Academic literature on the topic 'Oil reservoir engineering Oil fields Fluid dynamics'

Summary Electromagnetic (EM) heating is becoming a popular method for heavy-oil recovery because of its cost-efficiency and continuous technological improvements. It exploits the relationship that the viscosity of hydrocarbons decreases for increasing temperature; the heavy-oil components become more fluid-like, and hence easier to extract from the reservoir. Although several field studies have considered the effects of heating on the viscosity of the hydrocarbons, there has been very little research on the long-term effects of field production and the forecasting of the development of the reservoir. Increased flow rates within the reservoir render the moving fluids less viscous, implying fast-changing fluid-propagation patterns and increased uncertainty about the state of the oil displacement. This means, in the long term, strongly varying production projections, strong dependence on the permeability of the reservoir, and potentially undesirable fluid migration. To improve the forecasting of production in heavy-oil fields and to accurately capture the dynamics of the fluid movements, we present a history-matching framework incorporating well data and seismic and EM crosswell-imaging techniques. The incorporation of seismic and EM data into the history-matching process counteracts the changing reservoir dynamics caused by increased fluid velocity caused by heating and is shown to significantly improve reservoir matching and forecasts for a variety of different heating scenarios.

Well prioritization rules on integrated production models are required for the interaction between reservoirs and restricted production systems, thus predicting the behavior of multiple reservoir sharing facilities. This study verified the impact of well management with an economic evaluation based on the distinct prioritizations by reservoir with different fluids. We described the impact of the well management method in a field development project using a consolidated methodology for production strategy optimization. We used a benchmark case based on two offshore fields, a light oil carbonate and a black-oil sandstone, with gas production constraint in the platform. The independent reservoir models were tested on three different approaches for platform production sharing: (Approach 1) fixed apportionment of platform production and injection, (Approach 2) dynamic flow-based apportionment, and (Approach 3) dynamic flow-based apportionment, including economic differences using weights for each reservoir. Approach 1 provided the intermediate NPV compared with the other approaches. On the other hand, it provided the lowest oil recovery. We observed that the exclusion of several wells in the light oil field led to a good valuation of the project, despite these wells producing a fluid with higher value. Approach 2 provided the lower NPV performance and intermediate oil recovery. We found that the well prioritization based on flow failed to capture the effects related to the different valuation of the fluids produced by the two reservoirs. Approach 3, which handled the type of fluids similarly to Approach 1, provided a greater NPV and oil recovery than the other approaches. The weight for each reservoir applied to well prioritization better captured the gains related to different valuation of the fluids produced by the two reservoirs. Dynamic prioritization with weights performed better results than fixed apportionment to shared platform capacities. We obtained different improvements in the project development optimization due to the anticipation of financial returns and CAPEX changes, due mainly from adequate well apportionment by different management algorithm. Well management algorithms implemented in traditional simulators are not developed to prioritize different reservoir wells separately, especially if there are different economic conditions exemplified here by a different valuation of produced fluids. This valuation should be taken into account in the short term optimization for wells.

Summary In reservoir history matching or data assimilation, dynamic data, such as production rates and pressures, are used to constrain reservoir models and to update model parameters. As such, even if under certain conceptualization the model parameters do not vary with time, the estimate of such parameters may change with the available observations and, thus, with time. In reality, the production process may lead to changes in both the flow and geomechanics fields, which are dynamically coupled. For example, the variations in the stress/strain field lead to changes in porosity and permeability of the reservoir and, hence, in the flow field. In weak formations, such as the Lost Hills oil field, fluid extraction may cause a large compaction to the reservoir rock and a significant subsidence at the land surface, resulting in huge economic losses and detrimental environmental consequences. The strong nonlinear coupling between reservoir flow and geomechanics poses a challenge to constructing a reliable model for predicting oil recovery in such reservoirs. On the other hand, the subsidence and other geomechanics observations can provide additional insight into the nature of the reservoir rock and help constrain the reservoir model if used wisely. In this study, the ensemble-Kalman-filter (EnKF) approach is used to estimate reservoir flow and material properties by jointly assimilating dynamic flow and geomechanics observations. The resulting model can be used for managing and optimizing production operations and for mitigating the land subsidence. The use of surface displacement observations improves the match to both production and displacement data. Localization is used to facilitate the assimilation of a large amount of data and to mitigate the effect of spurious correlations resulting from small ensembles. Because the stress, strain, and displacement fields are updated together with the material properties in the EnKF, the issue of consistency at the analysis step of the EnKF is investigated. A 3D problem with reservoir fluid-flow and mechanical parameters close to those of the Lost Hills oil field is used to test the applicability.

AbstractFaults are known to affect the way that fluids can flow in clastic oil and gas reservoirs. Fault barriers either stop fluids from passing across or they restrict and direct the fluid flow, creating static or dynamic reservoir compartments. Representing the effect of these barriers in reservoir models is key to establishing optimal plans for reservoir drainage, field development and production.Fault property modelling is challenging, however, as observations of faults in nature show a rapid and unpredictable variation in fault rock content and architecture. Fault representation in reservoir models will necessarily be a simplification, and it is important that the uncertainty ranges are captured in the input parameters. History matching also requires flexibility in order to handle a wide variety of data and observations.The Juxtaposition Table Method is a new technique that efficiently handles all relevant geological and production data in fault property modelling. The method provides a common interface that is easy to relate to for all petroleum technology disciplines, and allows a close cooperation between the geologist and reservoir engineer in the process of matching the reservoir model to observed production behaviour. Consequently, the method is well suited to handling fault property modelling in the complete life cycle of oil and gas fields, starting with geological predictions and incorporating knowledge of dynamic reservoir behaviour as production data become available.

Summary An oil/water capillary transition zone often contains a sizable portion of a field's initial oil in place, especially for those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (Sor) against depth, and on the rock and fluid interactions that control the residual oil saturation (Sor), capillary pressure, and relative permeability characteristics as a function of initial oil saturation. Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the transition zone, modeling both the static and dynamic properties of carbonate fields with large transition zones remains an ongoing challenge. In this paper, we first review the transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed, based on extensive experimental measurements and numerical simulation, for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure curves including hysteresis, based on experimental special-core-analysis (SCAL) data, has a significant impact on the field-performance predictions, especially for heterogeneous reservoirs with transition zones. Introduction The reservoir interval from the oil/water contact (OWC) to a level at which water saturation reaches irreducible is referred to as the capillary transition zone. Fig. 1 illustrates a typical capillary transition zone in a homogeneous reservoir interval within which both the oil and water phases are mobile. The balance of capillary and buoyancy forces controls this so-called capillary transition zone during the primary-drainage process of oil migrating into an initially water-filled reservoir trap. Because the water-filled rock is originally water-wet, a certain threshold pressure must be reached before the capillary pressure in the largest pore can be overcome and the oil can start to enter the pore. Hence, the largest pore throat determines the minimum capillary rise above the free-water level (FWL). As shown schematically in Fig. 2, close to the OWC, the oil/water pressure differential (i.e., capillary pressure) is small; therefore, only the large pores can be filled with oil. As the distance above the OWC increases, an increasing proportion of smaller pores are entered by oil owing to the increasing capillary pressure with height above the FWL. The height of the transition zone and its saturation distribution is determined by the range and distribution of pore sizes within the rock, as well as the interfacial-force and density difference between the two immiscible fluids.

Summary The present work describes a parallel computational framework for carbon dioxide (CO2) sequestration simulation by coupling reservoir simulation and molecular dynamics (MD) on massively parallel high-performance-computing (HPC) systems. In this framework, a parallel reservoir simulator, reservoir-simulation toolbox (RST), solves the flow and transport equations that describe the subsurface flow behavior, whereas the MD simulations are performed to provide the required physical parameters. Technologies from several different fields are used to make this novel coupled system work efficiently. One of the major applications of the framework is the modeling of large-scale CO2 sequestration for long-term storage in subsurface geological formations, such as depleted oil and gas reservoirs and deep saline aquifers, which has been proposed as one of the few attractive and practical solutions to reduce CO2 emissions and address the global-warming threat. Fine grids and accurate prediction of the properties of fluid mixtures under geological conditions are essential for accurate simulations. In this work, CO2 sequestration is presented as a first example for coupling reservoir simulation and MD, although the framework can be extended naturally to the full multiphase multicomponent compositional flow simulation to handle more complicated physical processes in the future. Accuracy and scalability analysis are performed on an IBM BlueGene/P and on an IBM BlueGene/Q, the latest IBM supercomputer. Results show good accuracy of our MD simulations compared with published data, and good scalability is observed with the massively parallel HPC systems. The performance and capacity of the proposed framework are well-demonstrated with several experiments with hundreds of millions to one billion cells. To the best of our knowledge, the present work represents the first attempt to couple reservoir simulation and molecular simulation for large-scale modeling. Because of the complexity of subsurface systems, fluid thermodynamic properties over a broad range of temperature, pressure, and composition under different geological conditions are required, although the experimental results are limited. Although equations of state can reproduce the existing experimental data within certain ranges of conditions, their extrapolation out of the experimental data range is still limited. The present framework will definitely provide better flexibility and predictability compared with conventional methods.

Summary This paper quantifies the potential variation in composition and pressure/volume/temperature (PVT) properties with depth owing to gravity, chemical, and thermal forces. A wide range of reservoir fluid systems has been studied using all of the known published models for thermal diffusion in the nonisothermal mass-transport problem. Previous studies dealing with the combined effects of gravity and vertical thermal gradients on compositional grading have been either (1) of a theoretical nature, without examples from reservoir fluid systems, or (2) proposing one particular thermal-diffusion model, usually for a specific reservoir, without comparing the results with other thermal-diffusion models. We give a short review of gravity/nonisothermal models published to date. In particular, we show quantitative differences in the various models for a wide range of reservoir fluid systems. Solution algorithms and numerical stability problems are discussed for the nonisothermal models that require numerical discretization, unlike the exact analytical solution of the isothermal gradient problem. We discuss the problems related to fluid initialization in reservoir models of complex fluid systems. This involves the synthesis of measured sample data and theoretical models. Specific recommendations are given for interpolation and extrapolation of vertical compositional gradients. The importance of dewpoint on the estimation of a gas/oil contact (GOC) is emphasized, particularly for newly discovered reservoirs in which only gas samples are available and the reservoirs are near-saturated. Finally, we present two field case histories—one in which the isothermal gravity/chemical equilibrium model describes measured compositional gradients in a reservoir grading continuously from a rich gas condensate to a volatile oil, and another example in which the isothermal model is grossly inconsistent with measured data and convection or thermal diffusion has apparently resulted in a more-or-less constant composition over a vertical column of some 5,000 ft. Introduction Composition variation with depth can result for several reasons:Gravity segregates the heaviest components toward the bottom and lighter components like methane toward the top. [1-3]Thermal diffusion (generally) segregates the lightest components toward the bottom (i.e., toward higher temperatures) and heavier components toward the top (toward lower temperatures). [3,4]Thermally induced convection creating mixed fluid systems with more-or-less constant compositions is often associated with very high permeability or with fractured reservoirs.[5-7]Migration and equilibrium distribution of hydrocarbons is not yet complete because the times required for diffusion over distances of kilometers may be many tens of millions of years. [8]Dynamic flux of an aquifer passing by and contacting only part of a laterally extensive reservoir may create a sink for the continuous depletion of lighter components such as methane.Asphaltene precipitation (a) during migration may lead to a distribution of varying oil types in the high- and low-permeability layers in a reservoir [9] and (b) in the lower parts of a reservoir (tar mats) caused by nonideal thermodynamics and gravitational forces. [10,11]Varying distribution of hydrocarbon types (e.g., paraffin and aromatic) within the heptanes-plus fractions. [2,12]Biodegradation varying laterally and with depth may cause significant variation in, for example, H2S content and API gravity.Regional (tens to hundreds of kilometers) methane concentrations that may lead to neighboring fields having varying degrees of gas saturation (e.g., neighboring fault blocks that vary from saturated gas/oil systems to strongly undersaturated oils).Multiple source rocks migrating differentially into different layers and geological units. These conditions and others, separately or in combination, can lead to significant and seemingly uncorrelatable variations in fluid composition, both vertically and laterally. For a given reservoir, it is impossible to model numerically most of these complex phenomena because (a) we lack the necessary physical and chemical understanding of the problem, (b) boundary conditions are continuously changing and unknown, and (c) we do not have the physical property data and geological information necessary to build even the simplest physical models. One purpose of this paper is to evaluate simple 1D models of vertical compositional gradients caused by gravity, chemical, and thermal effects, with the fundamental simplifying assumption of zero component mass flux defining a stationary condition. We show that the gravitational force usually results in maximum compositional variation, while thermal diffusion tends to mitigate gravitational segregation. Published field case histories13–17 and a number of fields where we have studied vertical compositional gradients show that (a) the isothermal model describes quantitatively the compositional variation in some fields; (b) some fields show almost no compositional variation, even though the isothermal model predicts large variations; (c) a few fields have compositional variations that are larger than predicted with the isothermal model; and (d) some fields show variations in composition that are not at all similar to those predicted by zero-flux models. Another purpose of this study was to compare quantitatively the various thermal-diffusion models for a wide range of reservoir fluid systems. Such a comparison was not available, and we were unsure whether the available models showed significant differences. Finally, we wanted to give guidelines for how to use measured field data for defining initial fluid distribution, and how simple gradient models can be used to assess measured data and to extrapolate compositional trends to depths where samples are not available. Compositional Grading—Zero-Mass-Flux Model Calculating the variation of composition with depth is usually based on the assumption that all components have zero mass flux—existing in a stationary state18–21 in the absence of convection. To satisfy the condition of zero component net flux, a balance of driving forces or flux equations are used. The driving forces considered include:Chemical energy.Gravity.Thermal gradient.

Summary This paper describes the procedure of building a probabilistic decision tree on the basis of the integration of data from multiple sources, conditional probabilities, and the application to map fracture corridors (FCs) in a mature oil field with abundant production data. A fracture corridor is a tabular, subvertical, fault-related fracture swarm that intersects the entire reservoir and extends laterally for several tens or hundreds of meters. Direct indicators of fracture corridors, such as image logs, flow profiles, well tests, and seismic fault maps, are sometimes insufficient to map all fracture corridors in a field. It is also necessary to use indirect fracture-corridor indicators from well data, such as productivity index (PI), gross rate, water cut, and openhole logs. Fracture corridors from indirect indicators can be inferred by a probabilistic decision tree, which makes predictions by integrating data from multiple sources, giving preference to the indicators with the highest relevance. Decision trees are constructed by use of a training set that includes measurements of both direct and indirect fracture-corridor indicators. In this study, wells with borehole images, production logs (flow profiles), and injector/producer short cuts are selected as the training set. The resulting decision trees reveal that total losses, gross production rates, and water cuts are the three most effective indirect indicators of fracture corridors in the test field. Introduction It is often the case that a particular reservoir attribute, such as porosity, has only sparse direct measurements. It is possible, however, to predict values of such a target variable with the help of a set of other variables that exhibit some degree of correlation to the target variable and have abundant measurements. A common example is estimating porosity from seismic attributes. In this paper, the variables that have one-to-one correspondence to the target variable are called direct indicators and the variables that have some degree of correlation are called indirect variables. For example, density and neutron logs are direct indicators of porosity, whereas seismic impedance is an indirect indicator. There are several statistical techniques to predict a target variable from a set of indirect indicators, and these can be collected under two main groups: supervised prediction techniques and unsupervised prediction techniques. In the case of supervised prediction techniques, indirect indicators are correlated to a target variable by use of a training set of data that includes measurement of both direct and indirect indicators of the target variable. The generated predictive system can be used to estimate values of the target variable solely on the basis of indirect indicators in wells that do not have any measurement of direct indicators. Multiple regression, back propagation, neural networks, and Bayesian decision trees belong to this category. In cases where the training set is small or no direct indicators are available, it is possible to adopt statistical techniques that do not require extrapolation from a training set. These are termed unsupervised prediction techniques. Several such techniques exist, including cluster analysis, unsupervised neural networks, and factor analysis (Wasserman 1989; Chester 1993; Van De Geer 1971). The basic idea is to discover hidden factors that control indicator variables and to interpret these factors in terms of the target variable. For example, the density (spacing/relative abundance) of conductive fractures may affect the rapid water-cut rise, high initial PI, and high gross rate. These three indirect indicators will be highly correlated to each other. An unsupervised prediction technique may uncover the hidden factor (fracture density) that controls all three variables from the high correlation among them. Both supervised and unsupervised inferences are methods for making predictions with incomplete information (Tamhane et al. 2000; Fletcher and Davis 2002). Most of the applications in the oil industry use fuzzy logic or fuzzy neural networks. These applications also use soft computing decision making with incomplete evidence and risk reduction by use of a fuzzy-expert system (Weiss et al. 2001; Chen et al. 2002; Saggaf and Nebrija 2003). This idea has found some application, especially in mapping fracture density by use of seismic attributes (Ouenes et al. 1995; Zellou et al. 2003; Bloch et al. 2003). Both supervised and unsupervised statistical techniques aim at determining some global attribute of dispersed fractures, such as density. It is often fracture corridors, however, rather than dispersed fractures that are characterized as the main reservoir heterogeneity (Ozkaya and Richard 2006). An FC is a tabular, subvertical, fault-related fracture swarm that intersects the entire reservoir and extends laterally for several tens or hundreds of meters (Fig. 1). FCs could be fluid-conductive or cemented. In this paper, an FC denotes a fluid-conductive FC unless otherwise specified. FCs may have significant conductivity and may play a major role in reservoir dynamics by providing pressure support and, therefore, causing early water breakthroughs and increased gross rates. The four main requirements to map an FC are location, strike, length, and conductivity. Here, we focus primarily on locating FCs and discuss only briefly how other attributes can be estimated. Our objective is not the actual mapping of FCs but examining Bayesian decision trees as a viable technique in FC identification. The basis and procedures for calculating conditional probabilities, entropy, information Gain (IG), and the construction of decision trees are explained in the Appendix.

Running pulsed-neutron logs in Malaysia has previously been plagued by results with high uncertainties, especially in brown fields with complex multistacked clastic reservoirs. Together with a wide range of porosities and permeabilities, the acquired logs quite often tended to yield inconclusive results. In addition, the relatively fresh aquifer water (where salinity varies from 5,000 to 40,000 ppm) makes reservoir fluid typing and distinguishing between oil and water even more challenging. As a result, the inconsistencies and uncertainties of the results tend to leave more questions than answers. Confidence in using pulsed-neutron logging, especially to validate fluid contacts for updating static and dynamic reservoir models, deteriorated within the various study teams. Due to this fact, the petrophysics team took the initiative to conduct a three-tool log off in one of their wells with the objective of making a detailed comparison of three pulsed-neutron tools in Malaysia’s market today. The main criteria selected for comparisons were the consistency of the data, repeatability, and statistical variations. With recent advancements in pulsed-neutron (multidetector) tool technology, newer tools are being equipped with more efficient scintillation crystals, improving the repeatability of the measurements as well as the number of gamma ray (GR) count rates associated with the neutron interactions. In addition, the newer tools now have up to five detectors per tool, with the farthest detector supposedly being able to “see” deeper into the formation, albeit at a lower resolution. With these new features in mind, the log off was conducted in a single well with a relatively simple completion string (single tubing, single casing), logged during shut-in conditions only, and the logs were acquired directly one after the other (back to back) to avoid bias to any particular tool. Both sigma and spectroscopy measurements were acquired to compare the capabilities of each tool. Due to the relatively freshwater salinity, the carbon-oxygen (C/O) ratio from the spectroscopy measurements is used to identify the remaining oil located in the reservoirs, while the sigma measurements determine the gas-oil or gas-water contact, if present. This paper will illustrate the steps taken by Petronas Carigali Sdn Bhd (PCSB) to compare the raw data and interpreted results from the three pulsed-neutron tools. Consequently, a comparison from all the tools was made to the current understanding of the reservoir assessed. The points from these comparisons will then show which tools are favored over the rest.

Summary Water-injection-induced fractures are key factors influencing successful waterflooding projects. Controlling dynamic fracture growth can lead to largely improved water-management strategies and, potentially, to increased oil recovery and reduced operational costs (well-count and water-treatment-facilities reduction), thereby enhancing the project economics. The primary tool that reservoir engineers require to guarantee an optimal waterflood field implementation is an appropriate modeling tool, which is capable of handling the dynamic fracturing process in complex reservoir grids. We have developed a new modeling strategy that combines fluid flow and fracture growth in one reservoir simulation. Dynamic fractures are free to propagate in length and height-direction with respect to poro- and thermoelastic stresses acting on the fracture. A prototype simulator for contained fractures was tested successfully. We have extended the coupled simulator to incorporate noncontained fractures. The new simulator, called FRAC-IT, handles fracture-length and -height growth by evaluating a fracture-propagation criterion on the basis of a Barenblatt (1962) condition. The solution of the 5D problem is computed by use of a tuned Broyden (1965) approach. We demonstrate the capabilities of the coupled simulator by showing its application to a complex reservoir-simulation model. The fracture modeling is used to history match an injectivity test in a five-spot injection pattern using produced water. The coupled-simulation results and the field-data interpretation show a very good match. The outcome of the injection test led to an appropriate waterflood-management strategy adapted to the specific reservoir conditions and, in terms of production, to a net oil-production increase of 50 to 100%. The field example shows how the coupled-simulator technology can be used to achieve optimized waterflood-management strategies and increased oil recovery. Introduction Waterflooding is often applied to increase the recovery of oil in mature reservoirs or to maintain the reservoir pressure above bubblepoint in the case of green fields. Even though often unnoticed, water injection frequently is taking place under induced-fracturing conditions. The rock fracturing has a strong influence on the water injectivity and the areal distribution of the fluids in the reservoir. A qualitative example of the impact of the fracture orientation on the areal sweep is demonstrated in Fig. 1. We show streamlines in two different water-injection-pattern configurations for two fracture orientations (i.e., line-drive and five-spot geometry, and fracture oriented toward the producer and away from the producer. The density of the streamlines indicates that the fracture orientation changes the areal sweep. In order to achieve optimized water-injection management, dynamic fracture propagation needs to be estimated properly before the injection, controlled during operations, and monitored to ensure predictions and reality do not deviate significantly. The tools commonly used to study fracture growth numerically are analytical fracture simulators, which often are based on a single-well model in a simplified reservoir formation. Generally, reservoir heterogeneity is reduced to a number of horizontal layers with homogeneous properties and a laterally infinite extent. Fracture propagation is described using a pseudo-3D description (van den Hoek et al. 1999). For many field developments under waterflooding, fracture propagation is estimated with acceptable error bars using these or similar tools. The major drawbacks areAreal reservoir heterogeneity is not accounted for.Varying poro- and thermoelastic stresses along the fracture are neglected.Injection pressures have large error bars because the reservoir response is not properly captured.Nearby well's influences (e.g., pattern flood) are not captured. In the past, many attempts have been made to address these issues. Common approaches can be grouped into fully implicit simulators (Tran et al. 2002), where both fluid-flow and geomechanical equations are solved simultaneously on the same numerical grid, and coupled simulators (Clifford et al. 1991), where a standard, finite-volume reservoir simulator is coupled to a boundary-element-based fracture-propagation simulator. To our knowledge, both approaches are not standard and currently not used in the industry becauseModels need to be purpose built (i.e., reservoir models from standard reservoir simulator cannot be used).Fracture propagation is oversimplified.Numerical stability is questionable. We have developed an extension to an existing reservoir simulator to circumvent these shortcomings. We use a coupled-simulator approach based on a two-way communication strategy between the fully numerical reservoir simulator and the half-analytical geomechnical-modeling part. The new simulator enables the modeling of fluid flow and dynamic fracture propagation in a combined way. We have applied the tool to field applications for waterflooding projects in which injector/producer shortcuts are a potential risk (pattern floods) and also to environments in which fracture containment and estimating accurate injection pressures are the main concerns. In this paper, we briefly review the coupled-simulator approach and discuss the application to a waterflooding field example.

Thesis (M.S.)--West Virginia University, 2006.
Title from document title page. Document formatted into pages; contains xx, 159 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 64-65).

Formulamos um modelo simplificado para o estudo do processo de injeção de solvente em reservatórios de petróleo, onde o fluido injetado (um ácido) tem a capacidade de dissolver parcialmente a matriz sólida. Como hipóteses principais, consideramos que o solvente e o soluto (componente químico que constitui o meio poroso) são espécies totalmente miscíveis, a viscosidade da mistura solvente + soluto não varia com a concentração de soluto, há significativa transferência de massa entre as fases e a permeabilidade do meio poroso varia linearmente com a porosidade. O modelo é formado por duas Equações Diferenciais Parciais, uma do tipo Convecção-Difusão a outra é do tipo Convecção-Reação. Para resolução numérica, desenvolvemos uma metodologia que denominamos de EPEC (Explícita Porosidade e Explícita Concentração). Tal metodologia se baseia em um limitador de fluxo do tipo TVD e em diferenças finitas centradas de segunda ordem. Em adição, o EPEC emprega uma técnica de separação de operadores. Deste modo, em cada passo de tempo, realizamos inicialmente o cálculo explícito da porosidade seguido do cálculo explícito da concentração do solvente. Assim, obtemos um desacoplamento natural das equações que descrevem o problema. Resultados de simulações são apresentados para um meio poroso bidimensional, após sessenta dias de injeção de solvente.
We formulate a simplified Model to study the process of solvent injection in petroleum Reservoir, where the injected fluid (an acid) can partially dissolve a solid matrix. As prime hypotheses, we considered that solvent an soluble component are completely mixed, the viscosity of the fluid does not vary with the concentration of the soluble component, theres significant transfer of mass between the parts and, the permeability of media porous changes linearly with porosity. The model is formed by two Partial Differential Equation, one is convection-diffusion type and another is a convection-reaction type. The Numerical Resolution weve developed a method called EPEC (Explicit Porosity Explicit Concentration). Such methodology is based upon a Limiting of Flow of TVD type and, used Centered Finite Differences of second order. In addition, the EPEC use a operators separation technique. This way, every time, first we clearly calculate the porosity and then the concentration of solvent is calculated. Thus we obtain a natural decoupling of the equations that describe the problem. Simulation results are presented to a two dimensional media porous after sixty days of solvent injection.

Conselho Nacional de Desenvolvimento Científico e Tecnológico
Neste trabalho é apresentado um novo procedimento numérico para o upscaling de permeabilidade utilizando condições de contorno periódicas. Este procedimento combina decomposição de domínio com elementos finitos mistos na discretização do problema local de pressão-velocidade necessário para se encontrar as permeabilidades equivalentes.
A new numerical method is proposed for the permeabilities upscaling take into consideration periodic boundary conditions. This method combines domain decomposition with mixed finite elements in discretization of the local problem of pressure-velocity necessary to meet the equivalent permeabilities.

This work is concerned with the application of finite difference simulation to modelling the pressure response in partially penetrating oil wells. This has relevance to the oil and hydrology industries where pressure behaviour is used to infer the nature of aquifer or reservoir properties, particularly permeability. In the case of partially penetrating wells, the pressure response carries information regarding the magnitude of permeability in the vertical direction, a parameter that can be difficult to measure by other means and one that has a direct influence on both the total volumes of oil that can be recovered and on the rate of recovery. The derivation of the non-linear differential equations that form the basis for multiphase fluid flow in porous media is reviewed and it is shown how they can be converted into a set of finite difference equations. Techniques used to solve these equations are explained, with particular emphasis on the approach followed by the commercial simulation package used in this study. This involves use of Newton's method to linearize the equations followed by application of a pre-conditioned successive minimization technique to solve the resulting linear equations. Finite difference simulation is applied to a hypothetical problem of solving pressure response in a partially penetrating well in an homogenous but anisotropic medium and the results compared with those from analytical solutions. Differences between the results are resolved, demonstrating that the required level of accuracy can be achieved through selective use of sufficiently small grid blocks and time-steps. Residual discrepancies with some of the analytical methods can be traced to differences in the boundary conditions used in their derivation. The simulation method is applied to matching a complex real-life well test with vertical and lateral variation in properties (including fluid saturation). An accurate match can be achieved through judicious adjustment of the problem parameters with the proviso that the vertical permeability needs to be high. This suggests that the recovery mechanism in the oil field concerned can be expected to be highly efficient, something that has recently been confirmed by production results.
Thesis (M.Sc.)-University of Natal, Pietermaritzburg, 2002.

This monograph presents the basics of super-element modeling method of two-phase fluid flows occurring during the development of oil reservoir. The simulation is performed in two stages to reduce the spatial and temporal scales of the studied processes. In the first stage of modeling of development of oil deposits built long-term (for decades) the model of the global dynamics of the flooding on the super-element computational grid with a step equal to the average distance between wells (200-500 m). Local filtration flow, caused by the action of geological and technical methods of stimulation, are modeled in the second stage using a special mathematical models using computational grids with high resolution detail for the space of from 0.1 to 10 m and time — from 102 to 105 C. The results of application of the presented models to the solution of practical tasks of development of oil reservoir. Special attention is paid to the issue of value transfer in filtration-capacitive properties of the reservoir, with a detailed grid of the geological model on the larger grid reservoir models. Designed for professionals in the field of mathematical and numerical modeling of fluid flows occurring during the development of oil fields and using traditional commercial software packages, as well as developing their own software. May be of interest to undergraduate and graduate students studying in areas such as "Mechanics and mathematical modeling", "Applied mathematics", "Oil and gas".

Abstract Characterization of the rock and fluids is an essential step in screening a reservoir for Low-Salinity Water Flooding (LSWF). A detailed characterization of rock and fluid properties using appropriate methods is being presented for LSWF in a low-permeability deep carbonate reservoir together with a critical analysis of findings. The techniques used are assessed against other possible alternative methods, with inferences drawn on advantages and disadvantages of each to better interpret and apply data so gathered. In so doing, discussions on their key features as to how they can be used effectively and efficiently to screen a reservoir for LSWF are also provided. Such integration of results with other available reservoir and production data should result in a comprehensive description of the target reservoir, and it will help interpret the mechanisms and process dynamics more reliably during a low-salinity waterflood. This integration should allow us not only to gain confidence on the experimental studies but could also help optimize the key parameters responsible for formulating a more robust, reliable and representative regime for tests relevant to the LSWF prior to its eventual implementation in the field. To authors’ knowledge, such integration of experimental studies has not yet been reported in the literature, particularly for the tight carbonate reservoirs with highly paraffinic oil.

Computational Fluid Dynamics (CFD) is a powerful engineering tool that has different applications in the Petroleum Industry. In recent years, CFD has been used to analyze the complex 3D multiphase flow inside production separators. Due to changing reservoir conditions oil companies replace old internals with upgraded ones. In this study, a numerical simulation of the turbulent multiphase flow using the Discrete Phase Model (DPM) is used to assess the effects of the oil droplet size distribution on the oil carry-over in a production separator. Liquid droplet size distributions, meant to represent fine and coarse populations of oil droplets, were generated at the inlet of the separator within the range of sizes recommended in the literature for design purposes. The DPM model accounts for the key phenomena of droplets coalescence and breakup. Although the real case includes three phases, the present DPM simulations do not account for the water phase due to its negligible volume fraction and its prevailing gravitational settling compared to the carry-over effect. The new internals included; an inlet device known as Schoepentoeter, agglomerator, parallel-plates coalescer, and cyclonic mist extractor. Unlike many of the CFD studies reported in the literature, usually representing the internals by numerical models for simplicity, the internals of the separator were replicated with the maximum of geometrical details in this study. The present work was compared with field tests and previous numerical simulations using the Population Balance Model PBM. The PBM simulations considered the whole separator volume and the presence of three phases (gas, oil, water). The mean residence time obtained from the simulations agreed reasonably with some of the results published in the literature using semi-empirical formulas and experiments. The new internals were seen to promote droplet coalescence with minimal breakup. The new inlet device (Schoepentoeter), in particular, was found to contribute considerably to the coalescence of droplets and, hence, to separation.

Liquid loading in gas wells is a phenomenon where the liquid content of the well is sufficient to create a back pressure (usually dominated by gravitational pressure changes) which restricts, and in some cases even stops, the flow of gas from the reservoir. Liquid loading is an all too common problem in mature gas fields around the world. It is estimated that in the U.S.A. alone, at least 90% of the producing gas wells are operating in liquid loading regime. The phenomenon is more detrimental in tight wells than in prolific wells and it poses a serious problem in subsea tie-backs, where back pressure effects through the risers and the flowlines may have an important role. Such is the importance of liquid loading; the oil and gas industry has devoted a lot of attention to the alleviation of the problem using various measures. However, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to how these flows interact with those in the reservoir. It is this latter dynamic interaction that has received the least attention by the industry. Reliable predictive models to link the well dynamics with the intermittent response of a reservoir, that is typical of liquid loading in gas wells, remain unavailable. This paper introduces the complexity of liquid loading and critically reviews recent attempts to model liquid loading and the dynamic interactions between reservoir and wellbore. The paper then illustrates the need for a better understanding of the transient flow phenomena taking place in the near-wellbore region of the reservoir. This includes re-injection of the heavier phase, a phenomenon that has yet to be proven by fluid mechanics.

Abstract Sand erosion is a severe problem during the transportation of oil and gas in pipelines. The technology of multiphase transportation is widely applied in production, due to its high efficiency and low cost. Among various multiphase flow patterns, annular flow is a common flow pattern in the transportation process. During the transportation of oil and gas from the hydrocarbon reservoir to the final destination, the flow direction of the mixture in pipelines is mainly changed by the bend orientation. The bend orientation obviously changes the distributions of the liquid film and sand particles in annular flow, and this would further affect the sand erosion in elbows. Computational Fluid Dynamics (CFD) is an efficient tool to investigate the issues of sand erosion in multiphase flow. In the present work, a CFD-based numerical model is adopted to analyze the effects of bend orientation on sand erosion in elbows for annular flow. Volume of Fluid (VOF) method is adopted to simulate the flow field of annular flow, and sand particles in the flow field are tracked by employing Discrete Particle Model (DPM) simultaneously. Then, the particle impingement information is combined with the erosion model to obtain the maximum erosion ratio. The present numerical model is validated by experiments conducted in vertical-horizontal upward elbows. Finally, the effects of various bend orientations on the erosion magnitude are investigated according to the numerical simulations.

Abstract Increase recovery from mature oil reservoirs requires the definition of enhanced reservoir management strategies, involving the implementation of advanced methodologies and technologies in the field's operation. This paper presents a digital workflow enabling the integration of commonly isolated elements such as: gauges, flowmeters, inflow control devices; analysis methods and data, used to improve scientific understanding of subsurface flow dynamics and determine improved operational decisions that support field's reservoir management strategy. It also supports evaluation of reservoir extent, hydraulic communication, artificial lift impact in the near-wellbore zone and reservoir response to injected fluids and coning phenomenon. This latest is used as an example to demonstrate the applicability of this workflow to improve and support operational decisions, minimizing water and gas production due to coning, that usually results in increasing production operation costs and it has a direct impact decreasing reservoir energy in mature saturated oil reservoirs. This innovative workflow consists on the continuous interpretation of data from downhole gauges, referred in this paper as data-driven; as well as analytical and numerical simulation methodologies using real-time raw data as an input, referred in this paper as model-driven, not commonly used to analyze near wellbore subsurface phenomena like coning and its impact in surface operation. The resulting analyses are displayed through an extensive visualization tool that provides instant insight to reservoir characterization and productivity groups, improving well and reservoir performance prediction capabilities for complex reservoirs such as mature saturated reservoirs with an associated aquifer, where undesired water and gas production is a continuous challenge that incorporates unexpected operational expenses.

Abstract The recent trend in the oil industry is to save CAPEX and exploit every offshore field to increase production and maximize reserves. Also, deeper water and longer step-out is a challenge for new fields. The most adapted technology to unlock these reserves is the use of subsea boosting like a multiphase pump on the seafloor. Subsea boosting has been used for decades with well proven results, but up to now, some limitations in power and lift pressure exist. This new multiphase pump development has increased the potential pressure generation manyfold from the typical ΔP of 50 bar (725 psi) at the beginning of the project. Developing such a powerful two-phase pump driven by a liquid-filled motor requires a unique combination of expertise in machinery engineering, electrical engineering, fluid mechanics and rotor dynamics. The objective of the co-authors is to share this experience by bringing some insights on what it takes to develop, test, and qualify such specific product. Outlines of the methodology will be described, key results will be detailed, and lessons learnt will be presented. The new design was fully tested first component-wise and then for a full-size prototype. A wide process envelope was mapped during the final qualification program with 3,000 points tested in the range 2,000-6,000 RPM and 0 - 100% GVF (Gas Volume Fraction). Qualification tests concluded with more than 2,000 cumulative hours. The main challenges in this program were the development of an innovative multiphase impeller and the qualification of the first MPP (MultiPhase Pump) with a back-to-back configuration. Concerning the motor, the development includes a high speed 6,000 RPM, 6 MW liquid-filled induction motor and a new stator winding insulation cable. With this new product, the pump market is ready to overcome challenges to produce deeper and further reservoirs in a constant evolutive oil and gas market.

The interaction of the wake between pairs of long flexible cylindrical structures is of major consequence in the design of offshore oil and gas production facilities. Modern designs of these facilities often utilize arrays of flexible pipes (risers) extending from the mean water line to the mud-line and then to the subsea reservoir. As ocean currents interact with these structures, wakes are formed at the upstream structure and propagate to the downstream structure (a perturbed flow-field) resulting in a modified force on the downstream structure. This effect, known as the shielding effect, needs to be properly accounted for during the design of offshore facilities. Conservative yet realistic estimates of the effect of separation between the structures under a variety of ocean currents are sought. It is common industry practice to evaluate the clearance between a pair of long flexible cylindrical structures using a finite element based tool. Hydrodynamic loads are based on experiments on a pair of short rigid cylinders. Recent advances in Computational Fluid Dynamics (CFD) technology have made it cheaper and quicker to perform simulations of these conditions without compromising the underlying physics. This alternative is preferred to more expensive and time consuming physical prototype experiments. This paper presents the results of high resolution, time accurate CFD simulations used to understand and quantify the wake interaction between a straked cylinder and a cylinder mounted with the AIMS Dual Fin Splitter (ADFS). No prior experimental data were available for the riser configurations and conditions that were investigated. The simulations were performed using prototypic current velocities and geometries. This paper will describe the CFD technology used in detail. The paper will cover the model setup, the extent of and discretization of the model, the choice of time-step, the boundary conditions, and a discussion on the results from the simulation.

In oil field applications, the Electrical Submersible Pumping (ESP) unit (comprised of multistage pump, seal and motor) is placed inside a wellbore to provide necessary energy to lift reservoir fluids from the formation to the surface when the energy in the reservoir is not sufficient to lift the fluid to the surface. ESP motors produce heat while operating. The motors are cooled by the well fluid that passes the motor while being pumped. Many well fluids have very limited heat carrying capacity, resulting in higher operating temperature within the motor. Only a limited number of studies have been conducted that have analyzed the inside temperature rise in the motor. A parametric study has been conducted using the computational fluid dynamic software Ansys CFX to examine the profile of the temperature rise in the motor. The computational model is validated by experimental data which showed that the computational model predicts the temperature with 95% accuracy. Therefore, this computational model effectively represents the experimentally determined temperature distribution of the motor.

In mature reservoirs, the goal is to increase oil mobility and decrease water mobility. As a result, oil production will be increased and unwanted water production will be decreased. Surfactant and alkaline are widely used to change the wettability of reservoir rocks from oil wet to water wet. Viscosity measurements are important in finding out the impact viscous fluids on enhanced oil recovery (EOR). This project focuses on the viscosity measurements of various mixed fluids used in oil-fields to enhance oil recovery. Two types of surfactants (A and B) and one type of alkaline were utilized throughout the work. In addition, different types of oil obtained from different areas were implemented. The viscosity of these mixed fluids was measured while observing the implications of using varying surfactant and alkaline concentrations. Lastly, the effect of temperature on fluid viscosity was monitored.

Negative pressure is one of the metastable states of liquids at which it can be extended up to a certain limit without a gap of continuity. There are numerous experimental studies where a negative pressure up to 40 MPa has been obtained at laboratory conditions. However, these results of the experimental works were not practically implemented, as real liquids both in the nature and the technological processes contain impurities. Under certain kinetic and hydrodynamic conditions the waves of negative pressure in real liquids (crude oil, water, and water-based solutions) were observed. The wave of negative pressure is a turned soliton wave with one negative hump. It is a conservative wave, which maintains its shape and dimensions, and travels long distances with the speed of sound. An advanced technology of generation of the negative pressure wave in real systems allowed creating completely new energy saving technology. This technology based on negative pressure phenomenon has been already used for increasing oil production efficiency during various oil well operations, cleaning of oil well bore, and pipelines from various accumulations. It is shown that a new technology has a lot of potentials for bottom-hole cleaning operations, oil recovery enhancement, pipeline transportation, gas-lift operation etc. Negative pressure is known to be one of the metastable states at which liquids can be extended up to a certain limit. Theoretic evaluations show that in pure liquids negative pressure may reach large values while the liquid may stand significant extending efforts. For instance, the maximum negative pressure that may be sustained by ideally pure water is estimated as −109N/m2. It means that an imaginable rope of completely pure water with the diameter of 0.01m can sustain a huge extending effort more than 105 N. It is evident that the real experimental values of negative pressure are much less than the corresponding theoretic estimations. It is connected with the impossibility of obtaining ideally pure liquids without any “weak places” (gas bubbles, admixture, etc) and with the circumstance that in experience, the rupture often happens not in the liquid volume but on the surface touching the walls of the vessels weakened by the existence of thin films, embryos, etc. There are numerous results of the experimental work of static and dynamic character, where negative pressure has appeared in one or another degree [1]. In laboratory conditions, negative pressure apparently was first revealed in the experiences made by F. M. Donny (1843), who used degassed sulfuric acid and obtained negative pressure only −0.012 MPa. Among the further attempts of receiving bigger negative pressure, it is worth mentioning the experiences made by O.Reynolds, M.Bertelot and J.Meyer. Basing upon a centrifugal method and using mercury, L.J.Briggs obtained the record value of negative pressure (−42.5 MPa). But as a matter of fact, beginning from the first experiences by F. M. Donny, the main condition in the investigations for the appearance of negative pressure has been the homogeneous character of the liquid and high degree of the purity the liquid-vessel system. Significant values of negative pressure has been obtained under those conditions, however these results of a great scientific importance have no effective applications in practice as real liquids in Nature and technological processes are heterogeneous multicomponent systems. A long-term experimental work has been done to generate negative negative pressure in real liquid systems and investigate influence of this state on thermohydrodynamical characteristics of natural and technological processes [2,3]. Basing on the idea that negative pressure can be created due to the sudden character of extending efforts a direct wave of the negative pressure in real liquids (water, oil, solutions etc.) have been obtained experimentally. For impulsive entering into metastable (overheated) zone in a phase diagram “liquid-vapor” the pressure should drop so fast that the existing centers of evaporation (bubbles, embryos, admixtures etc.) would not be able to manifest themselves for this period. In these terms purity of the liquid is not decisive, and herewith there might exist states of an overheated liquid with the manifestation of negative pressure. It was determined that wave of the negative pressure resembling overturned soliton wave with one but negative peak propagates with speed of sound. The typical variation of the pressure in the petroleum stream in pipe is given in Figure 1. Reversed wave of the negative pressure was not recorded during the experiments. Evidently this is associated with considerable structural changes in the liquid after the passing of the direct wave. The arising negative pressure though being a short-term, results in a considerable overheating of the fluid system and leads to spontaneous evaporation and gas-emanation with the further cavitation regime. It was determined that after passing of the negative pressure wave hydraulic resistance in the system becomes much less, and significant increase of permeability of the porous medium and intensification of the filtration process take place. On the base of the investigations it was made a conclusion that any discharge in the hydraulic systems when the drop of the pressure requires much less time that relaxation of the pressure in the system inevitably results in the arising of rarefaction wave, in particular, the negative pressure wave [4]. The larger is the hydraulic system and the higher is the depression of the pressure, the more intensively the negative pressure wave may manifest itself. In certain terms waves of the positive pressure may be reflected from free surfaces, different obstacles, from contact surfaces between phases in the form of the reverse wave of the negative pressure. On this base there were presented numerous theoretical and experimental works on the simulation of the process, investigation of impact of the negative pressure on certain physical features of real systems [5]. The negative pressure wave may lead to very hard complications: showings of oil and gas leading sometimes to dreadful open fountains, borehole wall collapse, column crushing, gryphon appearance [6]. Analysis of numerous facts of complications, troubles in wells as water-oil-gas showings, crushing of columns, collapses, gryphon formation demonstrates that they arise usually as a result of round-trip operations in drilling of wells and their capital repairs. The negative pressure wave may be initiated by a sudden pulling of pipes or drilling equipment, as well as their sudden braking, quick opening of a valve at the well exit, etc, resulting in metastable extension of the working fluid agent. Though impulse negative pressure manifests itself as a significant dynamic factor, its structural consequences are more dangerous for an oil well. Moving along a well the negative pressure wave results in the spontaneous boiling of the water in the drilling fluid, and as a result of considerable reduction of its specific weight the hydrostatic column is “switched-off’ for some seconds and this may be sufficient for oil and gas showings of the well to be appeared accompanied often by crushing of columns and collapsing of wells due to great destroying energy manifestation. Negative pressure waves may be considered also as one of the dominant factors in geophysical processes, especially, in evolution and appearance of volcanic eruptions and earthquakes [7,8]. Extreme dynamic processes in the underground medium as a matter of fact can be considered as a synergetic manifestation of the negative pressure together with other thermohydrodynamical factors. The waves of negative pressure in the underground environment may be initiated by tectonic dislocations and faults as a result of different dynamic processes, dramatic decrease of pressure during the displacement of fluids and rocks. They may arise also in the form of a reverse waves as a result of reflection of ordinary seismic waves from different underground surfaces. On the basis of received results the method of artificial creation of negative pressure waves has been created [4]. The essence of the method is that negative pressure waves can be generated by means of discharge in hydraulic systems (pipes, wells, etc) when the drop of the pressure takes place during the characteristic time much less than that of pressure relaxation in the system. The greater is the volume of hydraulic system and the higher is the depression of the pressure, the more intensively the negative pressure wave may manifest itself. This method was taken as a basis of elaboration of principally new technologies and installations to increase effectiveness and efficiency of some oil recovery processes. It has been worked out and widely tested in field conditions new technologies on using of the negative pressure phenomenon for cleaning of oil producing hydraulic systems/well bore, pipeline/from various accumulations and increasing of effectiveness of oil producing at different well operation methods. The technology provides generation negative pressure waves in the well using the special mechanisms that leads to the shock depression impact upon the oil stratum, and as a result, to considerable growth in the oil influx, bottom-hole cleaning, accompanied by essential saving both reservoir and lifting energies, elimination and prevention of sandy bridging, paraffin, silt, water, etc. accumulations. For implementations of these technologies corresponding installations have been elaborated, in part, equipments for cleaning out of oil holes from sand plugs, increasing of efficiency and effectiveness of gas-lift well operations and bottom-hole pumping. In cleaning out of oil-holes from sand plugs the most operative and effective liquidation of different sand plugs irrespective of their rheological character is provided, associated with complete bottom-hole cleaning, essential increase of oil recovery and overhaul period. Elaborated equipment is simple and easy to use. Other comparatively advantageous application of the technology provides increase of efficiency of a gas-lift well operation, expressed in considerable reduction of a specific gas consumption associated with essential increase of oil recovery and overhaul period. The design of the equipment is reliable and simple to service. There are different modifications of the equipment for single-row, double-row lifts in packer and packerless designs. The introduced technologies have passed broad test in field conditions. The operative and complete cleaning of numerous oil wells was carried out, where the altitude of sand plugs varied from 20m to 180m; oil output of wells and their overhaul period have been increased and specific gas discharge reduced significantly.