Reservoir History Research Articles

Of rats and children: plague, malaria, and the early history of disease reservoirs (1898–1930)

This article’s jumping-off point is the highly incisive but often-ignored claim by the French doctor, Louis-Jacques Tanon, in 1922 that rats acted as plague reservoirs in Paris; in other words, that they harboured the plague bacillus but were refractory to it. This claim partially reframed the fight against this disease in the French capital in the 1920s, which became more centred on surveilling the plague reservoir rather than on destroying rats. Drawing upon Tanon’s hypothesis, this article explores the emergence, evolution, and several iterations of the idea of disease reservoirs in the early twentieth century. On the one hand, it describes the crafting of a range of ideas with which Tanon was directly or indirectly dialoguing, namely, that rats could present a stage called chronic plague, which was especially developed in India; and that human populations, especially children, acted as sources or reservoirs of malaria in Sierra Leone and Algeria. On the other hand, this article shows how Tanon created original reasoning by combining and reformulating some of these ideas and applying them to Paris. Thus, this article contributes to the early history of reasoning in terms of disease reservoirs, as well as presenting a more dynamic history of microbiology by showing how concepts crafted in the “Rest” found their place in Europe.

Deformation and fluid flow history of a fractured basement hydrocarbon reservoir below the Sab'atayn Basin, Habban Field, Yemen

Fractured crystalline basement reservoirs are of increasing economic interest for oil and gas exploration and subsurface fluid storage. The successful characterization of these reservoirs is commonly challenged by their structural heterogeneity, complexity in fracture distribution and flow properties at multiple scales, and the difficulty of imaging fractures in exploration seismic. We analyzed the fracture geometry and fracture diagenetic attributes in two oriented cores from the Habban Field in the Late Jurassic Sab'atayn Basin (Yemen) to evaluate the multi-phase deformation history and fracture flow pathway evolution for (hydrothermal) fluids and hydrocarbons. Analyses included petrographic and fluid inclusion analysis of fracture-filling cements, and stable sulfur isotope analyses of fracture-filling pyrite.The Paleoproterozoic basement consists of amphibolite-facies metamorphic ortho- and paragneiss cut by several phases of Neoproterozoic granitoid intrusions. The investigated lithologies in the drill cores comprise (1) epidote quartzite, (2) amphibolite, (3) monzogranite, (4) meta-arkose, and (5) quartz-feldspar porphyry. These lithologies show an inhomogeneous fracture network that is partially cemented. Ediacaran brittle-ductile deformation (D1) recognized only within a Pan-African monzogranite lead to cataclasis and porosity generating alteration. Late Jurassic – Early Cretaceous extension (D2) related to the break-up of Gondwanaland and the formation of the Sab'atayn Basin is found in all lithologies and likely resulted in pervasive quartz cementation. Late Jurassic fractures parallel to the NW-SE trending long axis of the Sab'atayn Basin are best recognized in a strongly foliated amphibolites. Cenozoic extensional fracturing (D3) reactivated older structures, which probably formed during activity of the Neoproterozoic Najd Fault System and caused multi-phased (pyrite-(saddle) dolomite-calcite) fracture cementations. The sulfur isotope compositions of pyrite with δ34S values ranging between −17.4 and + 26.4‰ vs. V-CDT reflects the variability of the fluid source during sulphide mineral formation from hydrocarbon-rich hydrothermal solutions. Fluid inclusions indicate that cementation reactions occurred in a relatively narrow temperature field between 120 °C and 140 °C, ideal for hydrocarbon maturation. Our results demonstrate the potentially complex charge history of basement reservoirs, involving multiple phases of fracture formation and cementation, and fluid charge episodes.

History Matching Reservoir Models With Many Objective Bayesian Optimization

ABSTRACTReservoir models for predicting subsurface fluid and rock behaviors can now include upwards of billions (and potentially trillions) of grid cells and are pushing the limits of computational resources. History matching, where models are updated to match existing historical data more closely, is conducted to reduce the number of simulation runs and is one of the primary time‐consuming tasks. As models get larger the number of parameters to match increases, and the number of objective functions increases, and traditional methods start to reach their limitations. To solve this, we propose the use of Bayesian optimization (BO) in a hybrid cloud framework. BO iteratively searches for an optimal solution in the simulations campaign through the refinement of a set of priors initialized with a set of simulation results. The current simulation platform implements grid management and a suite of linear solvers to perform the simulation on large scale distributed‐memory systems. Our early results using the hybrid cloud implementation shown here are encouraging on tasks requiring over 100 objective functions, and we propose integrating BO as a built‐in module to efficiently iterate to find an optimal history match of production data in a single package platform. This paper reports on the development of the hybrid cloud BO based history matching framework and the initial results of the application to reservoir history matching.

Benzocarbazole and methylxanthone molecular migration tracers unravel migration routes and filling history of Veslefrikk, Oseberg-East and Brage reservoirs in the Norwegian North Sea

Identification of petroleum migration routes and reservoir filling processes is feasible by applying carbazoles or xanthones as molecular migration tracers. To verify their utility, a well-constrained migration route was chosen for this study: the petroleum migration along the Veslefrikk and Oseberg East fields until reaching the Statfjord Formation compartment within the Brage field in the Norwegian North Sea. This migration route comprises an ideal test case because the oil is sourced from the same kitchen area, yielding very similar oil families in all three fields, and because the maturity remains within the main oil window, below 0.9 Ro % vitrinite reflectance equivalence.Different methodologies applied by two laboratories, from sample preparation to analytical methods, yielded identical results of migration direction and route using the benzocarbazole ratio ([a]/([a]+[c]), thus underlining practicability and robustness of this molecular migration parameter. The benzocarbazole ratio (BCR) in this study was neither affected by source rock facies, and/or biodegradation. A thermal maturity effect on BCR is considered here to be of only subordinate impact whereas it substantially affects benzocarbazole concentrations. The BCR declined from values of 0.68 at onset of migration to 0.42 at end of migration, whereby the absolute concentrations of benzocarbazoles in parallel declined by a factor of 10, from 5000 to 500 ng/g oil. The distribution and concentration of methylxanthones evolved comparable to that of benzocarbazoles. The methylxanthones ratios (MXR) from onset of migration until reaching the Brage field declined from a value of 0.85 to 0.42. The benzocarbazoles and methylxanthones, like other geo/biomarkers, preferentially reflect the first charge of the most polar and least mature oil delivered upon petroleum migration and could help to understand the reservoir filling history.Migrating oils derived from the Sogn Graben kitchen entered the Veslefrikk oil field first and continued until the structure was filled to spill point. Thereafter, migration continued to the Oseberg East oil field and after reaching spill point there it continued to the Brage field and its Statfjord formation compartment. The complex migration route represents a classical fill to spill scenario and benzocarbazole fractionation upon migration delineates the initial filling trends. The maturity values of crude oils are in the mid-oil window and show trends of covariance with the molecular migration indicators, thus proving to be supporting tracers in a classical fill to spill scenario, where maturity values are lowest when migration distances are greatest. This is due to the first expelled oil being of lowest thermal maturity entering the nearest reservoir first and then being displaced into farther reservoirs along the migration route upon arrival of later oil (more mature) charges.

Mechanisms of Waterflood Inefficiency: Analysis of Geological, Petrophysical and Reservoir History, a Field Case Study of FWU (East Section)

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field.

Analysis on Vertical Variation Characteristics of Eogene Formation Water in Jizhong Depression

Jizhong Depression is located in the middle and west of Bohai Basin. During the Tertiary period, the depression was in a relatively stable state, and the shape of the depression did not change much, but the internal ups and downs of the depression were still continuous. In the Tertiary period, it experienced three development stages: early division, middle communication and late contraction, and three different sedimentary facies appeared accordingly. At the same time, it also caused three shifts of sedimentary centers. In the medium-term communication stage, two large water invasion periods occurred, and in some areas, the sedimentary water medium changed from salty to light twice. Oil and gas in the depression are associated with formation water, and the formation history of formation water is closely related to the formation history of oil and gas reservoirs. They are both in a hydrodynamic system and exchange material components for a long time. The lower tertiary is the main oil-bearing interval in central Hebei, but it is affected by the late tectonic movement and its structural characteristics are complex. Therefore, the hydrochemistry and vertical distribution characteristics of tertiary strata are studied. By effectively studying the distribution characteristics of formation water, it is concluded that the salinity of formation water in the basin tends to increase from edge to center and from shallow to deep, mainly in alternate blocking zones and alternate stagnation zones. The water deposition environment is relatively stable and the general regularity is obvious, which is an effective means to study the migration and distribution of oil and gas.

Assisted Upscaling of Miscible CO2-Enhanced Oil Recovery Floods Using an Artificial Neural Network-Based Optimisation Algorithm

Due to the high computing cost of the fine-scale compositional simulations needed to effectively model miscible CO2 flooding, upscaling techniques are needed to approximate the behaviour of these fine-scale grids on more realistic coarse-scale models. The use of transport coefficients to better represent small-scale interactions, such as the time-dependent flux of the components within the hydrocarbon phases (molecular diffusion), and the pseudoisation of relative permeabilities to ensure the matching of large-scale effects, such as the volumetric fluxes of the phases, are two of these procedures. Most times, a mismatch between the phase fluxes of the integrated fine-scale and that of the coarse-scale is observed. By adjusting or calibrating some of the generated coarse-scale pseudo functions, such as the transport coefficients, absolute permeability, or relative permeability endpoints, the accuracy of the upscaling results can be improved. This procedure can be treated a reservoir history matching problem which is typically computationally expensive. In this study, we provide a framework for representing the dynamics of small-scale molecular diffusion and macro-scale heterogeneity-induced channelling related to miscible CO2 displacements on upscaled coarser grid reservoir models. The method used was based on the pseudoisation of relative permeability and transport coefficients and was applied to two benchmark reservoir models from the Society of Petroleum Engineers (SPE). Our results demonstrated that using effectively calibrated transport coefficients improved the upscaling results, so that the calculated pseudo-relative permeability functions can be ignored. We proposed a unique approach to upscaling miscible floods that utilised a genetic algorithm and a neural-network-based proxy model to minimise the associated computing cost. The data-driven approximation model considerably decreased the computing cost associated with the assisted tuning technique, and the optimisation algorithm was used to reduce the error between the predictions of the upscaled models. In conclusion, the methodology described in this study effectively captured the small- and large-scale behaviour related to the miscible displacements on upscaled coarse-scale reservoir models while reduced associated computational costs.

Iterative ensemble smoothing scheme for reservoir history matching with unknown observation error covariance

Ensemble-based smoothers are well-known data assimilation tools in reservoir applications, including history matching and geophysical inversion. They entail the knowledge of the covariance of observation errors, which, however, is often poorly known in real applications and commonly estimated subjectively on the basis of a diagonal structure. This neglects the correlations within the observation errors, which may deteriorate the quality of the model estimates. Herein, we relaxed the independent observational error assumption by considering a nondiagonal structure for the covariance. Given that all the elements in the covariance matrix could not be estimated given a limited amount of data, which is typically the case in practice, we reduced the number of degrees of freedom by parameterizing this covariance with two scalar parameters, one for error variance and the other for error correlation length–scale. We then estimated these parameters together with the model variables using a hybrid algorithm that combined a variational Bayesian approach with particle filters and an ensemble-based smoother. The proposed approach was validated with a linear Gaussian model and a nonlinear reservoir flow model. The results clearly demonstrate the potential of the proposed method in effectively addressing the uncertainty of observations in the history-matching process.

Formation mechanisms and resource potential of carbonate geothermal reservoirs in the Beijing-Tianjin-Hebei plain

Investigating the formation mechanisms of carbonate geothermal reservoirs is of theoretical and practical significance for summarizing the formation pattern of geothermal resources and further guiding their effective exploitation. The Beijing-Tianjin-Hebei Plain (BTHP), predominantly located within the Jizhong Depression and Cangxian Uplift in the Bohai Bay Basin, serves as the primary region for geothermal exploitation and utilization in China. More than 1500 geothermal wells have been drilled therein, with water temperature at the wellhead ranging from 55 to 110 °C, single-well flow rate ranging between 80 and 120 m3/h, and cumulative heating area exceeding 100 × 106 m3. However, the exploration and research in the region remain limited overall. As per the previous geothermal and petroleum exploration results and the latest geothermal drilling data, this study comprehensively evaluated the geothermal resources of karst geothermal reservoirs. The results show that two suites of carbonate karst reservoirs, namely the Jxw Formation and the Ordovician strata, have primarily developed in the BTHP, and their formation and evolution can be divided into four stages: the Mesoproterozoic-Early Paleozoic stage with carbonate sedimentation and the development of interlayer karst, the Late Paleozoic stage with the development of direct sedimentary cover, the Mesozoic stage with compressional uplifting and development of buried hill karst, and the Cenozoic stage with regional cover deposition and the modification and finalization of karst geothermal reservoirs. Accordingly, the porosity evolution history of the geothermal reservoirs is composed of three stages, namely a significant decrease followed by a minor increase, a gradual decline, and then a small fluctuation from increase to decrease before slowly rising again. The karstification in geothermal reservoirs can be summarized into quasi-syngenetic karstification, epigenetic karstification, and burial karstification, which can be subdivided into seven subcategories. The carbonate geothermal reservoirs in the study area boast total geothermal resources of 53.821 × 109 GJ, or 184.155 × 109 t of standard coal equivalent (tce), and the annual exploitable geothermal resources in the urban area can heat an area of (400‒500) × 106 m3, indicating great potential of geothermal exploitation.

Formation and diagenesis of authigenic silicates in the Late Paleozoic alkaline lake deposits, Junggar Basin, NW China

Authigenic silicates are typical minerals of alkaline lake deposits. Their mineral composition and lateral distribution can be used for reconstructing paleoclimates, paleoenvironments, and diagenetic subsidence histories of hydrocarbon reservoirs. In particular the examples of pre-Mesozoic alkaline lake deposits were widely missing in the literature. To unveil this, a basin-wide high-resolution mineralogical investigation is conducted on the Late Paleozoic volcanic-related alkaline lake deposit of the Fengcheng Formation in the NW Junggar Basin, NW China. The investigated Late Paleozoic shales mainly contain stable silicates like K-feldspar, albite and reedmergnerite. Laterally, the authigenic silicates are mostly distributed in the lake-central and transitional zones and are especially abundant in organic-rich shales. Authigenic K-feldspar and albite were mainly formed by replacing detrital clay minerals and K-feldspar or directly precipitating from alkaline porewaters. Reedmergnerite was later formed by replacing acid-sensitive carbonate or feldspar minerals when organic matter was mature. Organic matter thermal maturation and hydrocarbon generation helped lower porewater pH and periodically open diagenetic systems. These processes facilitated fluid migration and element exchanges and promoted the transformation of thermodynamically unstable silicates and acid-sensitive carbonates to more stable silicates and quartz. A main result of this study is thus to emphasize the control of organic matter diagenesis and temperature on authigenic silicate evolution. This model can help revisit the genesis of the dominant felsic shales in alkaline lake deposits.

High-precision zircon age spectra record the dynamics and evolution of large open-system silicic magma reservoirs

The emplacement history and thermal evolution of subvolcanic magma reservoirs determine their longevity, size, and ability to feed volcanic eruptions. As zircon saturation is dependent on melt temperature and composition, quantitative analysis of zircon age distributions provides insight into the timing and magnitude of intensive parameter variations during the lifetime of a magma reservoir. Here we present chemical abrasion-isotope dilution-thermal ionization mass spectrometry (CA-ID-TIMS) U-Pb zircon crystallization ages and in-situ zircon trace-element geochemistry for a suite of caldera-related, coeval plutonic and volcanic units of the Permian Sesia Magmatic System (northern Italy). This dataset documents the protracted growth and evolution (∼1 Myr) of a voluminous (>1000 km3), upper crustal (3.5–2.0 kbar) silicic magma reservoir. Systematic changes in zircon composition with time reveal episodic intrusions of new magma into a single, progressively differentiating reservoir which was dominantly kept at high crystallinity conditions (>60 vol.%). The volcanic and plutonic units both show dispersed and heterogeneous CA-ID-TIMS age distributions. A stochastic, thermodynamics-based zircon saturation model accounting for fractional crystallization, recharge and thermal rejuvenation effects on zircon growth and stability in a rhyolitic magma body reproduces the observed distributions of zircon U-Pb ages. Model results suggest that zircon compositional variability and crystallization age heterogeneity, characteristic of the Sesia and other large silicic systems, distinguish open- and closed-system magmatic processes. Specifically, an increase of the mass of crystallized zircons over time is the hallmark of thermally and chemically mature magma reservoirs, capable of producing voluminous eruptions upon changes in the thermal and mechanical state of the system. Conversely, a decrease in crystallized zircon mass over time characterizes systems where crystallization dominates over magma mobility, hindering substantial mass release during eruptive events. We suggest that quantitative analyses of dispersed zircon crystallization age distributions obtained with high-precision techniques can be applied to the plutonic and volcanic record to identify mature silicic magma reservoirs whose properties and storage conditions allowed for catastrophic caldera-forming eruptions. This work provides the petrologic community with a new tool to investigate the genesis and evolution of zircon-bearing intermediate to silicic intrusive magmatism and caldera-forming volcanism through time and across tectonic settings.

A Novel Method for Calculating Diffusion Coefficient of Shale Gas Reservoirs: A Case Study of Longmaxi Formation in Weiyuan Area, Sichuan Basin, China

The entire process of shale gas generation, migration, and accumulation involves the diffusion of shale gas, and it is impossible to disregard the harm that gas diffusion does to gas reservoirs. The research object for this paper is the Longmaxi Formation shale gas reservoir in the Weiyuan area of the Sichuan Basin. Based on Fick’s diffusion law, an innovative mathematical model of shale gas diffusion is established, and it is clarified that the diffusion amount mainly depends on the free gas content and the diffusion coefficient. Based on the theory of fluid dynamics, the calculation equation of formation paleo-pressure is innovatively deduced. The equation fully considers gas migration, temperature and pressure changes, and the pressure control effect of organic matter gas generation, and restores the evolution history of free gas content in the reservoir. The evolution process of temperature, pressure and stratigraphic physical properties in the study area is the first to calculate the diffusion evolution history and cumulative diffusion amount of shale gas reservoirs in the study area, the reliability of the calculation results is verified by geochemical parameters. Studies have revealed that the existing Longmaxi Formation shale in the Weiyuan area of Sichuan Basin varies from 14.10 to 16.50 × 104 m3/m2 per unit area, with an average diffusion loss of 0.30 × 1012 m3 gas in the positive part and 0.30 × 1012 m3 in the negative part. The total lost gas accounts for around 1.72 times the present recappable reserves and is estimated to be 0.43 × 1012 m3 in volume. It is clear that the migration and accumulation of natural gas are significantly influenced by the research of diffusion loss.

Burial and Denudation Alter Microbial Life at the Bottom of the Hypo‐Critical Zone

AbstractHow subsurface microbial life changed at the bottom of the kilometers‐deep (hypo) Critical Zone in response to evolving surface conditions over geologic time is an open question. This study investigates the burial and exhumation, biodegradation, and fluid circulation history of hydrocarbon reservoirs across the Colorado Plateau as a window into the hypo‐Critical Zone. Hydrocarbon reservoirs, in the Paradox and Uinta basins, were deeply buried starting ca. 100 to 60 Ma, reaching temperatures >80–140°C, likely sterilizing microbial communities present since the deposition of sediments. High salinities associated with evaporites may have further limited microbial activity. Upward migration of hydrocarbons from shale source rocks into shallower reservoirs during maximum burial set the stage for microbial re‐introduction by creating organic‐rich “hot spots.” Denudation related to the incision of the Colorado River over the past few million years brought reservoirs closer to the surface under cooler temperatures, enhanced deep meteoric water circulation and flushing of saline fluids, and likely re‐inoculated more permeable sediments up to several km depth. Modern‐ to paleo‐hydrocarbon reservoirs show molecular and isotopic evidence of anaerobic oxidation of hydrocarbons coupled to bacterial sulfate reduction in areas with relatively high SO4‐fluxes. Anaerobic oil biodegradation rates are high enough to explain the removal of at least some portion of postulated “supergiant oil fields” across the Colorado Plateau by microbial activity over the past several million years. Results from this study help constrain the lower limits of the hypo‐Critical Zone and how it evolved over geologic time, in response to changing geologic, hydrologic, and biologic forcings.

Studying the Effect of Permeability Prediction on Reservoir History Matching by Using Artificial Intelligence and Flow Zone Indicator Methods

The map of permeability distribution in the reservoirs is considered one of the most essential steps of the geologic model building due to its governing the fluid flow through the reservoir which makes it the most influential parameter on the history matching than other parameters. For that, it is the most petrophysical properties that are tuned during the history matching. Unfortunately, the prediction of the relationship between static petrophysics (porosity) and dynamic petrophysics (permeability) from conventional wells logs has a sophisticated problem to solve by conventional statistical methods for heterogeneous formations. For that, this paper examines the ability and performance of the artificial intelligence method in permeability prediction and compared its results with the flow zone indicator methods for a carbonate heterogeneous Iraqi formation. The methodology of the research can be Summarized by permeability was estimated by using two methods: Flow zone indicator and Artificial intelligence, two reservoir models are built, where the difference between them is in permeability method estimation, and the simulation run will be conducted on both of the models, and the permeability estimation methods will be examined by comparing their effect on the model history matching. The results showed that the model with permeability predicted by using artificial intelligence matched the observed data for different reservoir responses more accurately than the model with permeability predicted by the flow zone indicator method. That conclusion is represented by good matching between observed data and simulated results for all reservoir responses such for the artificial intelligence model than the flow zone indicator model.

Better use of experience from other reservoirs for accurate production forecasting by learn-to-learn method

To assess whether a development strategy will be profitable enough, production forecasting is a crucial and difficult step in the process. The development history of other reservoirs in the same class tends to be studied to make predictions accurate. However, the permeability field, well patterns, and development regime must all be similar for two reservoirs to be considered in the same class. This results in very few available experiences from other reservoirs even though there is a lot of historical information on numerous reservoirs because it is difficult to find such similar reservoirs. This paper proposes a learn-to-learn method, which can better utilize a vast amount of historical data from various reservoirs. Intuitively, the proposed method first learns how to learn samples before directly learning rules in samples. Technically, by utilizing gradients from networks with independent parameters and copied structure in each class of reservoirs, the proposed network obtains the optimal shared initial parameters which are regarded as transferable information across different classes. Based on that, the network is able to predict future production indices for the target reservoir by only training with very limited samples collected from reservoirs in the same class. Two cases further demonstrate its superiority in accuracy to other widely-used network methods.

The Archaeology and History of Rock-cut Cisterns and Open Water Reservoirs in the Negev Highlands

The Archaeology and History of Rock-cut Cisterns and Open Water Reservoirs in the Negev Highlands

Reservoir automatic history matching: Methods, challenges, and future directions

Reservoir history matching refers to the process of continuously adjusting the parameters of the reservoir model, so that its dynamic response will match the historical observation data, which is a prerequisite for making forecasts based on the reservoir model. With the development of optimization theory and machine learning algorithms, automatic history matching has made numerous breakthroughs for practical applications. In this perspective, the existing automatic history matching methods are summarized and divided into model-driven and surrogate-driven history matching methods according to whether the reservoir simulator needs to be run during the automatic history matching process. Then, the basic principles of these methods and their limitations in practical applications are outlined. Finally, the future trends of reservoir automatic history matching are discussed. Cited as: Liu, P., Zhang, K., Yao, J. Reservoir automatic history matching: Methods, challenges, and future directions. Advances in Geo-Energy Research, 2023, 7(2): 136-140. https://doi.org/10.46690/ager.2023.02.07

Fully automated microfluidic mixing aided in-line detection of trace level oil field tracers

Recent development in oil field tracer technologies has been focused on implementations that increase oil recovery through optimized algorithms for production, aided by the addition of high fidelity interwell tracer data that improve reservoir history match. Prerequisites for successful tracer campaigns in oil reservoirs at a large scale not only include low-cost tracer materials with a rich palette of uniquely identifiable tracers, but also high sensitivity, easy-to-use trace-level detection and analysis methodologies. A fully automated in-line separation and detection protocol can simultaneously address challenges in throughput (speed and efficiencies) and accuracy (minimization of error-prone steps) of multi-tracer detection. Our previously reported tracer materials consist of barcoded variants of the dipicolinic acid (DPA) molecules that sensitize the emission of lanthanide ions. We have capitalized on the time-gated optical luminescence detectability of this sensitizer-lanthanide ion complex to reject background oil fluorescence, achieving high detection sensitivity in particularly complex oil field produced brine matrix. However, automation of the detection and analysis process has been hindered by opposing requirements in the integration of chromatography instrumentation (separation resolution) with in-line mixing (dispersion due to increase in residence time), and high sensitivity spectrofluorimetry (long integration time). We overcome this major barrier to implementing an in-line detection design under flow conditions by utilizing a microfluidic mixing chip which offers a high degree of mixing in a very short fluidic path length for the in-flow chelation of lanthanide ion to the chromatographically resolved tracer variants, and a flow-cell fluorescence detector at the output of the high-performance liquid chromatography (HPLC). In this study, we demonstrated the rapid in-line detection of a mixture of three different DPA-based barcoded tracers at ultra-trace level. An automated solid phase extraction (SPE) pre-concentration stage is added to the input of the HPLC, further lowering the detection limit down to a level of 100 pM (pico molar) of tracer molecules. As developed, the complete automated system offers unprecedented sensitivity of detection and accelerated oil field tracer analysis that approaches “near real-time” speed.

Mechanical formation damage control in permeability Biot’s effective stress-sensitive oil reservoirs with source/sink term

Geomechanical effects monitoring on reservoir rock and fluid properties response during the oil production curve are essential to improve oil recovery in a petroleum field. Incorporating geomechanics to flow models become the mathematical formulation regarding well-test and reservoir engineering more realistic because geomechanical parameters, e.g., in situ and overburden stress, as well as Biot’s coefficient, play a fundamental role in pressure response. Hence, permeability stress-sensitive oil reservoirs are the scope of various research in the petroleum industry for minimizing formation damage during drilling, completion, and stimulation operations. In this context, mechanical formation damage control plays a key role in preventing early-permeability loss that may result in reservoir compaction and oil field disinvestments. This work develops a new analytical solution for the nonlinear hydraulic diffusivity equation (NHDE) with instantaneous point-source/sink effects in permeability effective stress-sensitive oil reservoirs. The proposed model considers Biot’s effective stress change in the permeability response, and a new deviation factor is derived from comparing the nonlinear effect concerning the constant permeability classical solution and a decoupled case available in the literature. The calibration methodology is performed using a numerical simulator named IMEX®, widely used in formation evaluation works, and the results presented high convergence. The findings of this study allowed us to notice the role of overburden stress, oil flow rate, deviation factor, and Biot’s coefficient in permeability change during production in the diagnostic plots. Thereby, the modeling developed in this paper becomes a useful and attractive tool for predicting and monitoring permeability loss, oil flow rate specification, and reservoir history matching.

Pore and fracture characteristics of Cretaceous tight reservoir and its control effect on hydrocarbon accumulation in the Liuhe Basin

Tight oil and gas in the Cretaceous has been found in the Liuhe Basin, but the rules of tight reservoir and oil and gas accumulation are not clear. This paper discusses the developmental characteristics and evolution law of pores and fractures in the Cretaceous tight reservoir in the Liuhe Basin, and reveals its controlling effect on tight oil and gas accumulation. The results show that intercrystalline pores, intergranular pores and dissolution pores are scattered and only developed in shallow tight reservoirs, while microfractures are developed in both shallow and deep layers, which are the main type of reservoir space in the study area. The results of mercury intrusion porosimetry and nitrogen gas adsorption show that with the increase of depth, the proportion of macropores (microcracks) increases, while the proportion of micropores decreases. There are two stages of microfractures developed in the study area, corresponding to the initial fault depression stage from late Jurassic to early late Cretaceous and compressional uplift at the end of late Cretaceous. According to the principle of “inversion and back-stripping method”, combined with the data of optical microscopy and inclusions, the time of each key diagenesis and its contribution to porosity are revealed, and the porosity evolution history of reservoirs in different diagenetic stages is quantitatively restored. The porosity reduction rate of compaction can reach more than 80%, which is the main reason for reservoir densification. The relationship between pore evolution history and oil and gas accumulation history reveals that during the oil and gas filling period of the Xiahuapidianzi Formation (90–85 Ma), the reservoir porosity is only 1.15%, but the development of microfractures in the first stage of the reservoir is conducive to oil and gas accumulation.