Reservoir Response Research Articles

Enhanced antiviral immunity and dampened inflammation in llama lymph nodes upon MERS-CoV sensing: bridging innate and adaptive cellular immune responses in camelid reservoirs.

Middle East respiratory syndrome coronavirus (MERS-CoV) infection can cause fatal pulmonary inflammatory disease in humans. Contrarily, camelids and bats are the main reservoir hosts, tolerant for MERS-CoV replication without suffering clinical disease. Here, we isolated cervical lymph node (LN) cells from MERS-CoV convalescent llamas and pulsed them with two different viral strains (clades B and C). Viral replication was not supported in LN, but a cellular immune response was mounted. Reminiscent Th1 responses (IFN-γ, IL-2, IL-12) were elicited upon MERS-CoV sensing, accompanied by a marked and transient peak of antiviral responses (type I IFNs, IFN-λ3, ISGs, PRRs and TFs). Importantly, expression of inflammatory cytokines (TNF-α, IL-1β, IL-6, IL-8) or inflammasome components (NLRP3, CASP1, PYCARD) was dampened. The role of IFN-λ3 to counterbalance inflammatory processes and bridge innate and adaptive immune responses in camelid species is discussed. Our findings shed light into key mechanisms on how reservoir species control MERS-CoV in the absence of clinical disease.

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.

Experimental study on interlayer interference effect of CBM commingled production in a multi-pressure system under output control mode

This research adopted the self-developed test device to conduct tests to understand the interlayer interference in a multi-pressure system under output control mode. It analyzed the reservoir response and gas production characteristics in coalbed methane (CBM)'s commingled production and discussed the interlayer interference mechanism. The results revealed that the CBM's commingled production at the initial stage would generate interlayer interference under the output control mode, causing the cross-fluids of interlayer fluids. The interlayer interference would form a gas-production state. That is, the gas production of reservoirs with high fluid energy would inhibit that of the reservoirs with low fluid energy. When the gas production of reservoirs with high fluid energy is attenuated, that of reservoirs with low fluid energy would start recovering to maintain stable production. The reservoir pressure gradients positively influence interlayer interference. The more significant the difference between the reservoir's fluid energies aggravates, the more severe this interlayer interference. The output control values negatively affect the interlayer interference, as their increase would weaken the severity of interlayer interference. Therefore, the output control design should appropriately increase the output value or rationally select the reservoirs with a slighter difference in fluid energies. The gas model can be divided into three: conventional type, inhibitory type, and reverse-flow type, and their production stage can be divided into five different phases: gas rise, gas inhibition, reverse flow, gas recovery, and gas attenuation.

Understanding the fluxes of greenhouse gases in reservoirs under the inspiration of Margalef

Reservoirs are significant sources of greenhouse gases (GHG), such as carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O), to the atmosphere. These systems receive and metabolize a larger amount of organic and inorganic carbon and nitrogen from their watersheds than lakes, resulting in the production of CO2, CH4 and N2O. Despite their global relevance, there are still important uncertainties regarding the magnitude, variability and drivers of their emissions that undermine global estimates. Therefore, a comprehensive understanding of the origin of these emissions is required. Here, I investigate the fluxes of CO2, CH4 and N2O and their concentrations in the water column of twelve Mediterranean reservoirs during the stratification and mixing periods to discern the main pathways involved in their production and the spatial and seasonal variability among these gases and their emissions and radiative forcing. Finally, I provide a theorical framework to understand GHG emissions as a response of reservoirs to eutrophication and external forcing. I integrate Margalef’s ideas about how eutrophication perturbs the biogeochemistry of inland waters with the main findings of my previous work to analyze how the C, N and P inputs from reservoir watersheds modify the biogeochemical cycling of C, N, P and O, and determine the production and emission of CO2, CH4, and N2O. This perturbation effect is especially notable for CH4, and N2O emissions, which increase significantly in eutrophic waters, even exceeding the climate forcing of CO2. Therefore, emission of GHG should be seen as part of the reservoir response to the external forcing that displaces a fraction of the materials to the atmospheric boundary.

Response of clastic reservoir to magmatic intrusion: Advances and prospects

Exploration practice shows that magmatism-affected clastic reservoirs have potential in oil and gas exploration, but it lacks systematic understanding of the effect of magmatic intrusion on the surrounding clastic rocks. This paper shows that the influence range of magmatic intrusion into clastic reservoirs is positively correlated with the size of magmatic body. The influencing factors mainly include compressive deformation, high temperature, and hydrothermal activity. Magmatic intrusion into clastic reservoirs not only produce physical fractures or dissolve pores, but also lead to mineral precipitation to deteriorate the reservoir space. The vertical and horizontal migration of hydrothermal fluids complicate the distribution of reservoir space and induce reservoir heterogeneity. We further explore: 1) magmatic-hydrothermal information in clastic reservoirs through the analysis of fracture-related veins at different locations in the surrounding reservoirs and, 2) modification effects of magmatic intrusion in clastic reservoirs constrained by geothermometers and anomalous temperature fields. With the guidance of theories and previous studies, we can carry out research using key techniques such as SILLi heat transfer modeling and carbonate U–Pb dating. We aim to develop a comprehensive quantitative model for evaluating the thermal response of clastic reservoirs to magmatic intrusion, and revealing the co-evolution of temperature, thermal convection response and porosity of reservoir modification effect.

Numerical Simulation of Carbon Oxygen Ratio Logging Response in Natural Gas Hydrate Reservoirs

In the process of oil and gas field development, in order to identify the gas hydrate reservoir more accurately, we try to use the carbon oxygen ratio spectrum logging technology to study the log response law of this reservoir, and compare it with the reservoir response law to better guide the oil field production. Firstly, the theoretical response law of carbon and oxygen concentration ratio of natural gas hydrate reservoir and oil layer is deduced according to the petrophysical model, and then the response law of carbon and oxygen concentration ratio of two types of reservoirs simulated by Monte Carlo numerical simulation is studied, and the similarity law and difference between the two types of reservoirs are summarized. The results show that the carbon oxygen ratio has a regular change relationship with the porosity and saturation of the reservoir. The carbon oxygen ratio can be used to preliminarily distinguish and qualitatively identify the two types of reservoirs.

Prediction of Permian karst reservoirs in the Yuanba gas field, northern Sichuan Basin, China

Karst reservoir has great hydrocarbon potential, however karst reservoir prediction is inhibited by the strong lateral and vertical heterogeneity of karstification which in turn results in recognition difficulty when geological and geophysical methods are used in isolation. Combined geological and geophysical methods, including core observation, thin section analysis, well log interpretation, seismic attributes and seismic inversion are applied to understand the depositional environment, types of karstification, the geophysical response and distribution of karst reservoir and the controls over and evolution model of karst reservoir in Permian Yuanba gas field, northern Sichuan Basin. The results show that there are four types of major seismic facies recognized in the study area, which correspond to platform margin reef, carbonate platform, platform margin inter-bay and platform margin slope. Karstification can be divided into three zones: the supergene karst zone, the vertical seepage zone and the horizontal underflow zone, among which the supergene karst zone have the strongest karstification. Karstification is highlighted with low seismic impedance, low Poisson's ratio, and high seismic attenuation on seismic inversion as well as micro scale paleo geomorphology recognized by trend surface analysis. By comparing the distribution of karstification with paleo geomorphology, fault distribution and gas contents, it can be observed that the karstification have a good matching relationship with these factors. The dominant type of karstification is epigenic karst, which is strongly influenced by depositional facies and paleo geomorphology. Fracture networks have contributed to karstification but are not the dominant factor of karst formation. The integration of geological and geophysical methods can predict karst reservoir with high accuracy within large area and can be applied to karst reservoir hydrocarbon exploration of similar geological setting.

A 3D modeling study of effects of heterogeneity on system responses in methane hydrate reservoirs with horizontal well depressurization

Production tests in marine methane-bearing sediments have been carried out worldwide. Pilot horizontal well tests have exhibited the potential of using horizontal well depressurization for methane hydrate production. Many studies have focused on the 2D thermal-hydraulic-mechanical-chemical (THMC) responses induced by horizontal wells, which targeted certain vertical planes penetrating the well, while 3D numerical modeling of the associated heat and mass transfer behaviors and induced geomechanical responses can provide behaviors not captured by 2D modeling. Additionally, it can give elaborated results in heterogeneous cases. This study investigates the effects of heterogeneity caused by interlayers on the coupled THMC behaviors in a 3D domain depressurized by a horizontal wellbore. Full geomechanics is considered in the model. The model is verified against a widely used benchmark problem. Numerical results show that, due to the nature of 3D fluid flow induced by depressurization, flow patterns in vertical and horizontal directions are different, which leads to the phenomenon that the system response patterns captured by 3D THMC modeling are different from those in 2D THMC modeling. 2D THMC modeling may simplify the coupled THMC system response with the presence of horizontal wells. Also, the system response is mainly governed by the thickness of hydrate-free interlayers in heterogeneous cases. The effect of heterogeneity on pressure is observed in all investigated locations while its effect on temperature and displacement is only observed in planes penetrating the wellbore. The negative impact of heterogeneity on methane production is magnified by thicker hydrate-free interlayers.

Effects of temperature and pressure on the wave responses of deep carbonate reservoirs

AbstractDeep carbonate reservoirs are subject to in-situ conditions of high temperature and high pressure. We consider six water-saturated dolomite specimens from these reservoirs and perform ultrasonic experiments to obtain the P- and S-wave waveforms and velocities under different pressure and temperature conditions. The P-wave attenuation is estimated using the spectral-ratio method. The results show that with the increase of temperature, the velocities slightly decrease and attenuation increases. At effective pressures <40 MPa, the P-wave velocities increase sharply with pressure and then approximately linearly at higher pressures, while attenuation decreases gradually with pressure. The crack porosity as a function of pressure is obtained from the experimental data. The P-wave velocities decrease with this porosity while attenuation shows an opposite behavior. Then, a multiscale poroelasticity model considering micro-, meso- and macro-scale fluid-flow mechanisms is proposed to analyze the effects of the fluid properties, temperature and crack content on the wave responses. The model results agree well with the experimental data at different pressures, which provides a theoretical basis for the analysis of broadband wave velocity dispersion and attenuation phenomena of carbonate reservoirs and underground porous media in general.

Automated Reservoir Model Calibration Applied to a Complex Multizone Heavy Oil Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210185, “Automated Reservoir Model Calibration for Field-Development-Plan Evaluation Under Subsurface Uncertainty Applied to a Complex Multizone Heavy Oil Field,” by Luis D. Mendoza, Atahualpa J. Villarroel, SPE, and Maria F. Hurtado, Schlumberger, et al. The paper has not been peer reviewed. _ Fully integrated reservoir modeling for field-development optimization under subsurface uncertainty has been a major challenge so far for Rubiales, a major heavy oil field in Colombia with original oil in place of greater than 5 billion STB. An automated reservoir characterization work flow was developed to generate multiple history-matched models on the field and well level. The developed methodology and work flow successfully delivered field-development evaluation under subsurface uncertainty. The work-flow design is applicable for other fields with similar characteristics and delivery objectives. Introduction The Rubiales field is in the southeast of Puerto Gaitán, approximately 310 km from Bogotá. It is the most important oil field in Colombia in terms of extension, original volumes, and production but also is one of the country’s most complex fields, with a variety of technical challenges. Lithologically, the field is an unconsolidated sandstone reservoir with stratigraphic complexity that includes a high degree of vertical and lateral heterogeneity. Additionally, it has an infinite aquifer with tilted oil/water contact (OWC) in combination with high permeability. The produced fluid is a heavy oil (15 °API) with high water cut (approximately 95%). The current field-development plan (FDP) is based on horizontal wells as infill drilling to maintain oil production levels. A solution was designed to be tested in a specific area of the field implementing digital integration technologies. This solution included the capture of geological heterogeneities in terms of lateral and vertical continuity of the sand bodies. This digital methodology allows understanding seal and OWC effects on water production using a high-resolution model combined with an automated calibration process based on actual production as evidence. Work-Flow Design History Matching. In this project, a typical assisted history-matching process was run initially that included sensitivity and uncertainty analyses followed by an optimization algorithm. Once the sensitivity analysis was complete, the most-influential parameters were identified. Then, some variables were disabled and the uncertainty process was run with a Monte Carlo sampling considering only those parameters considered significant for the objective response. Through this process, a case ensemble with a wide-spectrum result was obtained. The next step was to focus on the optimization that was designed to improve the objective function value that should be minimized by tuning the set of input parameters remaining as active influencers. An evolutionary algorithm was implemented for the optimization that operated with three phases. In the first phase, simulation cases were distributed randomly in the search region, providing an initial ensemble. During the second phase, the better simulation cases were retained and the average objective function value was reduced. In the final phase, only the best simulation cases survived. Even when a modern algorithm was applied, the matching results were not sufficient at the well level. However, this work flow provided a good base case and insights regarding reservoir response, which are the inputs for the next stage of history matching. The further development of the history-matching methodology is detailed in the complete paper.

Utilizing 2D seismic forward modeling to constrain the seismic response and plane distribution of grain shoal reservoir in the northern slope of Central Sichuan Paleo-uplift, Sichuan Basin

Carbonate grain shoal reservoirs are well developed in the first member of the Longwangmiao Formation on the northern slope of the Central Sichuan Paleo-uplift. Influenced by the stratal thickness, reservoir heterogeneity, and development patterns, it is difficult to predict reservoirs by using the seismic data present. In this contribution, multiple sets of seismic models were established, and then the seismic forward modeling method was used to constrain the seismic response of the reservoirs. The results show: (1) When reservoirs are not developed in the Longwangmiao Formation, the top interface of the Longwangmiao Formation corresponds to 1/8 λ above the central lobe of the wave peak while the bottom interface corresponds to the central lobe of the wave trough; (2) If a single set of reservoirs is developed in the first member of the Longwangmiao Formation, the waveform of the top interface will be constant, but the bottom trough will shift upward and the frequency will decrease. Additionally, the scale of trough upward movement and frequency reduction is negatively correlated with reservoir velocity and positively correlated with reservoir thickness. (3) If multiple sets of reservoirs are developed in the first member of the Longwangmiao Formation, the waveforms of the top and bottom interface are consistent with that of a single reservoir which has the same total thickness. Similarly, the corresponding relationship between the wave trough variation and reservoir velocity or thickness remains constant. (4) When reservoirs are both developed in the first and second members of the Longwangmiao Formation, the top and bottom waveforms will vary regularly with the difference in reservoir velocity between them. If the reservoir velocity in the first member is less than that of the second member, the top peak is constant while the bottom trough shifts upward, and the frequency decreases. On the contrary, if the reservoir velocity in the second member is lower than that of the first member, the bottom trough is constant while the top peak moves downward, and the frequency increases. Finally, using the waveform clustering method, the reservoir is divided into three grades, namely high-, medium-, and poor-quality. Among them, high-quality reservoirs are mainly distributed in the southeast and northeast of the study area which is the key area for oil and gas exploration in the next step.

Experimental and numerical investigation of sandstone deformation under cycling loading relevant for underground energy storage

Considering the storage capacity and already existing infrastructures, underground porous reservoirs are highly suitable to store green energy, for example, in the form of green gases such as hydrogen and compressed air. Depending on the energy demand and supply, the energy-rich fluids are injected and produced, which induces cyclic change of state-of-the-stress in the reservoir and its surrounding. Detailed analyses of the geo-mechanical deformations under variable storage conditions i.e., storage frequency and fluid fluctuating pressures, are crucially important for safe and efficient operations. The present work presents an integrated analysis, based on experimental and constitutive modeling aspects, to investigate sandstones’ geomechanical response to cyclic loading relevant to underground energy storage (UES). To this end, sandstone rock samples were subjected to cyclic loading above and below the onset of dilatant cracking under different frequencies and loading amplitudes. Axial strains and Acoustic Emissions (AE) were measured in both regimes to quantify the total deformation (strain) of the rock and its AE characteristics. It is found that the inelastic strain and number of AE events is the highest in the first cycle and reduce subsequently cycle after cycle. Moreover, cyclic inelastic deformations are affected by the mean stress, amplitude, and frequency of the stress waveform. On the one hand, the higher the mean stress and the amplitude, the higher the total inelastic strains. On the other hand, the lower the frequency, the higher the total inelastic strain. From the modeling perspectives, five types of deformation mechanisms were identified based on the governing physics: elastic, viscoelastic, compaction-based cyclic inelastic, inelastic brittle creep, and dilatation-based inelastic deformation. To model elastic, viscoelastic, and brittle creep, the Nishihara model was used. A cyclic modified cam clay model (MCC) and hardening–softening model were applied to capture plastic deformation. The results show a very good fit of the constitutive model with the experimental results, which could help in studying the response of reservoirs to injection and production.

Response in coal reservoirs and in-situ stress control during horizontal well coal cavern completion and stress release

Widely developed tectonically-deformed coal (TDC) blocks the recovery of coalbed methane (CBM). Horizontal well cavern completion and stress release (HWCCSR) is expected to extract TDC in-situ CBM efficiently. Systematic investigations on reservoir response during stress release are essential for evaluating stress-relief performances and guiding engineering practices. However, the dynamic-controllable cavern enlargement and the influence of high stress and intense tectonic stress were mainly ignored in previous work. Additionally, the mechanism of permeability variation remained unclear under complex stress surroundings. In this work, the geological-engineering numerical model of coal cavern completion was constructed, and the equivalent method was adopted to investigate the dynamic HWCCSR. The stress, plastic deformation, and permeability responses were analyzed, and the impact of in-situ stress on reservoir response was discussed. The mechanism and model of permeability changes under complex stress were revealed.The results showed that the equivalent method could imitate the dynamic-controllable enlarging of the cavern properly with easy operation and good convergence. The reservoir responded significantly during the HWCCSR. With increasing cavern diameter (Dc), the plastic deformation zone (PDZ) increased, permeability could be expanded to 1–105 times the initial value, and the effective permeability increase zone (EPIZ) was linear with Dc. Laboratory and field data confirmed the rationality of simulation results. High vertical principal stress and significant lateral stress coefficient were conducive to generating more complex PDZ and larger EPIZ and enhancing more considerable permeability in TDC reservoirs due to more energy and a strong damage-deformation trend. Four models of permeability variation and possible division of permeability distribution were proposed according to the integrated control of elastic-plastic deformation, stress difference, and volume stress. Stress difference was the direct reason for coal plastic deformed-failure. Plastic deformed-failure coupled with volume stress-relief could significantly increase permeability. Plastic deformed-failure and volume stress concentration might cause a permeability decrease. Coal elastic deformation with volume stress concentration might induce a similar outcome. Additionally, elastic deformation coupled with volume stress-relief might enhance permeability and expand the EPIZ under tectonic stress conditions. In conclusion, larger caverns had better stress-relief performance, expected to attain a high recovery of coalbed methane. The HWCCSR was suitable for recovering TDC in-situ CBM in areas with intense tectonic stress and large burial depths. This work confirmed the feasibility of efficient recovery of TDC in-situ CBM through HWCCSR. It provided basics for evaluating reservoir responses to stress-relief and selecting layers.

Estimating Sustainable Long-Term Fluid Disposal Rates in the Alberta Basin

Reliable regional-scale permeability data and minimum sustained injectivity rate estimates are key parameters required to mitigate economic risk in the site selection, design, and development of commercial-scale carbon sequestration projects, but are seldom available. We used extensive publicly available disposal well data from over 4000 disposal wells to assess and history-match regional permeability estimates and provide the frequency distribution for disposal well injection rates in each of 66 disposal formations in the Alberta Basin. We then used core data and laboratory analyses from over 3000 cores to construct 3D geological, geomechanical and petrophysical models for 22 of these disposal formations. We subsequently used these models and the history-matched regional permeability estimates to conduct coupled geomechanical and reservoir simulation modeling (using the ResFrac™, Palo Alto, CA, USA, numerical simulator) to assess: (i) well performance in each formation when injecting carbon dioxide for a 20-year period; (ii) carbon dioxide saturation and reservoir response at the end of the 20-year injection period; (iii) reliability of our simulated rates compared to an actual commercial sequestration project. We found that: (i) the injection rate from our simulations closely matched actual performance of the commercial case; (ii) only 7 of the 22 disposal formations analyzed appeared capable of supporting carbon dioxide injectors operating at greater than 200,000 tons per year/well; (iii) three of these formations could support injectors operating at rates comparable to the successful commercial-scale case; (iv) carbon dioxide presence and a formation pressure increase of at least 25% above pre-injection pressure can be expected at the boundaries of the (12 km × 12 km) model domain at the end of 20 years of injection.

Experimental study on sand production and coupling response of silty hydrate reservoir with different contents of fine clay during depressurization

To further understand the characteristics of clay and sand production (hereafter collectively referred to as sand production) and to provide optimization designs of sand control schemes are critical for gas production from clayey silt natural gas hydrate reservoirs in the South China Sea. Thus-, gas-water-sand production behavoirs and coupling reservoir subsidence characteristics before, during, and after hydrate dissociation of the clayey silt hydrate reservoirs with different clay contents (5%, 10%, 15%, 20%, 25%, and 30%) have been studied through a self-developed experimental system. The results show that with the increase of clay content, the total mass of sand production first increases and then decreases, and it reaches maximum when the clayey content is 20%. The sand production is the lowest before hydrate dissociation and increases significantly during hydrate dissociation, which mainly occurs in the high-speed gas and water production stage at the beginning of hydrate dissociation. After hydrate dissociation, the sand production decreases significantly. During the whole depressurization process, the clay and free sand particles generally move to the sand outlet due to the fluid driving force and overlying stress extrusion. However, for conditions of high clay contents, those particles fail to pass through the sand control screen and gradually accumulate and block the screen by forming a mud cake, which greatly reduce the permeability of the screen and limite sand production as well as gas and water production. Our research lays a foundation for sand production prediction and sand control scheme selection during gas recovery from clayey silty hydrate reservoirs that greatly need to consider a balance between sand control and gas productivity.

Reflectivity Cross Plot of Modified Zoeppritz Equation

Beside the complexities and not readily practical applications resulting from the full Zoeppritz equation, the seismic amplitude reflection does not give enough information beyond the critical angle. Consequently, there are breakdown of the Zoeppritz equation approximations at angle of incidence beyond (Shuey’s approximation). More so, the validity is only for slight contrast in elastic parameters across the formations and small angle of incidence is assumed. In an attempt to address these inaccuracies and enhance understanding of seismic reservoir responses and prediction of fluid and lithology, a modified form of the Zoeppritz equation is derived using relations between elastic constants and velocities in terms of Pseudo Poisson’ ratio reflectivity, rigidity reflectivity, density reflectivity in linearized forms devoid of the complexities associated with the original Zoeppritz equation with practical applications in hydrocarbon exploration, exploitation and production. These properties are lithology and fluid discriminators. The modified Zoeppritz equation was analyzed using well data from oil field in a sedimentary basin, onshore of Niger Delta area. Reflectivity crossplot was carried out and comparison with the exact and other approximations was done to validate the derived equation. The results showed that the modified equation can be applied in exploration beyond the critical angle than the shuey’s and Aki & Richards’ approximations especially for deep targets and wide angle acquisition for accurate estimation of intercept and gradient attributes. The modified Zoeppritz equation in this study gives higher accuracy at far offset than the two foremost approximations.

Experimental Study of Complex Resistivity Characteristics of a Sandstone Reservoir under Different Measurement Conditions

Due to the variability of fluid properties and saturation of reservoirs, large differences in formation temperature and pressure, and the diversity of rock and mineral compositions, the petrophysical response of reservoirs is often complex. This study explored a new method of reservoir fluid identification and evaluation based on the complex resistivity response characteristics of sandstone reservoirs under different measurement conditions. The complex resistivity of the five sandstone samples was measured under normal temperature and pressure and variable pressure, temperature, and formation conditions and under different oil saturations. Furthermore, the reservoir was comprehensively analyzed and evaluated based on the mineral composition, porosity, and permeability parameters. The results show that the resistivity of the sandstone increases logarithmically with pressure and oil saturation but decreases logarithmically with temperature and depth. The polarizability decreases slightly with increasing pressure and increases slightly with increasing temperature. With increasing depth, the polarizability decreases obviously, and with increasing oil saturation, the polarizability decreases moderately. Under different measurement conditions, the complex resistivity data for the sandstone reservoir and the IP parameters extracted through inversion are regular. The results of this study provide a new method for the identification and evaluation of complex reservoir fluids and have important reference value.

The dual laterolog response of fractured-vuggy reservoirs based on conductivity tensor and Maxwell–Garnett mixing rule

Dual laterologs measure reservoir resistivity at deep and shallow depths around a wellbore, a thorough understanding of the dual laterolog response of fractured-vuggy reservoirs is key for reservoir identification and saturation evaluation. The joint development of the fracture and vugs complicates the laterolog response of fractured-vuggy reservoirs. In this study, the conductivity model of the dipping anisotropic structure on the horizontal plane was analyzed according to the theory of the conductivity tensor. Then, based on the Maxwell–Garnett mixing rule, a conductivity model of the vuggy reservoirs was established. On this basis, the dual lateral conductivity model of fractured-vuggy reservoirs was established by equating the vuggy reservoir to the matrix and the dipping anisotropic structure plane to the fracture plane. Furthermore, based on the dual lateral conductivity model and physical experiments, the dual laterolog responses with respect to the fracture dip angle, fracture porosity, and vug porosity were systematically analyzed. The study revealed that (1) the fracture dip angle significantly affects the separation of the dual laterolog. In other words, at a low dip angle, the fracture shows a negative separation of the dual laterolog, whereas a positive separation at a high dip angle; (2) for vuggy reservoirs, the development of vugs decreases the deep and shallow laterologs, and the more the vugs developed, the greater the decrease; (3) for fractured-vuggy reservoirs, the dual laterolog response is mainly controlled by fractures. The development of vugs did not change the negative or positive separation of dual laterologs with different fracture dip angles.

History-Matching and Forecasting Production Rate and Bottomhole Pressure Data Using an Enhanced Physics-Based Data-Driven Simulator

Summary In this study, we present a novel application of our newly developed physics-based data-driven interwell numerical simulator (INSIM) referred to as INSIM-BHP to history match highly variable real-life (oscillatory) oil rate and bottomhole pressure (BHP) data acquired daily in multiperforated wells produced from an oil reservoir with bottomwater drive mechanism. INSIM-BHP provides rapid and accurate computation of well rates and BHPs for history matching, forecasting, and production optimization purposes. It delivers precise BHP calculations under the influence of a limited aquifer drive mechanism. Our new version represents the physics of two-phase oil-water flow more authentically by incorporating a harmonic-mean transmissibility computation protocol and including an arithmetic-mean gravity term in the pressure equation. As the specific data set considered in this study contains a sequence of highly variable oil rate and BHP data, the data density requires INSIM-BHP to take smaller than usual timesteps and places a strain on the ensemble-smoother multiple data assimilation (ES-MDA) history-matching algorithm, which utilizes INSIM-BHP as the forward model. Another new feature of our simulator is the use of time-variant well indices and skin factors within the simulator’s well model to account for the effects of well events on reservoir responses such as scaling, sand production, and matrix acidizing. Another novel modification has been made to the wellhead term calculation to better mimic the physics of flow in the wellbore when the production rate is low, or the well(s) is(are) shut in. We compare the accuracy of the history-matched oil rate and BHP data and forecasted results as well as computational efficiency for history matching and future prediction by INSIM-BHP with those from a high-fidelity commercial reservoir simulator. Results show that INSIM-BHP yields accurate forecasting of wells' oil rates and BHPs on a daily level even under the influence of oscillatory rate schedules and changing operational conditions reflected as skin effects at the wells. Besides, it can help diagnose abnormal BHP measurements within simulation runs. Computational costs incurred by INSIM-BHP and a high-fidelity commercial simulator are evaluated for the real data set investigated in this paper. It has been observed that our physics-based, data-driven simulator is about two orders of magnitude faster than a conventional high-fidelity reservoir simulator for a single forward simulation. The specific field application results demonstrate that INSIM-BHP has great potential to be a rapid approximate capability for history matching and forecasting workflow in the investigated limited-volume aquifer-driven development.

Geochemical reactions altering the mineralogical and multiscale pore characteristics of uranium-bearing reservoirs during CO2 + O2in situ leaching

CO2 + O2in situ leaching has been extensively applied in uranium recovery in sandstone-type uranium deposits of China. The geochemical processes impact and constrain the leaching reaction and leaching solution migration; thus, it is necessary to study the CO2 + O2–water–rock geochemical reaction process and its influence on the physical properties of uranium-bearing reservoirs. In this work, a CO2 + O2–water–rock geochemical reaction simulation experiment was carried out, and the mineralogical and multiscale pore characteristics of typical samples before and after this simulation experiment were compared by X-ray diffraction and high-pressure mercury intrusion porosimetry (HPMIP). The results show that the CO2 + O2–water–rock geochemical reaction has complicated effects on the mineral compositions due to the various reaction modes and types. After the CO2 + O2–water–rock geochemical reaction, the femic minerals decrease and the clay minerals in the coarse sandstone, medium sandstone, fine sandstone, and siltstone increase, while the femic minerals and clay minerals in sandy mudstone show a contrary changing trend. The CO2 + O2–water–rock geochemical reaction decreases the total pore volume of uranium-bearing reservoirs and then promotes pore transformation from small scale to large scale. The fractal dimensions of macropores are decreased, and the fractal dimensions of mesopores, transition pores, and micropores are increased. The effects of felsic mineral and carbonate dissolution, secondary mineral precipitate, clay mineral swelling, and mineral particle migration are simultaneously present in the CO2 + O2in situ leaching process, which exhibit the positive transformation and the negative transformation for the uranium-bearing reservoirs. The mineral dissolution may improve reservoir permeability to a certain degree, while the siltation effect will gradually reveal with the extension of CO2 + O2in situ leaching. This research will provide a deep understanding of the physical property response of uranium-bearing reservoirs during CO2 + O2in situ leaching and indicate the direction for the efficient recovery of uranium resources.