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Reservoir pressure reduction due to continuous production from oil and gas wells affects the sand production rate. An increase in drawdown pressure and/or a decrease in reservoir pressure increases the sand production rate. Since the problem of sand production is one of the main issues in the Asmari sandstone formation located in one of the oilfields in the southwest of Iran, therefore, in this research, the variations in the sand production rate due to the changes in the reservoir and drawdown pressures were investigated. So, for the first time, a hybrid numerical model of finite difference method (FDM)—discrete element method (DEM)—finite element method (FEM)—computational fluid dynamics (CFD) was developed. This numerical model investigated the increase in the sand production rate due to variations in reservoir pressure with a constant bottom-hole flowing pressure. Then, by performing an extensive sensitivity analysis on different values of reservoir pressure and drawdown pressure, the changes in the sanding rate, the critical drawdown pressure, and the safe drawdown line were determined. The results showed that, if the production flow rate of the well is constant, increasing the drawdown pressure can change the sand production rate only to a certain extent, and more than that, will be produced at a constant rate. Also, adjusting the drawdown pressure within a safe range does not necessarily keep the sand production rate constant at a permissible value for a long time, while by keeping the bottom hole flowing pressure constant within an acceptable range, the sand production rate can be controlled for a longer period. [ABSTRACT FROM AUTHOR]

In this paper we present the results of studies of the Botuobin, Talakh, and Khamakin reservoirs of the Vendian period in the Chayanda hydrocarbon field (Eastern Siberia). Based on an analysis of variations in the petrophysical parameters of reservoirs upon an increase in effective pressure from 37 to 57 MPa, i.e., under conditions simulating the development of a field for depletion, changes in the volume and compressibility of the pore space are estimated. In this case, the porosity coefficient decreases by 0.043 abs. %, while the compressibility of the pore space decreases by 0.228 1/GPa. The average volumetric compression strain increases by 0.096%, which means a reduction in the volume of developed reservoirs by almost 0.1% relative to the beginning of development. A deformable formation model developed by Yu.O. Kuzmin based on the geodynamic history of the development of deposits is applied to estimate the magnitude of possible subsidence of the ground surface during development. The maximal values of possible surface subsidence (drawdowns) upon a decrease in reservoir fluid pressure by 5 MPa are estimated to be 0.33 m with allowance for the dynamics of petrophysical parameters and 0.335 m with no allowance for it. The maximal drawdowns are already estimated at 0.60 and 0.65 m upon a decrease in reservoir pressure by 10 MPa and 0.78 and 0.83 m upon a complete depletion of reservoir energy, respectively. The results of the studies show that taking into account the changes in petrophysical characteristics caused by the field development processes alters the estimate of the deformation state of the rock massif and the ground surface above the deposit and, consequently, the estimate of the level of geodynamic risk of oil-and-gas complex objects. [ABSTRACT FROM AUTHOR]

On the basis of modern ideas about the structural organization of the geological shell of the Earth, the authors substantiate the geofluid dynamics patterns of the localization of hydrocarbon systems (and their elements) at great depths. According to the authors, under conditions of high compressive loads exerted by overlying deposits, reliable all-round lithological shielding of reservoirs, hydrodynamic stagnation in deep-seated complexes of evaporite basins, a special type of hydrocarbon system, that is, autoclaved, can be developed. The authors predict that in the Pricaspian oil-and-gas province in the subsalt oil and gas bearing stage (in the Lower Devonian–Lower Permian deposits), an autoclave hydrocarbon system could have formed due to the sealing of a salt-bearing complex of significant thickness (i), the unrealized generation potential of oil and gas source strata represented by deep-water deposits 4–6 km and deeper (ii), and hydrodynamic stagnation of the water drive system (iii). Under the control of these conditions, paleo-drive objects and intra-basin carbonate structures near contact with oil and gas source rocks act as high-capacity reservoirs for the products of catagenic fluid generation and the segregation of a single-phase fluid with phase separation of hydrocarbons during periods of a sharp decrease in reservoir pressure completes the formation of unique and large hydrocarbon fields. [ABSTRACT FROM AUTHOR]

In the processes of oil-and-gas accumulation at the lower stages of salt basins, the authors of this paper substantiate the leading role of special, autoclave type of hydrocarbon systems (HCSs). According to the authors concept, autoclave hydrocarbon systems are multiscale, tectonically and lithologically screened fluid-saturated areas of the lithosphere, which are characterized by spatiotemporal conjugation of the processes of generation, primary migration, and accumulation of hydrocarbons (HC) in an environment of hydrodynamic stagnation, age identity of fluids and fluid host rocks. The paper discusses the place of autoclave hydrocarbon systems in the hierarchical series of oil and gas localizing objects of different ranks: uvosphere → oil-and-gas bearing level → hydrocarbon system → oil-and-gas complex → oil and gas bearing horizon. The main attention is paid to the kitchen (focal) autoclave hydrocarbon systems. The general conclusion of the authors is that under the conditions of autoclave kitchen hydrocarbon systems, the segregation of hydrocarbons (when the temperature-baric threshold of phase separation of oil, condensate, and gas is reached) from a single-phase fluid is confined to zones of low hydrodynamic potentials and the localization of free hydrocarbons mainly occurs in situ. [ABSTRACT FROM AUTHOR]

The injection of fluids into a compartmentalized formation induces pore pressure buildup and may result in reactivation of sealing faults. Among other variables, the pore volume compressibility (PVC) can affect the amount of pore pressure change during injection. PVC has been traditionally measured with isotropic loading compressibility tests. However, long and thin reservoirs subjected to depletion or injection typically follow a uniaxial strain stress path, rather than an isotropic stress path. Furthermore, injection unloads the reservoir rock by reducing effective stress, whereas depletion causes loading. This paper reports experimental measurements of the uniaxial strain unloading compressibility of Frio sand, a member of Tertiary strata in the Gulf of Mexico Basin. The uniaxial strain unloading compressibility increases nonlinearly from 0.29 to 1.45 GPa−1 (2 to 10 µsip) as the mean effective stress is reduced from 26 to 5 MPa. The uniaxial strain unloading compressibility of Frio sand is about one third of the uniaxial strain loading compressibility at comparable levels of effective stress. The uniaxial strain compressibility of Frio sand is roughly one half of the isotropic compressibility. Reservoir simulation highlights that using incorrect pore compressibility values considerably underestimates the expected increase of pore pressure in a compartmentalized formation during injection. Uniaxial strain unloading compressibility of target reservoir rocks should be accurately estimated or measured to prevent excessive pressure build up in target storage formations during injection of CO2 or any other fluid. [ABSTRACT FROM AUTHOR]

This study aims to evaluate Kharita gas reservoir to enhance the production. The increase in water-cut ratio reduces the left hydrocarbons' amount behind pipe. Accurate determination of pore throats, pores connectivity and fluid distribution are central elements in improved reservoir description. The integration of core and logging data responses is often used to draw inferences about lithology, depositional sequences, facies, and fluid content. These inferences are based on petrophysical models utilizing correlations among tools' responses as well as rocks and fluids properties. Upper Kharita Formation produces gas and condensate from the clastic sandstone in Badr-3 field, western desert of Egypt. It consists mainly of sandstone with shale intercalations. It is subdivided into three sub-units Kharita A, Kharita B and Kharita C that are in pressure communication. Hence, a new further investigation and review for the previously calculated GIIP (gas initially in place) was initiated. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation; subsequently, a new unconventional petrophysical evaluation approach was performed. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. Reservoir shale cutoff of 55% by using cross-plot between shale volume and porosity (Toby Darling concept) was utilized to discriminate the reservoir from non-reservoir sections. The porosity model was used to calculate reservoir porosity, using the density log. The Archie and saturation/height function models were used to calculate the water saturation and used to calibrate the water saturation in the transition zone. The porosity–permeability (POR-PERM) transform equation was used to estimate the reservoir connectivity (absolute permeability) for the four petrophysical facies (High Quality Reservoir, Moderate Quality Reservoir, Low Quality Reservoir and Highly Shale Reservoir). Core data have shown variations in reservoir quality parameters (porosity and permeability) from one well to the other. Integration of all the reservoir pressures indicated that there are different fluid types (oil, gas and water) in the Upper Kharita Formation level. The saturation/height function model was used to calibrate the saturation in the transition zone. The integration of geological core and geophysical log data helped to conduct a comprehensive petrophysical assessment of Upper Kharita Formation for a better estimation of the reservoir and to achieve a better understanding of the water encroachment in the Upper Kharita reservoir. The big challenge is the determination of the most correct model for calculating porosity, permeability and water saturation in this reservoir of different quality sand. The new petrophysical evaluation resulted in doubling the volumes in Upper Kharita reservoir and so a perforation campaign was performed to confirm the new volumetric calculations, which showed a good match with the model results. Hence, a new well was drilled targeting the low quality sand and found them with high pressure almost near virgin pressure. [ABSTRACT FROM AUTHOR]

Estimation of fluid and rock properties of a hydrocarbon reservoir is always a challenging matter; especially, it is true for heterogeneous carbonate reservoirs. Petrophysical logs and laboratory activities are common methods for characterizing a hydrocarbon reservoir. This method in conjunction with geostatistical methods is applied to relatively homogeneous sandstone reservoirs or matrix media of dual-porosity heterogeneous carbonate reservoirs. To estimate properties of fracture system of a dual-media carbonate reservoir, outcrop properties, electrical borehole scans, fractal discrete fracture network and analogy with other reservoirs are common methods. Results which obtained from these methods describe the reservoir in a static way and could be relied on them for very small portion of the reservoir. In this paper, a dynamic procedure for describing reservoir features is proposed in order to enhance the conventional reservoir characterization methods. This method utilizes the reported production data for a specific period of time in conjunction with rock and fluid properties to estimate drainage radius of the well and matrix block height, porosity and width of fracture in the estimated drainage radius. The presented method is elaborated through its application in a real case. By this method, one can generate maps of matrix block size and fracture width and porosity throughout the reservoir. Also, it could be a powerful tool for estimation of effectiveness of acid/hydraulic fracturing activity. [ABSTRACT FROM AUTHOR]

This paper is based on a talk given at the Arterial Hemodynamics: Past, Present and Future symposium in June 2016. Like the talk it is divided into three different but related parts. Part 1 describes the calculation of reservoir and excess pressure from clinical pressure waveforms measured at 5 different aortic sites in 40 patients. The main results are that the reservoir pressure waveform propagates down the aorta and is effectively constant from the aortic root to the aortic bifurcation. Part 2 describes a low-frequency asymptotic analysis of the input impedance of an arterial tree. Neglecting terms of second order, the results show that the low-frequency component of the pressure waveform is uniform throughout the arterial tree and is delayed by an effective wave travel time that depends on the properties of the network. The low-frequency pressure waveform shares all of the properties of the reservoir pressure waveform, but it is premature to say that they are identical. Part 3 describes the analysis of arterial hemodynamicsusing wave fronts. It shows that every wave front introduced at the root of the aorta generates an exponentially increasing number of reflected and transmitted waves with exponentially decreasing amplitudes. The long-time response of the arterial tree can be described by a number of exponentially decaying eigen-modes, each with a different time constant. The analysis is applied to a 55-artery model of the human circulation and the modes and their time constants are shown. This theory provides an alternative method for studying arterial hemodynamics and helps in the interpretation of reservoir and excess pressure. [ABSTRACT FROM AUTHOR]

A theoretical model has been constructed for the gas-hydrate reservoir that represents a unique natural chemical reactor, and the principal possibility of the full extraction of gas from a hydrate due to the thermal reserves of the reservoirs themselves and the surrounding rocks has been analyzed. The influence exerted on the evolution of a gas hydrate reservoir by the reservoir thicknesses and the parameters that determine its initial state (a temperature, pressure, hydrate saturation) has been studied. It has been established that the shortest time of exploitation required by the reservoirs with a thickness of a few meters for the total hydrate decomposition is recorded in the cyclic regime when gas extraction alternated with the subsequent conservation of the gas hydrate deposit. [ABSTRACT FROM AUTHOR]

Geophysical techniques play key roles in the measuring, monitoring, and verifying the safety of CO sequestration and in identifying the efficiency of CO-enhanced oil recovery. Although geophysical monitoring techniques for CO sequestration have grown out of conventional oil and gas geophysical exploration techniques, it takes a long time to conduct geophysical monitoring, and there are many barriers and challenges. In this paper, with the initial objective of performing CO sequestration, we studied the geophysical tasks associated with evaluating geological storage sites and monitoring CO sequestration. Based on our review of the scope of geophysical monitoring techniques and our experience in domestic and international carbon capture and sequestration projects, we analyzed the inherent difficulties and our experiences in geophysical monitoring techniques, especially, with respect to 4D seismic acquisition, processing, and interpretation. [ABSTRACT FROM AUTHOR]

We reviewed existing methods for analyzing, in the time domain, physical mechanisms underlying the patterns of blood pressure and flow waveforms in the arterial system. These are wave intensity analysis and separations into several types of waveforms: (i) forward- and backward-traveling, (ii) peripheral and conduit, or (iii) reservoir and excess. We assessed the physical information provided by each method and showed how to combine existing methods in order to quantify contributions to numerically generated waveforms from previous cardiac cycles and from specific regions and properties of the numerical domain: the aortic root, arterial bifurcations and tapered vessels, peripheral reflection sites, and the Windkessel function of the aorta. We illustrated our results with numerical examples involving generalized arterial stiffening in a distributed one-dimensional model or localized changes in the model parameters due to a femoral stenosis, carotid stent or abdominal aortic aneurysm. [ABSTRACT FROM AUTHOR]

Abstract: It is commonly assumed that pressure and flow in the arteries are purely the result of forward and backward travelling waves. We will show that various observations of arterial behaviour are difficult to explain using this assumption. In particular we will look at what happens to arterial pressure under different conditions: during ectopic beats, in experimental studies of pressure and flow when the aorta is totally occluded at different locations, in a computational study of the input impedances of randomly generated networks of arteries and when pressure and velocity are measured at different distances along the aorta. We show that all of these observations can be explained using wave intensity analysis. We further show that this analysis suggests that it is useful to separate arterial pressure into a reservoir pressure that accounts for the overall compliance of the arterial system and an excess pressure that is determined by local conditions. Evidence has accumulated in the decade since the introduction of the reservoir-wave hypothesis that the reservoir/excess pressure separation can be useful in interpreting the results of vasoactive drugs on cardiovascular performance and that parameters based on the reservoir/excess pressure are significant predictors of cardiovascular events. The important question that remains to be answered is the usefulness of the concept in the interpretation, physiologically and clinically, of the complex behaviour of the cardiovascular system. We conclude that the evidence suggests that it is a worthwhile topic for future research. [Copyright &y& Elsevier]

A regional scale, showcase saline aquifer CO storage model from the North German Basin is presented, predicting the regional pressure impact of a small industrial scale CO storage operation on its surroundings. The intention of the model is to bridge the gap between generic and site-specific, studying the role of fluid flow boundary conditions and petrophysical parameters typically found in the North German Basin. The numerical simulation has been carried out using two different numerical simulators, whose results matched well. The most important system parameters proved to be the model's hydrological boundary conditions, rock compressibility, and permeability. In open boundary aquifers, injection-induced overpressures dissipate back to hydrostatic level within a few years. If a geological flow barrier is present on at least one side of the aquifer, pressure dissipation is seriously retarded. In fully closed compartments, overpressures can never fully dissipate, but equilibrate to a compartment-wide remnant overpressure. At greater distances to the injection well, maximum fluid pressures are in the range of a few bar only, and reached several years to decades after the end of the actual injection period. This is important in terms of long-term safety and monitoring considerations. Regional pressure increase impacts the storage capacities of neighbouring sites within hydraulically connected units. It can be concluded that storage capacities may be seriously over- or underestimated when the focus is on a single individual storage site. It is thus necessary to assess the joint storage capacities and pressure limitations of potential sites within the same hydraulic unit. [ABSTRACT FROM AUTHOR]

Regularization methods are used to construct computational algorithms for the interpretation of results from hydrodynamic studies of horizontal wells that provide estimates of the reservoir anisotropy, reservoir pressure, and the dependence of the in-place permeability on pressure. In contrast to graphic analytic methods, the proposed approach does not require the identification of flow regimes. [ABSTRACT FROM AUTHOR]

The effects of condensate gas blockage in the gas reservoir in the Mahakam Delta, East Kalimantan, Indonesia, are successfully simulated. Condensate blockage arises during gas production due to decreasing reservoir pressure. Gas production causes the isothermal pressure of the reservoir to fall, producing condensate accumulation in front of the wellbore and causing a decrease in the permeability and productivity of the well. The key parameters that control condensate gas blockage are pressure, permeability, and the relationship between pressure, volume, and temperature (PVT). This paper presents a simulation of condensate gas blockage in the Mahakam Delta gas field, East Kalimantan, Indonesia. Condensate gas blockage was simulated for two production wells that are controlled by the physical properties of the rock, such as its acoustic, elastic impedance, and permeability. The simulation results showed that the reservoir pressure decreases gradually, starting with decreasing pressure in the well. Condensate gas was formed when the pressure reached 3100 psig and was observed throughout the reservoir depending on the pressure and permeability distribution; condensate gas blockage readily occurs in a reservoir with low permeability. This paper proposes two drilling program scenarios that involve well stimulation and horizontal well drilling to overcome the condensate gas blockage. Well stimulation was applied in order to increase the permeability around the wellbore using fracturing, while horizontal well drilling aimed to increase the permeability and to enhance the coverage of the reservoir layer. Simulation of these two scenarios showed that horizontal well drilling provides a higher gas recovery factor than well stimulation. [ABSTRACT FROM AUTHOR]