the point-bar stratigraphic framework, accurately reflecting the Guantao Formation channel-fill architecture. An exponential function was used to reconstruct the permeability model of intermediate-scale elements and lateral-accretion beds in contrast with models constrained by porosity and shale drapes.Analysis assay data of sealed coring wells indicate that porosity does not display obvious changes in the main body part of point-bar sandstone, and porosity has less obvious correlations with permeability and grain size. The grain size of sandstone exhibits regular variation in intermediate-scale depositional elements and lateral-accretion beds. Vertically, the change of permeability presents exponential functions in the same intermediate-scale element and lateral-accretion bed.Two- and three-dimensional (2-D and 3-D) models and black-oil simulations compare scenarios based on different lithologies, shale drapes, observed grain-size trends, petrophysical properties, and modeling methods. Affected by the shape features of lateral-accretion interfaces, the enrichment areas of remaining oil obviously exhibit morphological characteristics of the echelon. There is little difference in breakthrough time between the “shale drapes” model using porosity as constraint and that using the permeability-distribution function as constraint, but the recovery percentage of the latter model is obviously lower than that of the former. The model in which lateral-accretion beds and units were modeled with the permeability-distribution function as the constraint is about 6% lower than the “shale drapes” model constrained by porosity in recovery percent after 10 years. From the development effect, the injection-production method in which the water-flooding direction is along the dip direction of lateral-accretion surfaces is a little better than that in which the water-flooding direction is opposite to the dip direction of intersurfaces.

An Expert Elicitation of the Proliferation Resistance of Using Small Modular Reactors (SMR) for the Expansion of Civilian Nuclear Systems.

To facilitate the use of nuclear energy globally, small modular reactors (SMRs) may represent a viable alternative or complement to large reactor designs. One potential benefit is that SMRs could allow for more proliferation resistant designs, manufacturing arrangements, and fuel-cycle practices at widespread deployment. However, there is limited work evaluating the proliferation resistance of SMRs, and existing proliferation assessment approaches are not well suited for these novel arrangements. Here, we conduct an expert elicitation of the relative proliferation resistance of scenarios for future nuclear energy deployment driven by Generation III+ light-water reactors, fast reactors, or SMRs. Specifically, we construct the scenarios to investigate relevant technical and institutional features that are postulated to enhance the proliferation resistance of SMRs. The experts do not consistently judge the scenario with SMRs to have greater overall proliferation resistance than scenarios that rely on conventional nuclear energy generation options. Further, the experts disagreed on whether incorporating a long-lifetime sealed core into an SMR design would strengthen or weaken proliferation resistance. However, regardless of the type of reactor, the experts judged that proliferation resistance would be enhanced by improving international safeguards and operating several multinational fuel-cycle facilities rather than supporting many more national facilities.

A New Dynamic Model for Sealed Coring Saturation Correction in Hydrocarbon Reservoir

It is one of the most intuitive methods to analyze the formation of oil and water saturation by sealed coring. But this method is affected by a variety of factors, such as pore volume change, fluid compression, and separation of dissolved gas. In view of the impact of such factors on sealed coring test saturation, there are four kinds of correlation methods currently, namely, comprehensive coefficient correction method, experiment correlation method, mathematical statistics method, and mathematical model correction method, with their own advantages and disadvantages. Based on the analysis of physical change during core lifting process, this paper proposes the mathematical model for dynamic correction of core saturation based on dissolved gas drive filtration theory, multiphase flow fractional flow theory, and corresponding work flow. This method comprehensively considers the impact of relative permeability of three-phase fluid flow, elastic compression nature of fluid and rock, fluid viscosity, volume factor, solution GOR, and other high-pressure PVTs, so it features a wider adaptability, and the accuracy of model correction results satisfies the project requirements. This method provides a reliable basis for the true oil-water saturation of actual reservoir and has an important theoretical and practical significance.

Mineralogical controls on porosity and water chemistry during O2-SO2-CO2 reaction of CO2 storage reservoir and cap-rock core

Reservoir and cap-rock core samples with variable lithology's representative of siliciclastic reservoirs used for CO2 storage have been characterized and reacted at reservoir conditions with an impure CO2 stream and low salinity brine. Cores from a target CO2 storage site in Queensland, Australia were tested. Mineralogical controls on the resulting changes to porosity and water chemistry have been identified. The tested siliciclastic reservoir core samples can be grouped generally into three responses to impure CO2-brine reaction, dependent on mineralogy. The mineralogically clean quartzose reservoir cores had high porosities, with negligible change after reaction, in resolvable porosity or mineralogy, calculated using X-ray micro computed tomography and QEMSCAN. However, strong brine acidification and a high concentration of dissolved sulphate were generated in experiments owing to minimal mineral buffering. Also, the movement of kaolin has the potential to block pore throats and reduce permeability. The reaction of the impure CO2-brine with calcite-cemented cap-rock core samples caused the largest porosity changes after reaction through calcite dissolution; to the extent that one sample developed a connection of open pores that extended into the core sub-plug. This has the potential to both favor injectivity but also affect CO2 migration. The dissolution of calcite caused the buffering of acidity resulting in no significant observable silicate dissolution. Clay-rich cap-rock core samples with minor amounts of carbonate minerals had only small changes after reaction. Created porosity appeared mainly disconnected. Changes were instead associated with decreases in density from Fe-leaching of chlorite or dissolution of minor amounts of carbonates and plagioclase. The interbedded sandstone and shale core also developed increased porosity parallel to bedding through dissolution of carbonates and reactive silicates in the sandy layers. Tight interbedded cap-rocks could be expected to act as baffles to fluids preventing vertical fluid migration. Concentrations of dissolved elements including Ca, Fe, Mn, and Ni increased during reactions of several core samples, with Mn, Mg, Co, and Zn correlated with Ca from cap-rock cores. Precipitation of gypsum, Fe-oxides and clays on seal core samples sequestered dissolved elements including Fe through co-precipitation or adsorption. A conceptual model of impure CO2-water-rock interactions for a siliciclastic reservoir is discussed.