Reservoir Fluid Distribution Research Articles

Integrated numerical simulation of hydraulic fracturing and production in shale gas well considering gas-water two-phase flow

Based on the displacement discontinuity method and the discrete fracture unified pipe network model, a sequential iterative numerical method was used to build a fracturing-production integrated numerical model of shale gas well considering the two-phase flow of gas and water. The model accounts for the influence of natural fractures and matrix properties on the fracturing process and directly applies post-fracturing formation pressure and water saturation distribution to subsequent well shut-in and production simulation, allowing for a more accurate fracturing-production integrated simulation. The results show that the reservoir physical properties have great impacts on fracture propagation, and the reasonable prediction of formation pressure and reservoir fluid distribution after the fracturing is critical to accurately predict the gas and fluid production of the shale gas wells. Compared with the conventional method, the proposed model can more accurately simulate the water and gas production by considering the impact of fracturing on both matrix pressure and water saturation. The established model is applied to the integrated fracturing-production simulation of practical horizontal shale gas wells. The simulation results are in good agreement with the practical production data, thus verifying the accuracy of the model.

Prediction Model for Tight Gas Wells with Time-Dependent Mechanism and Stress Sensitivity Effect.

In the production process of tight gas wells, reservoir fluid distribution and gas-water relative permeability vary with time. However, traditional models fail to handle the time-dependent mechanism and stress sensitivity effect in the reservoir, leading to significant errors in the dynamic analysis results. To address this issue, this article presents a prediction model for fractured well production in tight gas reservoirs. It is based on a three-dimensional embedded discrete fracture model (EDFM), which considers the influences of the time-dependent mechanism and stress-dependent reservoir permeability. Transient flow equations are treated by using the finite volume method to obtain the solution of the model. The accuracy and reliability of the model are verified by comparison with the results of the commercial simulator Eclipse and the field application. Based on the model's solution, this study emphasizes the analysis of the impact of the time-dependent mechanism and reservoir stress sensitivity on gas well productivity. Simulation results show that the time-dependent relative permeability curve can decrease the level of irreducible water saturation and promote the migration of irreducible water, resulting in an increase in water permeability and a decrease in gas permeability. This effect will reduce the period of stable gas production and increase the level of water production. Besides, reservoir stress sensitivity will reduce daily water production and accelerate gas well decline. It is necessary to control the production pressure difference reasonably during the production process to effectively reduce the negative impact of stress sensitivity effects. The results indicate that when the relative permeability curve and the reservoir permeability are constant, the real gas production capacity of the reservoir will be strengthened. The application of field case studies shows that the theoretical model exhibits stronger adaptability, achieves better fitting results, and can guide the compilation and adjustment of development plans for water-bearing tight gas reservoirs. These findings provide insights into understanding the effects of the time-dependent mechanism on gas production rates in tight gas reservoirs. Furthermore, this study offers useful guidance for the prediction of field-scale gas production.

The macro and micro analysis on EOR mechanisms during steam and solvent thermal recovery in heavy oil reservoirs

Using only pure steam as a driving medium in heavy oil reservoirs may result in a low oil recovery factor. Solvent is a good oil displacement medium that can be dissolved in heavy oil, which can greatly reduce the viscosity and improve the mobility of heavy oil. Therefore, the method of solvent assisted displacement and drainage has the unique advantage during steam flooding. In this paper, a quantitative method is proposed to choose appropriate solvents. Then a series of experiments are carried out, including oil displacement experiment to measure oil displacement efficiency, 2D visualization experiment to analyze the sweep efficiency and remaining oil distribution, and 3D scaling physical simulation setting with bottom water condition, which are used to analyze production performance, the expanding characteristics of steam chamber and study reservoir fluid distribution. The results show that steam moving upwards to heat and drive heavy oil to production well under the action of displacement and drainage. In a heavy oil reservoir with thin bottom water, if only steam is injected into reservoir, then there is no obvious stage of stable oil production and the oil recovery factor is only 32.7%. However, when solvent and steam are co-injected into reservoir, the stage of stable oil production maintaining about 0.6 PV and the oil recovery factor is 43.2%. During steam and solvent flooding, solvent can greatly reduce the oil viscosity to improve its mobility; meanwhile solvent can promote the expansion of steam chamber. The co-injection of steam and solvent can obviously expand steam chamber and increase oil recovery factor in heavy oil reservoirs (even connecting with bottom water layer). The method of steam and solvent flooding further enriches EOR technologies of thermal recovery in heavy oil reservoirs.

Molecular dynamics study of fluid-fluid and solid-fluid interactions in mixed-wet shale pores

Mixed wet pores are abundant in shales, yet there is little to no information on the behavior of fluids confined within pores characterized by one hydrophilic and one hydrophobic surface. This mixed wettability can impact fluid storage, distribution, capillary pressures and transport. In this study, we use molecular dynamics simulations to describe the initial distribution of reservoir fluids, such as multicomponent hydrocarbon mixtures and water, in mixed-wet pores. This is an essential pre-requisite to additional studies documenting fluid transport in such pores. The molecular model of the mixed wet pore used consists of kerogen separated by some distance from two clay surfaces. We evaluate spatial distribution of water and individual hydrocarbon species, at varying values of water concentration. Throughout the entire study, the results from the equilibrated system indicate a high affinity between the heavy components, such as the asphaltene/resin fraction and the kerogen surfaces. The more surprising result is the hydrogen bonding observed between the polar constituents in the asphaltene/resin fraction and water. This creates a situation where the asphaltene/resin fraction shows an affinity towards water. When this happens, the hydrophilic clay surface effectively becomes hydrophobic. A pore bounded by an asphaltene layer on one side and kerogen on the other is more oil-wetting than mixed-wet. The presence of asphaltenes can therefore expect to create conditions of modified wettability that will impact oil recovery, oil transport and distribution. Another surprising result in this work is that water forms structures that bridge between opposing surfaces of the model. These water bridges are seen to happen for water concentration values larger than 20%. In other words, water is not merely just adsorbed on to the clay surfaces, but also forms these bridge-like structures. Nevertheless, we still observe a strong affinity between the asphaltene/resin fraction and water leading to a lesser degree of mixed wettability. This study is the first, to the best of our knowledge, that considers water and multicomponent hydrocarbon mixtures in mixed-wet pores with realistic surface chemistry and constitutes a necessary first step towards additional studies related to water and hydrocarbon transport and EOR processes in shale nanopores.

Downhole System Enables Real-Time Reservoir-Fluid-Distribution Mapping

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 19807, “A New Downhole System for Real-Time Reservoir-Fluid-Distribution Mapping: E-REMM, the Eni Reservoir Electromagnetic Mapping System,” by Franco Bottazzi, Paolo Dell’Aversana, and Claudio Molaschi, SPE, Eni, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. This paper presents the basic concepts and architecture of the Eni Reservoir Electromagnetic Mapping (E-REMM) borehole electromagnetic (EM) mapping system that integrates borehole EM methodology with surface EM methods to provide real-time mapping of reservoir-fluid distribution during production or injection. By helping well teams know how distribution of hydrocarbons and water changes over time and space, the system addresses a fundamental requirement for managing the reservoir to maximize the recovery factor, optimize production, and reduce associated costs. Introduction Several approaches are currently used to map hydrocarbons and other fluids in the reservoir in real time with variable sensitivity, differences in effectiveness, and a wide range of costs. Among the various approaches, EM and electric methods show a high benefit-to-cost ratio and a high sensitivity to the resistivity contrast between oil-saturated and brine-saturated reservoir rocks. These methods can estimate variations in fluid properties at reservoir depth in a distance range of hundreds of meters, although the spatial resolution decreases significantly with the distance between sources and receivers. Furthermore, combining multiple layouts in boreholes and at surface can improve the effectiveness of EM and electric methods significantly while increasing their spatial resolution. The integrated system discussed in the complete paper allows multiscale EM prospecting and deep investigation in a large 3D volume of rocks between multiple wells and surface.

Effects of Foam Microbubbles on Electrical Resistivity and Capillary Pressure of Partially Saturated Porous Media.

Laboratory measurements of capillary pressure (Pc) and the electrical resistivity index (RI) of reservoir rocks are used to calibrate well logging tools and to determine reservoir fluid distribution. Significant studies on the methods and factors affecting these measurements in rocks containing oil, gas, and water are adequately reported in the literature. However, with the advent of chemical enhanced oil recovery (EOR) methods, surfactants are mixed with injection fluids to generate foam to enhance the gas injection process. Foam is a complex and non-Newtonian fluid whose behavior in porous media is different from conventional reservoir fluids. As a result, the effect of foam on Pc and the reliability of using known rock models such as the Archie equation to fit experimental resistivity data in rocks containing foam are yet to be ascertained. In this study, we investigated the effect of foam on the behavior of both Pc and RI curves in sandstone and carbonate rocks using both porous plate and two-pole resistivity methods at ambient temperature. Our results consistently showed that for a given water saturation (Sw), the RI of a rock increases in the presence of foam than without foam. We found that, below a critical Sw, the resistivity of a rock containing foam continues to rise rapidly. We argue, based on knowledge of foam behavior in porous media, that this critical Sw represents the regime where the foam texture begins to become finer, and it is dependent on the properties of the rock and the foam. Nonetheless, the Archie model fits the experimental data of the rocks but with resulting saturation exponents that are higher than conventional gas–water rock systems. The degree of variation in the saturation exponents between the two fluid systems also depends on the rock and fluid properties. A theory is presented to explain this phenomenon. We also found that foam affects the saturation exponent in a similar way as oil-wet rocks in the sense that they decrease the cross-sectional area of water available in the pores for current flow. Foam appears to have competing and opposite effects caused by the presence of clay, micropores, and conducting minerals, which tend to lower the saturation exponent at low Sw. Finally, the Pc curve is consistently lower in foam than without foam for the same Sw.

3D structural modelling and fluid identification in parts of Niger Delta Basin, southern Nigeria

Integrated 3D seismic and well log interpretations were used to assess structures and define reservoir fluid in some parts of the Niger Delta Basin. This method of characterizing structures and delineating fluid types has been proven to generate reliable interpretations of reservoir geometry and structures which serves as inputs during flow modelling and reservoir simulations. The study is aimed at defining 3D structural architecture and differentiating reservoir fluid across reservoirs in parts of Niger Delta, due to the difficult associated in building structural grid in complex reservoir situations for reservoir modelling and simulation, in spite of the enormous growth in grid generation. The structural styles in the field show intricate network of gravity-driven growth fault systems such as synthetic and antithetic listric faults, back-to-back faults within the ridges of mobile shale beneath the depo-belt and a variety of trapping mechanisms such as fault closures and rollover structures. These fault systems influence the dynamics of reservoir fluid providing preferential pathways that mobilize hydrocarbon up-dip. Localized variability in sedimentary succession and structural styles evident in the litho-facies logs and reservoir fluid distribution across the entire field were also identified. This work provides a relatively simple and reliable workflow for 3D structural modelling and reservoir fluid identification.

Investigating deep geological reservoirs using seismic reflection and well logs, Tawila oil field, Yemen: Implications for structural setting and reservoir properties

Seismic reflection data were used to evaluate the deep geological structures in Tawila oil field, Masila rift basin, Yemen. A combined set of 2D seismic profiles and geophysical well logs were used to produce structural mapping at the top of the clastic Qishn reservoir and the several overlying and underlying horizons. We have investigated the distribution of reservoir fluids in relation to the identified structures. The seismic horizons with their intersecting faults have been determined to be very important in the hydrocarbon distribution. Two key fault systems have been identified to control the hydrocarbon entrapment in the study area: major, deep, E–W normal faulting that affected the northern area, which caused extensive structural deformation, and a much shallower ENE–WSW fault system to south. The shale type and distribution and the basic reservoir properties, were enhanced through analysing the logging data using the standard clastic models. The reservoir is composed of three clastic compartments (S1, S2 and S3) which are separated by thin shale beds. No hydrocarbons were found in the S1 top unit which had considerable shale volume of a dispersed shale type. Considerable to good hydrocarbon content up to 57% and 61%, associated with a structural uplift, was identified in front of the S2 and S3 units, respectively. A dispersed/laminated shale model was assigned for these two units with a laminated style priority. The hydrocarbon entrapment in the study area was caused by the sealing characteristics of the overlying layers as well as the juxtaposition of the reservoir against other seal rocks. The distribution maps show an increase in hydrocarbon saturation toward the west, north and northeast which coincided with areas of low seismic-derived properties of velocity, acoustic impedance and negative reflection coefficient. An elongated structural horst of good hydrocarbon potentiality was identified in the upthrow of the major fault. This prospective structural high is a key to explore hydrocarbons in nearby areas and other basins of similar geologic characteristics.

Spatial distribution of reservoir fluids in mature kerogen using molecular simulations

This work analyses the distribution of volatile oil and other reservoir fluids in kerogen belonging to the gas condensate/volatile oil window. The kerogen models representing kerogen Type II-C contain pores in the range of micropores (diameter <2 nm) and mesopores (2 nm < diameter < 50 nm). A few of the micropores are isolated pores whereas the mesopores are connected in all spatial directions. Methane is observed to fill the pores while longer n-alkane chains transition from filling the pore to adsorbing onto the pore surface. The heavier components in the reservoir fluids adsorb onto the surface of the pore and can partially or completely clog the pore throats. As a general trend, the longer the alkane chain, the more preferentially the molecule adsorbs onto the pore surface. Additionally, the molecular simulations correctly capture the hydrophobic environment in which water molecules cluster together to form a droplet that resides in or close to a pore throat. Some molecules of carbon dioxide seem to preferentially adsorb onto either the kerogen internal surface or on the molecules of adsorbed heavier components, while the rest of the molecules diffuse into the kerogen body. This observation has not been previously reported to the best of our knowledge. Also the adsorption of the heavier species onto the pore walls significantly decreases the surface area available for adsorption of other species. This work underscores the significance of knowing fluid distributions to model primary recovery as well as secondary or tertiary recovery.

Visualization and quantification of capillary drainage in the pore space of laminated sandstone by a porous plate method using differential imaging X‐ray microtomography

AbstractThe experimental determination of capillary pressure drainage curves at the pore scale is of vital importance for the mapping of reservoir fluid distribution. To fully characterize capillary drainage in a complex pore space, we design a differential imaging‐based porous plate (DIPP) method using X‐ray microtomography. For an exemplar mm‐scale laminated sandstone microcore with a porous plate, we quantify the displacement from resolvable macropores and subresolution micropores. Nitrogen (N2) was injected as the nonwetting phase at a constant pressure while the porous plate prevented its escape. The measured porosity and capillary pressure at the imaged saturations agree well with helium measurements and experiments on larger core samples, while providing a pore‐scale explanation of the fluid distribution. We observed that the majority of the brine was displaced by N2 in macropores at low capillary pressures, followed by a further brine displacement in micropores when capillary pressure increases. Furthermore, we were able to discern that brine predominantly remained within the subresolution micropores, such as regions of fine lamination. The capillary pressure curve for pressures ranging from 0 to 1151 kPa is provided from the image analysis compares well with the conventional porous plate method for a cm‐scale core but was conducted over a period of 10 days rather than up to few months with the conventional porous plate method. Overall, we demonstrate the capability of our method to provide quantitative information on two‐phase saturation in heterogeneous core samples for a wide range of capillary pressures even at scales smaller than the micro‐CT resolution.

The Application of Nanoparticles in Enhancing Oil Recovery by Wettability Alteration

Wettability is one of most important characteristics for governing the flow and distribution of reservoir fluids in the porous media,the wetting and spreading behavior of liquids on the solid surfaces changes if the wettability of solid surface is altered. Recent studies show the spreading behavior of liquids on solid surface can be significantly improved after nanofluid treatment. In order to investigate the influence of wettability alternation on enhancing oil recovery after nanofluid treatment,flushing oil experiment and contact angle measurement were conducted in the laboratory. The first experiment involved flushing crude oil with the nanofluid and conventional surfactants, respectively. In the second case, the contact angles of oil phase in nanofluid (conventional surfactant solutions)-crude oil-slide systems were measured after treating 36 hours. The results indicated that nanofluid can produce a better flushing efficiency compared with that of conventional surfactant, and the contact angles of oil phase increased from 33° to 118° after nanofluid treatment in nanofluid/crude-oil/slide system. The mechanism of enhanced oil recovery of nanofluid is mainly wettability alternation.

Surface energy characterization of carbonate rocks

Carbonate rocks (calcite and dolomite) account for more than half of the world's hydrocarbon reserves. Despite the complexity posed by these rocks, it is important to understand the fundamental forces of adhesion responsible for the spreading and distribution of reservoir fluids, such as crude oil/brine on the reservoir rock surface. These physico-chemical interactions determine the surface energetics of a reservoir and affect their wetting characteristics. Inverse gas chromatography is introduced to characterize the surface energy of carbonates (calcite and dolomite). The behavior of the polar and non-polar interaction forces was investigated at varying water coverage and at different temperatures. The results indicated that in general as the water coverage increased, the Lifshitz–van der Waals component of surface energy decreased to nearly that of the bulk water, while the acid–base component also showed a decreasing trend. The Lifshitz–van der Waals component of surface energy always decreased with increase in temperature, while the acid–base properties showed contrasting trends for the two minerals.

Wettability determination of core samples through visual rock and fluid imaging during fluid injection

Reservoir rock wettability is a key factor in oil recovery, as it controls the location, flow, and distribution of reservoir fluids. However, proper assessment of wettability is not an easy task and provides a number of challenges. Wettability is in parts determined by the history of the oil reservoir through mechanisms such as aging and fouling. Hence direct measurements on freshly exposed rock surfaces (e.g. on core plugs) are critical and might not represent the true wettability within the sample. We present a new and fast method for wettability determination based on the optical observation of injected fluids, which allows for wettability determination independent from the surface wettability state of the sample. Fluid behavior within the boundaries of the capillary regime is driven by capillary forces and thus by wettability, which is exploited for our method. We show that a combined optical white-light and fluorescence imaging technique provides excellent contrast for reliable observations. Based on this imaging technique, we successfully distinguish core samples with different internal wettability, independent of their surface state.

Ensemble-based conditioning of reservoir models to seismic data

While 3D seismic has been the basis for geological model building for a long time, time-lapse seismic has primarily been used in a qualitative manner to assist in monitoring reservoir behavior. With the growing acceptance of assisted history matching methods has come an equally rising interest in incorporating 3D or time-lapse seismic data into the history matching process in a more quantitative manner. The common approach in recent studies has been to invert the seismic data to elastic or to dynamic reservoir properties, typically acoustic impedance or saturation changes. Here we consider the use of both 3D and time-lapse seismic amplitude data based on a forward modeling approach that does not require any inversion in the traditional sense. Advantages of such an approach may be better estimation and treatment of model and measurement errors, the combination of two inversion steps into one by removing the explicit inversion to state space variables, and more consistent dependence on the validity of assumptions underlying the inversion process. In this paper, we introduce this approach with the use of an assisted history matching method in mind. Two ensemble-based methods, the ensemble Kalman filter and the ensemble randomized maximum likelihood method, are used to investigate issues arising from the use of seismic amplitude data, and possible solutions are presented. Experiments with a 3D synthetic reservoir model show that additional information on the distribution of reservoir fluids, and on rock properties such as porosity and permeability, can be extracted from the seismic data. The role for localization and iterative methods are discussed in detail.

Theoretical Treatment of Asphaltene Gradients in the Presence of GOR Gradients

The modeling of hydrocarbon fluids in oil-field reservoirs is essential for optimizing production. In particular, the often large compositional variations of reservoir crude oils must be understood and modeled. The two most important chemical constituents that govern many chemical and physical properties of subsurface reservoir crude oils are the dissolved gas content, described by the gas−oil ratio (GOR), and the asphaltene content. The modeling of GOR variations of crude oils in reservoirs has been practiced routinely for many decades. However, proper modeling of the asphaltenes and/or heavy ends of reservoir crude oils has been precluded because of the lack of understanding of the chemical and physical properties of asphaltenes in crude oils. Recently, the modified Yen model has codified advances in asphaltene science by providing a framework for understanding the molecular and colloidal structure of asphaltenes in crude oils. Here, a thermodynamic model of asphaltenes in reservoir crude oils is developed that can incorporate the modified Yen model and thus can be used to treat reservoir crude oils. Our objective is to analyze the distribution of reservoir fluids, in particular the asphaltenes. This deviates from most previous studies of asphaltene thermodynamics, which were focused on the phase behavior of asphaltenes. Here, compositional gradients of asphaltenes, as well as the GOR of reservoir crude oils, are analyzed. Asphaltene gradients are shown to be strongly affected by both gravity and solubility. The latter effect is heavily dependent on the dissolved gas content of the reservoir crude oil. Case studies are provided that exhibit the power of this modeling.

ウムアルアンバー油田の貯留層内流体について

Reservoir fluids in Umm Al-Anbar (AR) Field have unique characteristics with vertical variations in the hydrocarbon properties in the 500-ft thickness of Arab Formations. While Arab A and B reservoirs are black oil reservoirs, Arab C and D1 reservoirs are reservoirs with near critical fluids varying in composition according to the reservoir depths. Since Arab D2 and D3 reservoirs are gas condensate reservoirs, there are three types of reservoir fluid in the field.Modeling of the migration and accumulation process has been studied in order to explain vertical reservoir fluid distribution and the formation of near critical fluids in the field. The process of primary oil and secondary gas migration was proposed in 1993.This report presents several technical topics related to :(1) The vertical distribution of different types of reservoir fluid.(2) The process of primary oil accumulation and secondary gas migration.(3) Special properties of near critical fluid.In addition several technical points on the treatment of near critical fluid in reservoir simulation studies are discussed.

Abstract: Structural Compartmentalization and Reservoir Fluid Distribution in the Terry and Muddy (J) Sandstones, Denver Basin, Colorado&amp;nbsp;

Abstract: Structural Compartmentalization and Reservoir Fluid Distribution in the Terry and Muddy (J) Sandstones, Denver Basin, Colorado&amp;nbsp;

Structural and Stratigraphic Compartmentalization of the Terry Sandstone, and Effects on Reservoir Fluid Distributions, Latham Bar Trend, Denver Basin, CO: ABSTRACT

Structural and Stratigraphic Compartmentalization of the Terry Sandstone, and Effects on Reservoir Fluid Distributions, Latham Bar Trend, Denver Basin, CO: ABSTRACT

Structural and Stratigraphic Compartmentalization of the Terry Sandstone and Effects on Reservoir Fluid Distributions in Hambert-Aristocrat Fields, Denver Basin, Colorado: ABSTRACT

Structural and Stratigraphic Compartmentalization of the Terry Sandstone and Effects on Reservoir Fluid Distributions in Hambert-Aristocrat Fields, Denver Basin, Colorado: ABSTRACT

AN EMPIRICAL EXPRESSION FOR PERMEABILITY IN UNCONSOLIDATED SANDS OF THE EASTERN NIGER DELTA

Several correlations for estimating the reservoir permeability from electric well‐log data have previously been developed. Unfortunately, none of these correlations are universally valid, since each correlation is strongly dependent on the local lithology, and the properties and distribution of reservoir fluids in the well. There is therefore a need to develop such a correlation for use in reservoir rocks of the Niger Delta Basin.Using multiple‐regression analysis, the Authors have developed empirical expressions for permeability in terms of log‐derived porosity and irreducible water‐saturation for unconsolidated sands in the Eastern Niger Delta. A comparison is made between this new expression and those previously proposed, using 218 sets of field‐measured data. Permeability estimated by the newly‐ proposed expression is found to be accurate.The expression could be valid for other oil‐producing areas, provided that the reservoir rock and fluid properties are similar to those of unconsolidated sands in the Eastern Niger Delta.