Reservoir Fluid Research Articles

Engineering tribological rehydration of cartilage interfaces: Assessment of potential polyelectrolyte mechanisms

Articular cartilage, primarily composed of water and collagen, is vital for synovial joint function. Traditional hard biomaterials like ceramic or cobalt-chrome used in hemiarthroplasty often result in abnormal contact pressures and premature implant failure. This study investigates the tribological properties of polyelectrolyte functionalised PEEK (SPMK-g-PEEK) in contact with cartilage, proposing a solution to these issues by utilising tribological rehydration and effective aqueous lubrication.We demonstrate a new mode of polyelectrolyte enhanced tribological rehydration where SPMK-g-PEEK achieves low friction and promotes interstitial fluid recovery during sliding, independent of traditional hydrodynamic theories. This results in a rapid stabilisation of the coefficient of friction (CoF) to levels comparable to natural cartilage (CoF ∼ 0.01) and aids in approximately 8% cartilage strain recovery, indicating effective tribological rehydration even under cartilage degradation or altered osmotic conditions.Furthermore, we find that lubrication and rehydration against an SPMK-g-PEEK interface depend minimally on biphasic lubrication but significantly on the hydrophilic sulfonic acid groups of SPMK, which act as a fluid reservoir. Our findings suggest SPMK-g-PEEK as a promising biomaterial for cartilage interfacing implants that offer low friction and modulate cartilage interstitial fluid pressure. This study enhances our understanding of biotribological interactions and contributes to the development of joint replacement materials that support the natural function of cartilage.

Evaluating CO 2 retention risk of geological sequestration sites: physical, time-scale, and site style considerations

With some exceptions, such as fluid phase, pressure evolution, and reservoir geometry, evaluation of CO 2 retention for geological sequestration sites primarily involves well-established seal and trap concepts and methods developed by the petroleum industry. Inputs to a CO 2 retention evaluation (e.g. bed seal capacity analysis) include CO 2 phase, CO 2 and brine density, reservoir pressure and temperature, rock properties, and stress state. The inputs are used to perform capillary and mechanical seal analyses similar to the petroleum industry, but unlike hydrocarbons, CO 2 retention also occurs within the reservoir pore volume by capillary and solubility trapping, adding additional requirement for analyses using reservoir engineering concepts and methodology. Reservoir geometry types for CO 2 storage include conventional traps (depleted hydrocarbon fields, brine-filled traps) and brine-filled reservoirs that lack a conventional trap geometry (e.g. a monocline). Each geometry style and project phase (injection, near-term post-injection, long-term static) requires different retention considerations, for example the CO 2 plume extent and height. Based on a retention evaluation, retention risk and uncertainty may be articulated using a qualitative risk matrix that facilitates early screening, identification of data needs, possible mitigating strategies, and comparisons across a portfolio of potential sites. Thematic collection: This article is part of the Geoscience workflows for CO 2 storage collection available at: https://www.lyellcollection.org/topic/collections/geoscience-workflows-for-CO2-storage

Investigation of Asphaltene Precipitation and Reservoir Damage during CO2 Flooding in High-Pressure, High-Temperature Sandstone Oil Reservoirs

Summary Asphaltenes are heavy aromatic hydrocarbon compounds contained in reservoir fluids and may precipitate when the reservoir pressure is reduced by production or when gas is injected into the reservoir, and then further deposit on pore-throat surfaces causing reservoir damage. At present, the research on asphaltene precipitation and reservoir damage is carried out in conventional reservoirs, and the influence of CO2 injection under high-pressure, high-temperature (HPHT) conditions has not yet been clearly understood. In this work, we combined perturbed-chain statistical association fluid theory (PC-SAFT) calculation, experiments, phase-state simulation, and numerical simulation to predict the asphaltene precipitation with different pressures, temperatures, and amounts of injected gas and to clarify the influence on reservoir permeability and oil production when using CO2 injection. The results show that the precipitation of asphaltenes in the process of CO2 injection is the desorption of colloid-asphaltene inclusions caused by gas molecules and then the mutual polymerization process between dispersed asphaltene molecules. CO2 injection will increase the amount of precipitation and move the precipitation curve to the right side. The degree of permeability reduction caused by the deposition of asphaltenes in the core is 12.87–37.54%; the deposition of asphaltenes in the reservoir is mainly around the injection/production wells and along the injected gas profile. Considering asphaltenes, the oil recovery degree is reduced by 1.5%, and the injection rate is reduced by 17%. The reservoir pressure, temperature, and physical properties have a strong correlation with the degree of reservoir damage, while the initial asphaltene content has a low correlation. This work will be of great interest to operators seeking to enhance oil recovery by CO2 injection in deep reservoirs.

Joint Inversion Method of Nuclear Magnetic Resonance Logging Multiwait Time and Multiecho Time Activation Data and Fluid Identification

Summary Nuclear magnetic resonance (NMR) logging is effective for reservoir evaluation; at present, NMR logging data acquisition parameters are primarily divided into dual wait time (TW) and dual echo time (TE) and then are analyzed, respectively. However, the interpretation results of the two activations are often inconsistent and confuse the identification and quantitative evaluation of reservoir fluids. Based on the principle of multi-TW and -TE activations of NMR logging, the relaxation mechanism is analyzed, and the relationship between the amplitude of the echo train and the pore structure, fluid types, and content of different activations is established. The joint system of the amplitude of echo trains in multiactivations is constructed. Then, the difference spectrum and the oil porosity of the flushed zone can be calculated by the least squares algorithm (LSQR). The fluid-saturated rock model is set, and the numerical simulation of NMR is used to verify the data joint inversion is correct and that the calculation result is more accurate than the previous time domain analysis (TDA) processing method. Moreover, the oil porosity of the flushed zone-deep induction resistivity crossplot is constructed and is also proposed to identify fluid. The above method was applied to the Yanchang Formation in the western Ordos Basin. Based on the joint inversion of NMR multi-TW and -TE logging data in the study area, the methodology yields more precise calculations of fluid volume and saturation compared with conventional approaches. The crossplots derived from these calculations demonstrate high efficacy in identifying fluid types; therefore, the method for fluid identification exhibits potential for practical application and holds considerable value for widespread adoption in the field.

Investigating the effect of salt concentration on oil recovery during guar gum polymer flooding: A simulation study

Reservoirs producing heavy crude oil (gravities <20) pose serious production challenges due to oil's highly viscous nature. The risks of optimizing oil production from these reserves to meet energy demands are more feasible than the financial requirements of venturing into newer fields. Water injection options in such reservoirs substantially affect the oil produced but are limited, especially when the reservoir fluid is more viscous than the injected water. Thermal options for heavy oil reservoirs are often discouraged due to loss of energy and the lighter portion of the hydrocarbon fluids, hence less expensive and environmentally friendlier options such as polymer flooding are encouraged. This study considers polymer injection options and the effects of salt concentrations as it affects heavy oil recovery us. Firstly, 6 wt %’s of Guar Gum (GG) (0.1, 0.2, 0.3, 0.4, 0.5, and 1.0) are diluted in 300 ml of water and the rheological properties estimated from these concentrations are used to build 6 different reservoir models (with an oil density of 20lb/ft3) in conjunction with polymer/salt keywords, rock and fluid properties using the Eclipse black oil model. Two salt concentrations are considered individually for each polymer concentration and a base case of natural production is considered. An oil recovery of 5.90 % (primary production), 30.78 % (water injection), 48.53 %, 48.74 %, 48.78 %, 49.18 %, 49.34 %, and 55.49 % are recorded under polymer flooding. An oil recovery of 55.04 % and 54.60 % is recorded at 5 % wt. and 10 % wt. Salt concentrations during 1 % wt. Polymer flooding. Increasing GG concentration will evidently increase oil recovery due to a higher viscosity index while increasing salt concentrations will reduce oil recoveries.

Quantitative characterization of 3D pore structures and percolation characteristics in bioturbated reservoir media based on X-ray micro-CT: a case study of the Neogene Sanya Formation in the Qiongdongnan Basin, Northern South China Sea

Organisms alter the primary texture of sediments, leading to alteration in petrophysical properties mediated by a textural and mineralogical contrast between burrow-fill and sediment host, which affects reservoir properties and fluid flow characteristics. In this article, in order to understand the microscopic pore structure and flow state of fluids in microscopic pores of bioturbated reservoirs, Ophiomorpha-bearing bioturbated reservoirs in the Neogene Sanya Formation of the Qiongdongnan Basin in the northern South China Sea were selected to research. Micro-CT was applied to scan selected core plugs, and a 3D pore structure model was established. The geometric characteristics of the microscopic pore structure were quantitatively and visually characterized by a modified maximal ball algorithm, and connectivity analysis of the pore structure was carried out. Numerical simulations of the percolation characteristics of the analyzed bioturbated reservoir samples were performed using digital core software (Avizo) and multi-physics field simulation software (Comsol). The results show that: (1) 3D pore structures reveal that pore volume, pore area, pore equivalent radius, throat area, throat equivalent radius and throat length have a large distribution range; among them, the pore volume has the largest distribution range, which can vary by six orders of magnitude, indicating that the pore size distribution of the bioturbated reservoir is uneven and has strong heterogeneous characteristics; (2) the connected pore structure is very complex, and as the equivalent radius of connected pore increases, the coordination number also gradually increases, the better the connectivity. Numerical percolation simulation results also suggested that larger connected pore space plays a key role in the effective permeability of the reservoir. This study has important implications for analyzing the modification effect of bioturbation on oil and gas reservoirs, and enhancing production and recovery in the study area.

EOR simulation of polymer flooding

Enhanced oil recovery (EOR) techniques, such as polymer flooding, have gained significant attention as a means to maximise hydrocarbon extraction from reservoirs. The success of polymer flooding is intricately tied to the complex interplay between fluid properties, reservoir heterogeneity, and injection strategies. It is admitted in classical modelling methodologies, to account for the mobility ratio in polymer flooding by scaling it with the help of the shear rate in situ. The accuracy of shear assessment therefore rules the mobility of oil and the global process efficiency. It is assumed to depend not solely on pore radius, rate, and porosity, but also on a dimensional parameter known as the shape factor, which varies according to the specifications of several authors. When lab measurement is available, it is possible to adjust this value to match the shear rate recorded from a rheometer at feeding stage, ahead of the core. In the present paper the consequence of not performing this stage in the case of a core flood, then in the simulation of a polymer flood pilot is investigated. An alteration of the recovery factor is then expected. The amplitude shall result from the coupling between pore-scale effects and reservoir-scale response, induced by geological constraints such as reservoir layers productivity, aquifer response, and multiphase dynamics. Relative effect and influence on reservoir parameters will be quantified, commented, and discussed.

Investigating phase dynamics of reservoir fluids in CO2 huff-n-puff enhanced oil recovery

This investigation delves into the dynamic phase behavior of reservoir fluids during CO2 huff-n-puff processes, a critical aspect of enhanced oil recovery. Utilizing numerical simulations, the study examines the formation and evolution of four key fluid phase zones, including a miscible-phase oil zone and two flanking miscible-phase condensate gas zones, shedding light on the intricate interactions between CO2 and reservoir fluids. The research methodically addresses the spatial and temporal dynamics of these zones, providing a framework for understanding their evolution. It delves into the complex interplay of fluid properties and phase states, revealing the fundamental role of component migration in influencing phase behavior. This exploration not only uncovers the mechanisms driving fluid dynamics in the CO2 huff-n-puff process but also emphasizes the broader implications for improving oil recovery strategies. By offering a comprehensive view of the factors governing phase behavior, the study contributes to the field's knowledge, suggesting avenues for future research and practical application in enhancing oil recovery efficiency.

Reservoir Simulations of Hydrogen Generation from Natural Gas with CO2 EOR: A Case Study

This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2.

Granitoids of the western Himalaya and Karakoram as potential geothermal reservoirs – A petrological, geochemical and petrophysical study

Hot springs in various granitoid and gneissic complexes in northern Pakistan indicate elevated geothermal gradients, which warrants their evaluation for geothermal applications. Evaluation of such prospects requires extensive knowledge of rock properties and their interaction with reservoir fluids. Our contribution provides first-order information on petrophysical, geochemical, and petrographic descriptions derived from outcrop analogs. About seventy samples of (mostly) granitoids and gneisses from the Nanga Parbat Massif (NPM), the Kohistan-Ladakh Batholith (KLB), and the Karakoram Batholith (KB) were collected. Biotite, K-feldspar, and plagioclase in the granitoid and gneiss show weak to moderate alteration, which increases in shear zones, suggesting fracture-assisted fluid interaction. Geochemical results indicate that the gneisses and granites of the NPM are mostly peraluminous S-type and show enrichment in most LREEs and depletion in HREEs. In addition, depleted Sr and Ba and enriched Rb and U in granites indicate partial melting and high fractionation. On the contrary, granitoids from the KLB are of calc-alkaline I-type and characterized by the depletion of REEs and the enrichment in Ba and Sr. The granitoids of the KB, due to their different magmatic histories, are more diverse, ranging from older I-type calc-alkaline granodiorite, and younger I-type alkaline syenite and S-type calc-alkaline granite. They show an overall enrichment in HREEs along with Ba, Th, Ta, Sr, and Lu. Allanites from syenite of the KB show significant concentrations of Th and U.Petrophysical measurements reveal low matrix porosities (0.6–3.5 %), with primarily average thermal conductivities (1.48–3.37 W m−1K −1) and thermal diffusivities (0.68–1.95 ∙10–6 m2 s−1), with minor variation in specific heat capacities (744–767 J kg−1 K−1). The NPM displays higher average thermal conductivity, thermal diffusivity, and lower porosity than the KB, while the petrophysical properties of the KLB range between these two domains.The geothermal systems in the area operate due to the thickening of a granitoid-dominant crust, which is enriched with radiogenic elements. The fault zones provide channels for meteoric water to access deeply these hot and thermally conductive rocks in the subsurface. After heat exchange, the water is discharged back to the surface as hot springs. The present data set provides a better understanding of regional geothermal regimes from petrological, geochemical, and petrophysical perspectives and assists in numerical modeling for potential geothermal assessment.

Mechanistic analysis of acid gas storage and oil recovery in naturally fractured reservoirs using single matrix block approach

AbstractThe objective of this study is to assess the storage of acid gas, containing CO2 and H2S, in a depleted naturally fractured reservoir (NFR) using single matrix block (SMB) approach. The acid gas dissolution in oil is considered by Peng‐Robinson equation of state and compositional simulation. The PHREEQC package is used to determine acid gas solubility in formation brine. Three types of acid gases with different compositions are used for this study and their swelling behavior and miscibility in relation to the reservoir oil are analyzed. An SMB model, with a matrix block surrounded by fractures, is constructed, and validated for simulation of a real experiment. The simulation is conducted for synthetic and real reservoir fluids when the oil is in its residual saturation. A sensitivity analysis is performed to study the effects of key parameters, such as acid gas composition, reservoir pressure, permeability, porosity and matrix height on the storage capacity and oil recovery factor. The matrix has a volume of 27 m3 and about half of acid gas storage is achieved in the first 5 years while the simulations are run for 30 years. The results show that up to 90% of remained oil is recoverable, and more than 0.67 kmol of acid gas per cubic meter of matrix is stored whether matrix contains a real oil or a synthetic one. Higher storage is achieved for higher matrix porosities and heights and large H2S proportion in acid gas. In all cases about 10% of acid gas is trapped in water and the remaining 90% is dissolved in oil. The mineral trapping was more active in CO2‐rich acid gases. While about 10 kg of the matrix rock was dissolved in the acidic brine when the acid gas contained H2S, the amount of the dissolved minerals in acidic brine resulted from the injection of CO2‐rich acid gas was more than 16 kg. Finally, this study gives a comparative analysis of the storage performance of acid gas mixture and pure CO2. © 2024 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

Reservoir fluid identification based on multi-head attention with UMAP

Gas logging curves obtained during drilling, along with conventional well logs, typically serve as foundational data for identifying reservoir fluids. Traditional methods for identifying layers containing oil or gas often suffer from limitations such as inadequate feature extraction, underutilization of differences in data points, and limited applicability. These limitations lead to reduced accuracy in predicting reservoir fluid segmentation. To address the challenge of spatiotemporal feature extraction in logging curves, this paper presents a fluid identification method based on deep learning networks and multivariate sequence classification. The method takes into account both the sequential variations in geological strata and the relationships among different curves for fluid prediction. Our proposed method utilizes a Transformer multi-head attention mechanism and follows a series of steps. First, an improved Symbolic Aggregate approXimation (SAX) is employed to assess the response characteristics of the logging curves to the target fluid and identify sensitive curves based on information similarity. Subsequently, the semi-supervised learning method UMAP is applied to identify layers with high interpretability. Hierarchical training is then employed to mitigate the impact of noise and high-dimensional nonlinearity on identification results. Finally, the processed vector curves are input into the attention module layer, where features of each layer are extracted in an encoding-decoding manner. This method has been tested and validated using gas logging data from 12 wells in a gas field offshore China. The overall prediction accuracy can exceed 94%, and the prediction accuracy for a single gas layer is over 88%. When compared to other machine learning approaches, such as K-means, decision tree, and XGBoost, this method exhibits superior identification accuracy and generalization ability, especially for unbalanced samples.

Optimizing Recovery of Fracturing Fluid in Unconventional and Tight Gas Reservoirs Through Innovative Environmentally Friendly Flowback Additives

Hydraulic fracturing, a method used to stimulate oil and gas from shale and tight formations, faces challenges like fluid blockage and fast declining oil or gas production rates due to the significant impact of capillary forces on water retention. To address this, surfactants and microemulsions are commonly employed as flowback additives to reduce surface and interfacial tension, enhancing water recovery during hydraulic fracturing. The effectiveness of flowback additives is highly impacted by harsh subsurface conditions, such as high salinity and high temperature. This study aims to assess the performance and effectiveness of methylimidazolium chloride-based ionic liquids as flowback additives at high salinities and temperatures.Different experimental analysis were conducted to screen different concentrations of methylimidazolium chloride-based ionic liquids (X1, X2, and X3). Surface tension measurements were conducted to estimate the critical micelles concentrations. A spinning drop tensiometer (SDT) was utilized to measure interfacial tension, in addition, contact angle measurements were used to evaluate the impact of the flowback additive on the wettability and the displacing behavior. Seawater was used as the base fracturing fluid with a salinity of 57,000 ppm and temperatures up to 90°c for all experiments. Coreflood experiments were conducted using tight formations to evaluate the regained hydrocarbon permeability and the fracturing fluid recovery in the presence of flowback additives.Various formulations, with surface tension values ranging from 30 to 45 mN/m and CMC values between 0.5 and 1 gallon per thousand units (gpt), were examined. The lowest interfacial tension value, notably 3 mN/m, was achieved with the X3 formulation. Ionic liquids demonstrated favorable surface tension reduction, where longer carbon chains led to lower values. Introducing diverse ions, especially divalent ions, enhanced the performance of ionic liquids. Interfacial tension measurements indicated a significant reduction with the addition of X3 to both 5 wt% KCl and the fracturing base fluid. Contact angle measurements revealed a shift towards greater water-wettability after treating the rock with flowback additives. Moreover, the use of ionic liquids improved permeability by 25%, enhancing fluid recovery to around 56%.According to our results, methylimidazolium chloride-based ionic liquids can be used as environmentally friendly flowback additives, especially in harsh conditions of high temperature and high salinity where the conventional additives are not suitable. This will contribute to the development of more sustainable and environmentally conscious practices in hydraulic fracturing operations. Ultimately, the utilization of these additives can help mitigate water blockage, reduce formation damage, and enhance shale gas production.

Impact of Fluid Distribution and Petrophysics on Geophysical Signatures of CO2 Storage Sandstone Reservoirs

AbstractCarbon Capture and Storage (CCS) is a key element to achieving net‐zero energy challenge timely. CCS operations require the integration of geophysical data, such as seismic and electromagnetic surveys, numerical reservoir models and fluid flow simulations. However, the 10–100s m resolution of seismic imaging methods complicates the mapping of smaller scale rock heterogeneities, while borehole measurements commonly show large fluctuations at sub‐cm scales. In this study, we combine laboratory data, well‐logging, rock physics theories and a proof‐of‐concept time‐lapse seismic modeling to assess the effect of pore‐scale fluid distribution and petrophysical heterogeneities on the expected performance of whole‐reservoir CCS operations in deep saline aquifers, by analogy to the Aurora CCS site, North Sea. We monitored the elastic and electrical properties of three sandstone samples with slightly different physical and petrographic properties during carbon dioxide (CO2) flow‐through tests under equivalent in situ effective pressure. We inferred the CO2‐induced damage in the rocks from the variations of their hydromechanical properties. We found that the clay fraction, CO2‐clay chemical interactions, and porosity were the main factors affecting both the CO2 distribution in the samples and the hydromechanical response. We used seismic modeling of well‐log data and the laboratory results to estimate the reservoir‐scale time‐lapse seismic response to CO2 injection and to assess the effect of the rock heterogeneities in our interpretation. The results show that disregarding the effect of rock heterogeneities on the CO2‐brine fluids distribution can lead to significant misinterpretations of seismic monitoring surveys during CCS operations in terms of both CO2 quantification and distribution.

A Review on the Application of Nanofluids in Enhanced Oil Recovery

Abstract: Oil mobility has been a significant issue since the recovery of a heavy crude reservoir. It is determined by two factors: oil rheological properties and penetrability. Nanofluids (NFs) are a distinct class of engineered fluids characterized by the dispersion of nanoparticles ranging in size from 1 to 100 nanometers (nm) into a working fluid. They are divided into groups based on physicochemical characteristics, including nanoparticle morphology, and thermal and rheological properties. The well-known nanofluids composed of metal (e.g., ZrO2) and ceramic (e.g., SiO2) had the best physicochemical performance in terms of oil mobility. This chapter examines the inundation of metal and nonmetal based nanofluids as a new enhanced oil extraction (EOR) method for extracting primary and secondary oil from more than 45% of confined reservoir fluids. Furthermore, new developments in the utilization of these materials on EOR approaches to combat significant interfacial adhesion across sandstone and fluid interfaces are summarized.

Acoustic vibration restoration of rock permeability while crude oil filtration containing paraffins

The paper presents the results of experimental studies on the filtration of a reservoir fluid (crude oil containing paraffins) through sedimentary rocks under the influence of acoustic vibrations in an ultrasound band. A laboratory rig is assembled that allows for modeling the filtration of a fluid from a reservoir into a well during the propagation of elastic waves from a well. Medium permeability sandstones are the focus of the study. The effect of acoustic vibrations manifests itself in unblocking the pore space and leads to restoration of rock permeability to different extents. Dependences of rock permeability on the frequency of acoustic vibrations are obtained. A model of the influence of acoustic vibrations on paraffin particles is developed.

Preparation and performance evaluation of microencapsulated acid used for gel breaking of fracturing fluid in low-temperature reservoirs

In low-temperature reservoirs, the generation of free radicals by oxidizing breakers is challenging, and the alkaline fracturing fluid generally inhibits enzyme’s activity, making it difficult to break down the fracturing fluid. Previous studies have demonstrated that acids can consume borate ions and disrupt crosslinking nodes even at low temperatures, thereby efficiently breaking gels. Thus, microencapsulated oxalic acid (OA) was prepared via a coacervation method, using ethyl cellulose (EC) or acrylonitrile–butadiene–styrene (ABS) as shell materials with varying initiator viscosities and core–shell ratios. An optimal microcapsule MC[OA/ABS-2000-1:2] was determined based on the coating effect, productivity, encapsulation rate, and release performance. The test results of FT-IR and TGA together proved that the optimal microcapsule was composed of 24.4 and 74.8 % of OA and ABS, respectively. Scanning electron microscopy and laser particle size analysis were employed to characterize the optimal microcapsule with an average particle size of 402.8 μm, which exhibited a high degree of sphericity. Because of their porous shells, these microcapsules exhibited sustained slow-release characteristics. Evaluations conducted at temperatures of 30 and 50 ℃, simulating the tight sandstone reservoir conditions in the Ordos basin, revealed that delayed gel breaking could be achieved within approximately 2.5 h at low temperatures by adding only 0.25 % of the optimal microcapsule. Furthermore, increasing the temperature and dosage of microcapsules resulted in shorter breaking times. Additionally, a synergistic breaking effect was observed between the enzymes and the prepared microencapsulated acid. Thus, by optimizing the microcapsule dosage based on the reservoir temperature and fracturing construction pumping time, employing the two breakers together can achieve delayed and complete gel breaking at the desired time. In conclusion, the microencapsulated acid prepared in this study has significant potential as a gel breaker for fracturing fluids in low-temperature reservoirs.

Method for assessing well interference at under-gas cap zone using CRM material balance model

Optimization of injection operation conditions is a primary task when designing the development of mature oil fields. To select optimal injectivities, solutions to the optimization problem based on a CRM (capacitance resistance model) analytical model are used. CRM models based on analytical solutions of the material balance equations of weakly compressible fluids due to their speed can be used as an alternative to flow simulation models in solving a number of problems to support oil field development. The main task of CRM models is to determine the well interference factor, i.e. the share of fluid produced due to a particular injection well. These factors can be used to analyze waterflooding and develop solutions for waterflood optimization. At the same time, in some cases reservoir fluids may have high gas content, which is a classical limitation of a CRM model and leads to underestimation of the interference factors when estimating the injection performance. In this paper, the authors propose an approach to solve the problems of distortion of such factors, and for the first time in CRM application practice a model has been adapted for use in the conditions of high GORs and has a potential for being applied for under-gas cap zones. This is achieved by including in the equations the physical properties of gas and their behavior under reservoir conditions. The complication of algorithms did not significantly affect the model run time, but allowed to match the model both separately and jointly for liquid and gas phases. Thus, the improved classical CRM model has significantly expanded the scope of application of operational waterflood analysis tools for assessing the current situation. No less complicated and urgent is the problem of forecasting the production of gas liberated in the conditions of the previously mentioned under-gas-cap zones, because it implies the need to estimate the future reservoir pressure. The authors intend to devote the next paper to finding a solution to this issue, taking into account the proposed new method of reservoir pressure estimation using a CRM model.

A Method to Identify Pore Fluids in Heterogeneous Conglomerate Reservoirs Using a Nuclear Magnetic Resonance Log with Oil-Based Mud Invasion

Summary Nuclear magnetic resonance (NMR) logging has been extensively utilized for identifying pore fluids in recent years. However, after oil-based mud (OBM) invasion, OBM filtrate partially takes the place of the original fluid in the reservoir and the morphology of the NMR T2 (transverse relaxation time) spectrum changes. OBM invasion makes it difficult to identify the formation fluid using routine NMR fluid identification methods. In this study, we took heterogeneous conglomerate formation in the northwestern Junggar Basin as a case study and carried out core experiments under four conditions (viz., water-saturated, OBM displacing water, oil-saturated, and OBM displacing oil) and simulated the states of OBM invasion into water and hydrocarbon-bearing formation. Comparative analysis finds that when the OBM invades the water layer, the movable peak of the T2 spectrum primarily reflects the bulk relaxation characteristics of OBM filtrate, whereas when the OBM invades into the oil layer, the T2 spectrum may exhibit a three-peak distribution, where the first peak mainly indicates irreducible water, the second peak reflects OBM filtrate, and the third peak primarily reflects nondisplaced oil. To facilitate fluid identification, two T2 cutoffs are adopted to divide the T2 spectrum into three segments, and combined with the T2 geometric average, a fluid identification factor (ifluid) is proposed. Finally, identification criteria for reservoir type are established on the NMR logging and drillstem test data. The field application verifies the reliability of the proposed methods. These methods realize the identification of oil layers under OBM drilling and guide the subsequent production and development of oil reservoirs.

Scleral lens induced short term corneal changes in eyes with Pellucid Marginal Degeneration

PurposeTo investigate the short-term effect of scleral lens (SL) on corneal curvature and corneal oedema in Pellucid Marginal Degeneration (PMD) eyes. MethodsCorneal anterior, posterior curvature and corneal thickness were measured in 14 eyes of 14 PMD participants with Schiempflug imaging at different corneal diameters and meridians at baseline and after 6 h of SL wear. ResultsThere was a significant flattening (up to 0.26 mm) of the anterior corneal curvature noted in the inferotemporal quadrant (from 210 to 255 degree at 2 mm, 8 mm and 10 mm corneal diameter), inferonasal quadrant (from 285 to 345 degree at 6 mm and 8 mm corneal diameter), and inferiorly at 2 mm and 10 mm corneal diameter (p < 0.05). Similarly, posterior corneal curvature showed statistically significant steepening mostly in inferotemporal quadrants (from 195 to 255 degree from 4 mm to 8 mm corneal diameter) and inferonasally at 2 mm and 4 mm corneal diameter (p < 0.05). A statistically significant increase in the corneal thickness noted in different corneal diameters with corneal oedema ranging from 2.10 % to 4.00 % after 6 h of SL wear. A gradual increase in corneal oedema was noted form centre to periphery. The baseline central fluid reservoir thickness (FRT) was 341.07 ± 139.8 which reduced to 276.71 ± 114.32 µm after 6 h of lens wear. No significant correlation was noted between corneal oedema with different parameters like initial and final FRT, change in anterior and posterior corneal curvature, and lens thickness (p > 0.05). ConclusionsShort-term SL wear induced a clinically acceptable range of corneal oedema. A clinically significant flattening in anterior curvature and minimal steepening in posterior curvature were noted. Practitioners should be careful while measuring corneal parameters in PMD eyes wearing SL, as these alterations can provide false impression of disease progression.