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Katterbauer, Klemens, Ibrahim Hoteit y Shuyu Sun. "History Matching of Electromagnetically Heated Reservoirs Incorporating Full-Wavefield Seismic and Electromagnetic Imaging". SPE Journal 20, n.º 05 (20 de octubre de 2015): 923–41. http://dx.doi.org/10.2118/173896-pa.
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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.
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von Hohendorff Filho, João Carlos y Denis José Schiozer. "Influence of well management in the development of multiple reservoir sharing production facilities". Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 70. http://dx.doi.org/10.2516/ogst/2020064.
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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.
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Chang, Haibin, Yan Chen y Dongxiao Zhang. "Data Assimilation of Coupled Fluid Flow and Geomechanics Using the Ensemble Kalman Filter". SPE Journal 15, n.º 02 (1 de febrero de 2010): 382–94. http://dx.doi.org/10.2118/118963-pa.
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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.
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Knai, Tor Anders y Guillaume Lescoffit. "Efficient handling of fault properties using the Juxtaposition Table Method". Geological Society, London, Special Publications 496, n.º 1 (2020): 199–207. http://dx.doi.org/10.1144/sp496-2018-192.
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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.
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Masalmeh, Shehadeh K., Issa M. Abu-Shiekah y Xudong Jing. "Improved Characterization and Modeling of Capillary Transition Zones in Carbonate Reservoirs". SPE Reservoir Evaluation & Engineering 10, n.º 02 (1 de abril de 2007): 191–204. http://dx.doi.org/10.2118/109094-pa.
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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.
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Bao, Kai, Mi Yan, Rebecca Allen, Amgad Salama, Ligang Lu, Kirk E. Jordan, Shuyu Sun y David Keyes. "High-Performance Modeling of Carbon Dioxide Sequestration by Coupling Reservoir Simulation and Molecular Dynamics". SPE Journal 21, n.º 03 (15 de junio de 2016): 0853–63. http://dx.doi.org/10.2118/163621-pa.
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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.
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Høier, Lars y Curtis H. Whitson. "Compositional Grading—Theory and Practice". SPE Reservoir Evaluation & Engineering 4, n.º 06 (1 de diciembre de 2001): 525–35. http://dx.doi.org/10.2118/74714-pa.
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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.
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Ozkaya, Sait I. "Using Probabilistic Decision Trees to Detect Fracture Corridors From Dynamic Data in Mature Oil Fields". SPE Reservoir Evaluation & Engineering 11, n.º 06 (1 de diciembre de 2008): 1061–70. http://dx.doi.org/10.2118/105015-pa.
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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.
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Johare, Dzulfadly, Mohd Farid Mohd Amin, Adi Prasodjo, Sarah M. Afandi y Rusli Din. "New Generation of Pulsed-Neutron Multidetector Comparison in a Challenging Multistack Clastic Reservoir: A Case Study in Brown Field, Malaysia". Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 61, n.º 6 (1 de diciembre de 2020): 585–99. http://dx.doi.org/10.30632/pjv61n6-2020a4.
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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.
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Hustedt, Bernhard, Dirk Zwarts, Hans-Petter Bjoerndal, Rashid A. Al-Masfry y Paul J. van den Hoek. "Induced Fracturing in Reservoir Simulations: Application of a New Coupled Simulator to a Waterflooding Field Example". SPE Reservoir Evaluation & Engineering 11, n.º 03 (1 de junio de 2008): 569–76. http://dx.doi.org/10.2118/102467-pa.
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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.
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Er, V. y T. Babadagli. "Miscible Interaction Between Matrix and Fracture: A Visualization and Simulation Study". SPE Reservoir Evaluation & Engineering 13, n.º 01 (4 de febrero de 2010): 109–17. http://dx.doi.org/10.2118/117579-pa.
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Summary CO2 injection has been applied in naturally fractured reservoirs (NFRs) for the purpose of enhanced oil recovery (i.e., the Wey-burn and Midale fields, Canada; the Wasson and Slaughter fields, USA; and the Bati Raman field, Turkey). The matrix part of these types of reservoirs could potentially be a good storage medium as well. Understanding the matrix/fracture interaction during this process and the dynamics of the flow in this dual-porosity system requires visual analyses. We mimicked fully miscible CO2 injection in NFRs using 2D models with a single fracture and oil (solute)/hydrocarbon solvent pairs. The focus was on the visual pore-scale analysis of miscibility interaction, breakthrough of solvent through fracture, transfer between matrix and fracture, and the dynamics of miscible displacement inside the matrix. First, matrix/fracture interaction was studied intensively using 2D glass-bead models experimentally. The model was prepared using acrylic sheets and glass beads saturated with oil as a porous medium while a narrow gap of 1-mm size containing filter paper served as a fracture. The first contact miscible solvent (pentane) was injected into the fracture, and the flow distribution was monitored using an image-acquisition and -processing system. The produced solvent and solute were continuously analyzed for compositional study. The effects of several parameters, such as flow rate, viscosity ratio (oil/solvent), and gravity, were studied. Next, the process was modeled numerically using a commercial compositional simulator, and the saturation distribution in the matrix was matched to experimental data. The key parameters in the matching process were the effective diffusion coefficients and the longitudinal and the transverse dispersivities. The diffusion coefficients were specified for each fluid, and dispersivities were assigned into gridblocks separately for the fracture and the matrix.
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Golubev, Vasily, Alexey Shevchenko y Igor Petrov. "Simulation of Seismic Wave Propagation in a Multicomponent Oil Deposit Model". International Journal of Applied Mechanics 12, n.º 08 (septiembre de 2020): 2050084. http://dx.doi.org/10.1142/s1758825120500842.
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A seismic survey is perhaps the most common geophysical technique used to locate potential oil and natural gas deposits in the geologic structures. Thanks to the rapid development of modern high-performance computing systems, the computer simulation technology plays a crucial role in processing the field data. The precision of the full-waveform inversion (FWI) essentially depends on the quality of the direct problem solver. This paper introduces a new approach to the numerical simulation of wave processes in complex heterogeneous media. The linear elasticity theory is applied to simulate the dynamic behavior of curvilinear geological layers. In contrast to the conventional approach, the producing oil formation is described in the frame of a porous fluid-filled model. It allows us to explicitly take into account the porosity, oil density, and other physical parameters. The method of setting the physically correct contact conditions between the reservoir and the geological massif based on the transport equation solution for Riemann invariants was successfully implemented. The grid-characteristic method, previously thoroughly verified on acoustic and elastic problems, was adopted. The explicit time-stepping procedure was derived for a two-dimensional case with a method of splitting along coordinate axes. This method guarantees the preservation of the scheme approximation order. The potential application of the new method to a complex model based on the data from the famous Russian oil deposit — the Bazhen Formation — is demonstrated. The seismic responses were registered on the wave fields and synthetic seismograms. The novelty of this paper relates to a uniform approach to the wave propagation simulation in the heterogeneous medium containing contacting subdomains with different rheology types.
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Feder, Judy. "Successful Fishbone Stimulation Completion for an Onshore Oil Field, United Arab Emirates". Journal of Petroleum Technology 73, n.º 04 (1 de abril de 2021): 44–45. http://dx.doi.org/10.2118/0421-0044-jpt.
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This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203086, “First Successful Fishbone Stimulation Completion in Onshore Oil Field in the United Arab Emirates,” by Fernando Quintero, Noor Talib, and Alvaro Jimenez, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. The complete paper describes the operator’s first implementation of fishbone stimulation technology. A multidisciplinary team analyzed the operational procedures, conducted risk assessments and logistical studies, and established contingency plans, technical requirements, and technical limitations. The deployment of the equipment and the production results were a success, overcoming hazard risks and uncertainties and closing gaps from previous, partially effective applications. According to the authors, fishbone stimulation technology will help increase productivity in a well too risky to be hydraulically fractured and beyond the reach of coiled tubing. Background As the industry seeks dynamic changes and novel ideas to increase the productivity of tight, thin reservoirs, fisbone stimulation represents a lower-risk and -cost solution to ensure deep connectivity with the reservoir in situations in which traditional conventional stimulation practices have reached their potential boundaries without achieving crude recovery objectives. The project described in the complete paper is part of a series of field-development projects in United Arab Emirates onshore fields to exceed expectations of the committed production targets. This trial has taken the form of a pilot test for implementing fishbone stimulation for a short duration in other onshore fields. The new approach has already enhanced production up to three times and has provided wellhead pressure support. While this marks a successful beginning, more field trials will be needed to implement wider use of this technology. Fishbone completion stimulation technology is based on the use of subs that are installed in uncemented liner in which each sub features four small-diameter, high-strength tubes called needles (Fig. 1) that can be extended up to 40 ft in length by bullheading acid (Fig. 2). The objective of the technology is to increase well productivity and injectivity by the needles by connecting natural fractures and vertical layers and increasing reservoir contact and effective well-bore radius. To address the deployment challenge, a risk assessment was under taken with the active participation of a multidisciplinary team, including members from the operator (drilling and asset team) and the service company, to ensure that all required precaution inputs were considered. The risk assessment was conducted by identifying the situations that could threaten the deployment and full extension of the needle, a critical aspect of the job. The complete paper describes primary factors such as the following: - Sub-assembly preparation - Running liner to total depth and setting liner hanger - Mixing and handling hydrochloric acid (HCl) - Pumping the acid job - Fluid losses after the acid job - Cleanup runs with fishbasket cutting assembly
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Mur, Alan, César Barajas-Olalde, Donald C. Adams, Lu Jin, Jun He, John A. Hamling y Charles D. Gorecki. "Integrated simulation to seismic and seismic reservoir characterization in a CO2 EOR monitoring application". Leading Edge 39, n.º 9 (septiembre de 2020): 668–78. http://dx.doi.org/10.1190/tle39090668.1.
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Understanding the behavior of CO2 injected into a reservoir and delineating its spatial distribution are fundamentally important in enhanced oil recovery (EOR) and CO2 capture and sequestration activities. Interdisciplinary geoscience collaboration and well-defined workflows, from data acquisition to reservoir simulation, are needed to effectively handle the challenges of EOR fields and envisioned future commercial-scale sites for planned and incidental geologic CO2 storage. Success of operations depends on decisions that are based on good understanding of geologic formation heterogeneities and fluid and pressure movements in the reservoir over large areas over time. We present a series of workflow steps that optimize the use of available data to improve and integrate the interpretation of facies, injection, and production effects in an EOR application. First, we construct a simulation-to-seismic model supported by rock physics to model the seismic signal and signal quality needed for 4D monitoring of fluid and pressure changes. Then we use Bayesian techniques to invert the baseline and monitor seismic data sets for facies and impedances. To achieve a balance between prior understanding of the reservoir and the recorded time-lapse seismic data, we invert the seismic data sets by using multiple approaches. We first invert the seismic data sets independently, exploring sensible parameter scenarios. With the resulting realizations, we develop a shared prior model to link the reservoir facies geometry between seismic vintages upon inversion. Then we utilize multirealization analysis methods to quantify the uncertainties of our predictions. Next, we show how data may be more deeply interrogated by using the facies inversion method to invert prestack seismic differences directly for production effects. Finally, we show and discuss the feedback loop for updating the static and dynamic reservoir simulation model to highlight the integration of geophysical and engineering data within a single model.
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Zapata, V. J., W. M. Brummett, M. E. Osborne y D. J. Van Nispen. "Advances in Tightly Coupled Reservoir/ Wellbore/Surface-Network Simulation". SPE Reservoir Evaluation & Engineering 4, n.º 02 (1 de abril de 2001): 114–20. http://dx.doi.org/10.2118/71120-pa.
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Summary One of the most perplexing and difficult challenges in the industry is deciding how to develop a new oil or gas field. It is necessary to estimate recoverable reserves, design the most efficient exploitation strategy, decide where and when to drill wells and install surface facilities, and predict the rate of production. This requires a clear understanding of energy distribution and fluid movements throughout the entire system, under any given operational scenario or market-demand situation. Even after a reservoir-development plan is selected, there are many possible facility designs, each with different investment and operating costs. An important, but not always considered, fact is that each facility scheme could result in different future production rates owing to various types, sizes, and configurations of fluid-flow facilities. Selecting the best design for the asset requires the most accurate production forecasts possible over the forecast life cycle. No other single technology has the ability to provide this insight, as well as tightly coupled reservoir and facility simulation, because it combines all pertinent geological and engineering data into a single, comprehensive, dynamic model of the entire oilfield flow system. An integrated oilfield simulation system accounts for all dynamic flow effects and provides a test environment for quickly and accurately comparing alternative designs. This paper provides a brief background of this technology and gives a review of a major development project where it is currently being applied. Finally, we describe some recent significant advances in the technology that make it more stable, accurate, and rigorous. Introduction Finite-difference reservoir simulation is widely used to predict production performance of oil and gas fields. This is usually done in a "stand-alone" mode, where individual well performance is commonly calculated from pregenerated multiphase wellbore flow tables that cover various ranges of wellhead and bottomhole pressures, gas/oil ratios (GOR's) and water/oil ratios (WOR's). The reservoir simulator determines the predicted production rate from these tables, normally assuming a fixed wellhead pressure and using a flowing bottomhole pressure calculated by the reservoir simulator. With this scheme it is not possible to consider the changing flow-resistance effects of the piping system as various fluids merge or split in the surface network. Neglecting this interaction of the surface network can, in many cases, introduce substantial errors into predicted performance. Basing multimillion- (in some cases, billion-) dollar exploitation designs on performance predictions that are suboptimal can be very detrimental to the asset's long-range profitability. To help eliminate this problem, considerable attention is being given to coupling reservoir simulators and multiphase facility network simulators to improve the accuracy of forecasting. Landscape Surface-network simulation technology was first introduced in 1976.1 Although successfully applied in selected cases, the concept was not widely adopted because of the excessive additional computing demands on computers of that era. In those earlier applications, the time consumed by the facility calculations could actually exceed the reservoir calculations.2,3 As computer performance has increased by orders of magnitude, this has become less of an issue. Reservoir model sizes have increased dramatically with much finer grids that take advantage of the increased computer power, but there was no need for a corresponding increase in the size of the facility models. Today, with tightly coupled reservoir/wellbore/surface models, the facility calculations are a fairly small part of the overall computing time and there is considerable effort in the industry to build these types of systems.4,5 Chevron's current tightly coupled oilfield simulation system is CHEARS®***/PIPESOFT-2™****. CHEARS® is a fully implicit 3D reservoir simulator with black-oil, compositional, thermal, miscible, and polymer formulations. It has fully implicit dual porosity, dual permeability options, and unlimited multiple-level local grid refinement. PIPESOFT-2™ is a comprehensive multiphase wellbore/surface-network simulator. It has black-oil, compositional, CO2, steam, and non-Newtonian fluid capabilities. It can solve any type of complex nested looping, both surface and subsurface. The coupling is done at the wellbore completion interval, which is the natural domain boundary between the flow systems. We refer to our implementation as "tightly coupled" because information is dynamically exchanged directly between the simulators without any intermediate intervention. A simple representation of the interaction between the simulators is shown in Fig. 1. Gorgon Field Example The following is an example of how this technology is currently being used. The Gorgon field is a Triassic gas accumulation estimated to contain over 20 Tscf of gas, located 130 km offshore northwest Australia in 300 m of water (Fig. 2). It is currently undergoing development studies for an LNG project. Field and Model Description. The field is 45 km long and 9 km wide, and it comprises more than 2000 m of Triassic fluvial Mungaroo formation in angular discordance with a Jurassic-age unconformity. It has been subdivided into 11 vertical intervals (or zones) on the basis of regional sequence boundaries and depositional systems. These 11 zones were first modeled individually with an object-based modeling technique before being stacked into a 715-layer full-field geologic model. This model was subsequently scaled up to a 46-layer reservoir simulation model, reducing the size of the model from 4.5 million cells to 290,000 cells. While the scaleup process preserved the original 11 zone boundaries, the majority of the layers were located in regions identified as key flow units. In addition to vertical subdivision, seismic and appraisal well data suggest structural compartmentalization, resulting in six major fault blocks. After deactivating appropriate cells, the final simulation model contained 50,000 active cells and was initialized with 35 independent pressure regions. Each of these regions corresponds to a single zone in a single fault block.
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Thiele, Marco R. y Roderick P. Batycky. "Using Streamline-Derived Injection Efficiencies for Improved Waterflood Management". SPE Reservoir Evaluation & Engineering 9, n.º 02 (1 de abril de 2006): 187–96. http://dx.doi.org/10.2118/84080-pa.
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Summary This paper describes a novel approach to predict injection- and production-well rate targets for improved management of waterfloods. The methodology centers on the unique ability of streamlines to define dynamic well allocation factors (WAFs) between injection and production wells. Streamlines allow well allocation factors to be broken down additionally into phase rates at either end of each injector/producer pair. Armed with these unique data, it is possible to define the injection efficiency (IE) for each injector and for injector/producer pairs in a simulation model. The IE quantifies how much oil can be recovered at a producing well for every unit of water injected by an offset injector connected to it. Because WAFs are derived directly from streamlines, the data reflect all the complexities impacting the dynamic behavior of the reservoir model, including the spatial permeability and porosity distributions, fault locations, the underlying computational grid, relative permeability data, pressure/volume/temperature (PVT) properties, and most importantly, historical well rates. The possibility to define IEs through streamline simulation stands in contrast to the ad hoc definition of geometric WAFs and simple surveillance methods used by many practicing reservoir engineers today. Once IEs are known, improved waterflood management can be implemented by reallocating injection water from low-efficiency to high-efficiency injectors. Even in the case in which water cannot be reallocated because of local surface-facility constraints, knowing IEs on an injector/producer pair allows the setting of target rates to maintain oil production while reducing water production. We demonstrate this methodology by first introducing the concept of IEs, then use a small reservoir as an example application. Introduction Local areas of water cycling and poor sweep exist as a flood matures. Current flood management is restricted to surveillance methods or workflows centered on finite-difference (FD) simulation, where areas of bypassed oil are identified and then rate changes, producer/injector conversions, or infill-drilling scenarios are tested. However, identifying and testing improved management scenarios in this way can be laborious, particularly for waterfloods with a large number of wells and/or a relatively high-resolution numerical grid. For mature fields that have potential for improved production without introducing new wells or producer/injector conversions, the main goal is to manage well rates so as to reduce cycling of the injected fluid while maintaining or even increasing oil production. Reservoir engineers have no easy or automated way to identify injection patterns, well-pair connections, or areas of inefficiency beyond simple standard fixed-pattern surveillance techniques (Baker 1997; Baker 1998; Batycky et al. 2005). Such methods are approximate at best owing to the need to define geometric allocation factors and fixed patterns, which suffer from "out-of-pattern" flow. These limitations are removed through streamline-based surveillance models (Batycky et al. 2005). By adding a transport step along streamlines, streamline simulation (3DSL 2006) can additionally identify how much oil production results from an associated injector, quantifying the efficiency down to an individual injector/producer pair. It is this crucial piece of information—the efficiency of an injector/producer pair—that allows an improved estimation of future target rates, leading to improved reservoir flood management.
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Patel, M. S., Nurliyana Azizan, M. S. Liew, Zahiraniza Mustaffa, Montasir Osman Ali y Andrew Whyte. "A Numerical Study: Transitional Hydrodynamic Behaviour of a Moored Barge in Different Ultra-shallow Water Depths of Malaysia". Open Civil Engineering Journal 13, n.º 1 (31 de diciembre de 2019): 238–59. http://dx.doi.org/10.2174/1874149501913010238.
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Background: Malaysia has most of its oil reservoirs in the South China sea. The water depth ranges from 50 m to 200 m. The effects of ultra-shallow water are of prime importance in the exploration of marginal oil fields. Hence, there is an increasing demand for understanding the hydrodynamic behavior of FPSO in ultra-shallow water depths. Objective: A simulation study in both frequency-domain and time-domain analyses has been performed to understand the dynamic responses of a moored barge in varying shallow water depths. The objective of this study was to observe the transitional hydrodynamic behavior of the moored barge under varying shallow water depths. Methods: The moored barge was administered under regular and irregular waves. Operating conditions for irregular waves in terms of significant wave height and peak time period were incorporated from PETRONAS Technical Standards (PTS). The wave-body interactions and mooring effects have been numerically modelled using a commercial Computational Fluid Dynamics (CFD) and simulation software (ANSYS AQWA) successfully. In order to gain confidence in the simulation software, additional experimental validation was performed for a FPSO model. Results: Though the barge was primarily free to rotate in all Degrees Of Freedom (DOF), however, only three DOFs were considered for our study; viz, heave, roll and yaw respectively. The force spectral density, cable RAO’s in addition to the time series of cable forces, along with the effect of significant motions on the mooring cables behavior have been discussed. Conclusion: In irregular beam sea state, the significant motions in ultra-shallow water were greater than that for deep waters, this was primarily the main reason for higher cable responses in ultra-shallow water.
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Lumley, D. E. y R. A. Behrens. "Practical Issues of 4D Seismic Reservoir Monitoring: What an Engineer Needs to Know". SPE Reservoir Evaluation & Engineering 1, n.º 06 (1 de diciembre de 1998): 528–38. http://dx.doi.org/10.2118/53004-pa.
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Summary Time-lapse three-dimensional (3D) seismic, which geophysicists often abbreviate to four-dimensional (4D) seismic, has the ability to image fluid flow in the interwell volume by repeating a series of 3D seismic surveys over time. Four-dimensional seismic shows great potential in reservoir monitoring and management for mapping bypassed oil, monitoring fluid contacts and injection fronts, identifying pressure compartmentalization, and characterizing the fluid-flow properties of faults. However, many practical issues can complicate the simple underlying concept of a 4D project. We address these practical issues from the perspective of a reservoir engineer on an asset team by asking a series of practical questions and discussing them with examples from several of Chevron's ongoing 4D projects. We discuss feasibility tests, technical risks, and the cost of doing 4D seismic. A 4D project must pass three critical tests to be successful in a particular reservoir: Is the reservoir rock highly compressible and porous? Is there a large compressibility contrast and sufficient saturation changes over time between the monitored fluids? and Is it possible to obtain high-quality 3D seismic data in the area with clear reservoir images and highly repeatable seismic acquisition? The risks associated with a 4D seismic project include false anomalies caused by artifacts of time-lapse seismic acquisition and processing and the ambiguity of seismic interpretation in trying to relate time-lapse changes in seismic data to changes in saturation, pressure, temperature, or rock properties. The cost of 4D seismic can be viewed as a surcharge on anticipated well work and expressed as a cost ratio (seismic/wells), which our analysis shows ranges from 5 to 35% on land, 10 to 50% on marine shelf properties, and 5 to 10% in deepwater fields. Four-dimensional seismic is an emerging technology that holds great promise for reservoir management applications, but the significant practical issues involved can make or break any 4D project and need to be carefully considered. Introduction Four-dimensional seismic reservoir monitoring is the process of repeating a series of 3D seismic surveys over a producing reservoir in time-lapse mode. It has a potentially huge impact in reservoir management because it is the first technique that may allow engineers to image dynamic reservoir processes1 such as fluid movement,2 pressure build-up,3 and heat flow4,5 in a reservoir in a true volumetric sense. However, we demonstrate that practical operational issues easily can complicate the simple underlying concept. These issues include requiring the right mix of business drivers, a favorable technical risk assessment and feasibility study, a highly repeatable seismic acquisition survey design, careful high-resolution amplitude-preserved seismic data processing, and an ultimate reconciliation of 4D seismic images with independent reservoir borehole data and history-matched flow simulations. The practical issues associated with 4D seismic suggest that it is not a panacea. Four-dimensional seismic is an exciting new emerging technology that requires careful analysis and integration with traditional engineering data and workflows to be successful. Our objective in this paper is to provide an overview of the 4D seismic method and illuminate the practical issues important to an asset team reservoir engineer. For this reason, we do not present a comprehensive case study of a single 4D project here, but instead draw examples from several Chevron 4D projects to illustrate each of our points. We have structured this paper as a series of questions an engineer should ask before undertaking any 4D seismic project: What is 4D seismic? What can 4D seismic do for me? Will 4D seismic work in my reservoir? What are the risks with 4D seismic? What does 4D seismic cost? We answer these questions, highlight important issues, and offer lessons learned, rules of thumb, and general words of advice. What Is 4D Seismic? To describe the basic concepts underlying 4D seismic, we briefly review the seismic method in general6 and then consider the advantages of the time-lapse aspect of 4D seismic. In a single 3D seismic survey, seismic sources (dynamite, airguns, vibrators, etc.) generate seismic waves at or near the earth's surface. These source waves reflect off subsurface seismic impedance contrasts that are a function of rock and fluid compressibility, shear modulus, and bulk density. Arrays of receivers (geophones or hydrophones) record the reflected seismic waves as they arrive back at the earth's surface. Applying a wave-equation-imaging algorithm7 to the recorded wavefield creates a 3D seismic image of the reservoir rock and fluid property contrasts that are responsible for the reflections. Four-dimensional seismic analysis involves simply repeating the 3D seismic surveys, such that the fourth dimension is calendar time,8 to construct and compare seismic images in time-lapse mode to monitor time-varying processes in the subsurface during reservoir production. The term 4D seismic is usually reserved for time-lapse 3D seismic, as opposed to other time-lapse seismic techniques that do not have 3D volumetric coverage [e.g., two dimensional (2D) surface seismic, and the borehole seismic methods of vertical seismic profiling and crosswell seismic9,10]. Four-dimensional seismic has all the traditional reservoir characterization benefits of 3D seismic,11 plus the major additional benefit that fluid-flow features may be imaged directly. To first order, seismic images are sensitive to spatial contrasts in two distinct types of reservoir properties: time-invariant static geology properties such as lithology, porosity, and shale content; and time-varying dynamic fluid-flow properties such as fluid saturation, pore pressure, and temperature. Fig. 1 shows how the seismic impedance of rock samples with varying porosity changes as the pore saturation changes from oil-full to water-swept conditions. Given a single 3D seismic survey, representing a single snapshot in time of the reservoir, the static geology and dynamic fluid-flow contributions to the seismic image couple nonuniquely and are, therefore, difficult to separate unambiguously. For example, it may be impossible to distinguish a fluid contact from a lithologic boundary in a single seismic image, as shown in Frames 1 and 2 of Fig. 2. Examining the difference between time-lapse 3D seismic images (i.e., 4D seismic) allows the time-invariant geologic contributions to cancel, resulting in a direct image of the time-varying changes caused by reservoir fluid flow (Frame 3 of Fig. 2). In this way, the 4D seismic technique has the potential to image reservoir scale changes in fluid saturation, pore pressure, and temperature during production.
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Samier, P., L. Quettier y M. Thiele. "Applications of Streamline Simulations to Reservoir Studies". SPE Reservoir Evaluation & Engineering 5, n.º 04 (1 de agosto de 2002): 324–32. http://dx.doi.org/10.2118/78883-pa.
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Summary Computer models of oil reservoirs have become increasingly complex in order to represent geological reality and its impact on fluid flow. Memory and CPU time limitations by finite-difference (FD)/ finite-volume (FV) simulators force a coarser resolution of reservoir models through upscaling. Upscaling can lead to significant difficulties in reservoir studies:while the fine-scale geological model is built from petrophysical, log, and seismic data, its dynamic behavior is never checked. As a result, a coarse-scale reservoir study can be linked to a fine-scale geological model, but the two might be inconsistent in their dynamic behavior.Conversely, the upscaled model cannot be properly tested because the flow and production behavior at the fine-scale level are not available. There is no reference solution for guiding important decisions for building a consistent upscaled model.A large number of sector models are required in designing optimal well patterns. Streamline simulation is now an attractive alternative to overcome some of these drawbacks because it offers substantial computational efficiency while minimizing numerical diffusion and grid-orientation effects. It allows the integration of fine-scale geological models into the reservoir engineering workflow. In this paper, we demonstrate the usefulness and efficiency of a streamline simulator in the reservoir engineering workflow. We evaluate its speed, memory requirements, and scalability using tracer and black-oil-test data sets on an SGI Origin 2000™* (250 MHz MIPS). Our data are based on real fields and range from 200,000 to 7 million cells, with cells as small as 30×30×0.5 m. Streamlines allowed us to check the validity of a large geological model and to optimize well patterns with more than 30 producers and injectors. We demonstrate how streamline-based simulation has matured from a research tool to an industrial application providing real benefits to engineers as a complementary tool to existing conventional simulation technology based on FVs. Introduction Dynamic flow simulation is still a bottleneck in most integrated reservoir studies that attempt to reconcile the geological model with seismic data and well data. Three-dimensional, high resolution (3DHR) seismic data, as well as improved 3D static modeling tools, produce models that are ever more detailed and allow significantly more faults than the previous generation of static models. Today's fine-scale models are commonly in the range of 1 to 10 million cells. On the other hand, flow simulation technology based on FVs or FDs is mature. Any improvements are expected mainly from parallel processing of key modules, such as the simultaneous solution of the linearized flow equations or PVT calculations. As a result, only relatively small dynamic models (100,000 active cells) can be considered in routine engineering studies. Dynamic flow simulation also has suffered from recent cost cutting by reserving large-scale computing power (machines with more than 1,000 processors) for seismic processing while shifting most other simulations to PC clusters with a limited number of processors (8 to 32). Upscaling fine-scale geological models remains a reality for most studies, causing significant deterioration in the geological model. In many cases, the fine-scale and coarse-scale models do not superimpose, with coarse blocks being traversed by fine-scale faults. Under realistic reservoir conditions, rigorous upscaling becomes difficult, forcing the engineer to make dubious approximations (fault location and transmissivity, layer resampling, etc.). The fact that these approximations often cannot be quantified because a fine-scale reference solution is not available makes matters worse. A methodology that allows for solutions to the original geological model is therefore desirable, allowing some quantification of errors caused by upscaling. Streamline-based reservoir flow simulation is one alternative currently available.1,2 Streamline Simulation vs. FV Simulation Streamline-based flow simulation has made significant advances in the past 10 years. Today's simulators are fully 3D1,3 and account for gravity1,4 as well as for complex well controls. Most recent advances also allow for compressible flow and compositional displacements.5,6 A number of recent publications demonstrate how streamline-based simulation is now coming into the mainstream.7–14 FV methods are based on the fundamental concept that fluids are moved from cell to cell. The problem with this methodology is an exponential increase in CPU time, with a linear increase in model size. The reason for this is that larger models dramatically reduce timestep sizes (both in implicit and explicit modes) because of reduced cell volumes and (often) increased heterogeneity. This means that locally higher fluxes have to be pushed through blocks with smaller volumes. Routine solutions of million-cell models with FV or FD technology are, therefore, out of reach for most practical applications. Even with significant simulation power, a single solution can take weeks. Data debugging and sensitivity calculations under these circumstances can become difficult. Streamline-based simulation is an attractive alternative because of the fundamentally different approach in moving fluids. Instead of moving fluids from cell to cell, streamline simulation breaks up the reservoir into 1D systems, or tubes. The transport equations are then solved along the 1D space defined by the streamlines using the concept of time of flight (TOF).15,16 By decoupling the transport problem from the underlying 3D geological model, fluids can be transported much more efficiently. Large timesteps can be taken, numerical diffusion is minimized, and CPU time varies nearly linearly with model size. Description of the Streamline Simulator Modern streamline-based simulation rests on five key principles:tracing streamlines in a velocity field;15writing the mass conservation equations in terms of TOF;16numerical solution of conservation equations along streamlines;17periodic updating of the streamlines;18,2 andoperator splitting to account for gravity.4 Details of the methodology can be found elsewhere;1 we give only a brief overview here.
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Akram, A. H., F. R. Halford y A. J. Fitzpatrick. "A Model To Predict Wireline Formation Tester Sample Contamination". SPE Reservoir Evaluation & Engineering 2, n.º 06 (1 de diciembre de 1999): 499–505. http://dx.doi.org/10.2118/59559-pa.
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Summary Wireline formation testers (WFTs) collect fluid samples for pressure-volume-temperature analysis through a probe set against the borehole wall. Filtrate contamination is reduced prior to sampling by either pumping the mixture of filtrate and reservoir fluid from the formation to the borehole or flowing the mixture into one or more WFT chambers. The cleanup is monitored at the surface. The time to reach the level of acceptable contamination (LAC) depends on the depth of invasion, pumpout rate, and various fluid and rock properties. Generalized guidelines predict time to first oil based on simple volumetrics but do not predict the rate of cleanup. Excessive cleanup time increases costs and the risk of differential sticking of the tool/cable. In some cases it may not be practical to attempt the operation as the LAC may take too long to achieve. A numerical simulator was used to investigate the characteristics of the contamination level versus time curve and to define the variables governing cleanup. The model was validated using data from five wells from two fields with differing rock and fluid properties. One hundred and fifty simulation runs were made with different invasion depths, flow rates, and rock and fluid properties. An equation was developed for field use that estimates filtrate contamination fw as a function of cleanout time t. An alternative approach for WFT sampling is also suggested, using not one but two probes. With this method, both cleanup time and the final level of filtrate contamination can be substantially reduced. Introduction Formation fluid is drawn through the probe and pumped into the wellbore for periods ranging from a few minutes to several hours or more. In this way, formations that were previously too contaminated with mud filtrate to yield useful samples can now be sampled by pumping out fluid until the level of contamination has dropped to an acceptable level. This can provide samples for pressure-volume-temperature analysis from a number of zones before the well is completed. Drill stem or production tests whose main objective was to collect formation fluid samples may no longer be required as a result. The contamination level is monitored continuously until it has reached the level of acceptable contamination (LAC), at which time a set of samples can be taken. The results of a study of near wellbore fluid flow during wireline formation tester (WFT) cleanup prior to sampling are presented. The objective was to predict cleanup time. In this way, it becomes possible to ascertain whether an operation is feasible, in terms of the time to reach LAC, the likely time/cost of the operation, and the consequential associated risks of stuck tools. The proportion of filtrate fw in the formation fluid pumped can be approximated by a function of the following form:1 f w = 1 − • [ 1 − ( t 0 / t ) n ] , where t0 and n are functions of radius of invasion, flow rate, and rock and fluid properties. Geometry of Flow The invaded zone can be visualized as a cylinder, with a hollow center representing the wellbore, and its outer wall representing the end of the invaded zone. Zero fluid movement through the mudcake is assumed. As filtrate is removed from around the probe, it is replaced by fluid in an elliptical flow regime, the geometry of which is dependent upon rock permeability anisotropy. The outer wall of the cylinder, which is the filtrate/oil interface, is also drawn in by the shrinking filtrate body toward the probe leading to a filtrate saturation distribution around the wellbore similar to the shape of an hourglass. The simulator results confirm this. Fig. 1 shows the radial section adjacent to the probe and Fig. 2 shows the section opposite the probe. Water filtrate (cooler colors) can be seen feeding in from above and below, while oil forms a cone directed toward the probe. Both figures show the development of the hourglass filtrate saturation distribution centered upon the probe. Assumptions This study is limited to sampling in vertical wells set in horizontal beds. The rock is homogeneous, and anisotropic. The mud is water based, and the filtrate is brine. The filtrate and the oil are immiscible, and the degree of contamination during cleanup is represented by the watercut. The rock is water wet. Corey relative permeability curves were used in the simulation runs used to test the effect of various parameters on cleanup time. The appropriate field relative permeability data were used when validating the model against the modular formation dynamics tester (MDT)*2 data sets. Appendix A describes the model setup. A Representative Invaded Zone The invaded zone was simulated by injecting water for a duration and rate that gave a radius of invasion obtained from resistivity logs. Pseudoised relative permeability curves were used to create a shock front. Watercut Prediction Five sets of MDT field data were used to validate the model. The optical fluid analyzer (OFA)*2 monitors the relative proportions of oil and water in the flowline with an accuracy of 5%. The observed water fraction during cleanout was compared to that predicted from the simulator. The watercut vs. time can be approximated to a particular function of time. Two points on the watercut curve have been selected as reference points: t0 the time when first oil starts to flow into the probe, and t1 the time when the watercut drops to 10%. Figs. 3 through 8 compare the observed water cut from the OFA data to the simulator results. Matching the Model with Field Data Wells X1, X3, and Y1 are from a field characterized by heavy viscous oil and high permeability rock. The field relative permeability data and fractional flow curves were used to generate the pseudoized relative permeability curves input to the simulations.
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Waggoner, J. R. "Lessons Learned From 4D Projects". SPE Reservoir Evaluation & Engineering 3, n.º 04 (1 de agosto de 2000): 310–18. http://dx.doi.org/10.2118/65369-pa.
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Summary Time-lapse three-dimensional, or four-dimensional (4D), seismic has been under consideration by the industry for reservoir monitoring for more than a decade. It offers the possibility of identifying the interwell distribution of bypassed and untapped oil, of monitoring displacement heterogeneity, and of detecting uneven pressure depletion away from wells. If obtained, these detailed observations could be used to increase ultimate recovery, reduce production costs, and prevent surprises such as unexpectedly early breakthrough. But these benefits are not easily obtained, and are certainly not guaranteed. There are a number of factors that impact whether a 4D project will be successful, and a careful study of these is required to give a realistic expectation of what 4D can do for a specific reservoir. Numerous 4D seismic projects have been active over oil fields world wide, and successes, relative to each project's objectives, have been realized by field operators using a wide variety of data acquisition techniques (land, streamer, and seabed methods), and over a variety of field types, including both clastics and carbonates. This paper draws from this experience to present a generalized 4D project workflow, and reviews results from some of these recent projects as illustrations. In general, sufficient software tools, rock physics data, and experience now exist to conclude that 4D is a low-risk/high-benefit reservoir management tool. The key to a successful project, however, is determining what 4D can do in a specific field, which requires a careful feasibility study, clear reservoir management objectives, and high-quality and experienced seismic processing and interpretation. Introduction Time-lapse three-dimensional (3D), or four-dimensional (4D), seismic has received a great deal of industry attention and activity over the past few years, as evidenced by the number of conferences organized specifically for 4D seismic and by the number of papers presented at more general conferences. In addition, both the Society of Exploration Geophysicists (SEG) and Society of Petroleum Engineers (SPE) designated Distinguished Lecturers in 1998 that presented excellent material regarding 4D techniques1 and the integration of 4D data with other types of data to improve reservoir description.2 These presentations have been well attended all over the world as the industry seeks to learn more about 4D seismic. What's All the Excitement About? The majority of people are probably interested in the ability of 4D to monitor fluid movement within the reservoir, and subsequently to identify bypassed reserves that can be produced through targeted offset drilling. Another commonly stated benefit of 4D is improved characterization of the reservoir to allow more reliable predictions from reservoir simulation studies, especially as it relates to the effectiveness of water or gas injection processes. These are but two of the extremely valuable reservoir management benefits of 4D seismic; others can be found in the numerous papers on the subject. Is the Excitement Justified? As with most things, the answer is both yes and no. As concluded by several authors,1,3-13 4D has potential, and several case histories to date have shown 4D to work to some degree. It is important to recognize that 4D is a simple idea based on physically limited measurements, difficult processing, and a complex earth. In some sense, it is amazing that it ever works, but experience shows that it can work, and it is that experience that forms the basis for the cautious optimism presented in this paper. Planning for Success Western Geophysical and its predecessors have been doing 4D seismic research, development, planning, and commercial projects, since the early 1980's. From that experience has grown a sound understanding of what it takes to do a successful 4D project. This paper is a collection of brief case histories within the framework of the following systematic and generalized 4D work flow: establish a clear reservoir objective; perform a careful feasibility study on the field of interest; do a rapid analysis of existing overlapping datasets; characterize the static reservoir properties; acquire and (re)process new 3D seismic data; analyze time-lapse differences; and characterize the dynamic reservoir properties using 4D results. Most of the cases have been published or presented at recent conferences, to which the reader is referred for more detailed description and analysis. Establish a Clear Reservoir Objective. Two of the general reservoir objectives were mentioned previously, and repeating a longer list would only serve to heighten the expectation that 4D will solve all problems. In fact, there are a large number of problems that surface seismic cannot address because of the physical limitations of the measurement. For example, 4D will never be able to see the movement of a heavy oil/water interface in a 10 ft thick carbonate at 15,000 ft depth under a large gas cloud. Even if it could, that information would only be of use to you if that was the condition in your reservoir. The goal here is to define what needs to be learned about the reservoir so that the 4D project can be properly planned and the results can be measured against whether the needed information was, in fact, provided by the seismic data. To date, most 4D projects have been performed primarily as a geophysical exercise, rather than with a primary reservoir objective, in order to "test" the 4D technique. For these studies, the stated objective is to take two existing 3D datasets, which happen to have some overlap, and see what the difference between them shows. An example of such a rapid analysis is shown in a later section. The most common result is a suggestion of a difference and a recommendation that the datasets be reprocessed, because the acquisition and processing were of different vintages and for different purposes. However, because the objective is not driven by a reservoir need, there are few examples of even a good geophysical result being used to influence a development or production decision. The important point in setting the reservoir objective is that it be set by the reservoir engineer or asset team to gain needed information. Not only is every reservoir different, but the objective for a particular reservoir will change during its development and production lifetime. Once set, the objectives need to be evaluated as part of the feasibility study that follows to avoid unrealistic expectations.
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Blonk, B., R. W. Calvert, J. K. Koster y G. van der Zee. "Assessing the Feasibility of a Time-Lapse Seismic Reservoir Monitoring Project". SPE Reservoir Evaluation & Engineering 3, n.º 01 (1 de febrero de 2000): 80–87. http://dx.doi.org/10.2118/60847-pa.
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Summary We discuss a method to assess if a particular seismic survey may be suitable as a base survey for a time-lapse seismic monitoring project, and to predict if anticipated changes in the reservoir's acoustic properties could be interpreted on a repeat survey. Our approach is to generate a simulated repeat survey using a realistic noise realization estimated from the candidate base survey. This repeat survey contains seismic changes that have been modeled by integrating rock and fluid property data, as well as results from the flow simulator. The method can be used to reduce the risk of shooting a repeat survey on which meaningful seismic changes cannot be interpreted. It can also help in deciding the proper timing for an eventual reshoot. Furthermore, the method is valuable for assessing data quality before quantitative interpretation studies. We show an example from the Middle East illustrating a survey that is unfavorable as a base survey. Furthermore, we show examples from the North Sea where application of the method was key for deciding upon a repeat survey and upon the proper timing of a possible repeat survey. Introduction Time-lapse seismic monitoring is an emerging technology with potentially very large commercial value. By repeat two-dimensional (2D) or three-dimensional (3D) seismic surveys, it aims to monitor seismic changes related to fluid and stress changes during the production of a field.1,2 Hence, this technology has the potential to allow field monitoring between and away from wells. In favorable circumstances, displacement of the fluid fronts may be seen.3,4 Pressure changes may also be detectable showing compartmentalization in a field.5 Improved knowledge of saturation and/or pressure distributions will result in improved dynamic reservoir models, which will help to optimize recovery.6 Sonneland et al.7 and Jenkins et al.8 describe two cases where time-lapse seismic monitoring has led to commercially significant decisions. The technique will work with a high probability of success on fields where the presence of hydrocarbons is already clearly indicated through reflection amplitude anomalies visible in the seismic data. In favorable circumstances, one may recognize waterflood, steamflood, gas cap formation, or bypassed oil. The probability of success of the technique heavily depends on many factors, like reservoir parameters (depth, rock, and fluid properties; pressure; etc.), nature of the recovery processes,9 and on business drivers.10 Repeatability of the different seismic surveys is another important factor; for instance, positioning errors or different offset distributions may result in failure if not accounted for correctly.11 A quick and quantitative approach in assessing the risk of a time-lapse seismic project has been described by Lumley et al.12 This paper focuses on another critical factor, namely, how the non-repeatable noise of the processed seismic data compares itself to the anticipated changes caused by production. The character of this noise may vary in time, as well as in space. Given the quality of the base survey, it can be assessed if seismic monitoring between wells is feasible and, furthermore, after how many years of production one may be able to pick up changes in seismic response. This information can have a high business impact. In specific cases, it may become clear that seismic monitoring is only feasible if the signal-to-noise ratio (SNR) of the seismic data can be increased via more sophisticated processing. We illustrate the application of the method using data from an onshore field in the Middle East (Yibal), and from two offshore fields in the North Sea (Brent and Draugen). Outline of the Method Approach. Our aim is to assess if a particular seismic survey may be suitable as a base survey in a time-lapse seismic monitoring project. Therefore, we need to know if expected acoustic changes (due to production from a reservoir) could be interpreted on a repeat survey, given the quality of the candidate base survey. Our approach is now to create a simulated, but realistic repeat survey consisting of three components:signal,noise, andmodeled seismic change. The signal and noise follow from the candidate base survey and are obtained as follows. Using a sparse spike inversion (SSI) method (explained below) we estimate reflectivities (spikes) that represent the reflectivity of the Earth. These reflectivities are subsequently used to determine the highest-resolution signal that can be determined from the base survey. This signal is component (i) for the simulated repeat survey. The difference between that signal and the base survey yields an estimate of the noise for that survey. Component (ii) is now obtained by changing all noise traces to other grid locations; hence, one obtains a new, realistic noise realization. Component (iii), the expected change, is now modeled as the seismic response of a 3D-wedge model representing expected changes in rock properties. Such a wedge model is useful to study for which thicknesses one could detect which contrasts in acoustic parameters. To this end, one can vary those contrasts in the lateral direction perpendicular to the direction of varying thickness. (For more details on the applications of wedge models, refer to, e.g., Refs. 13 and 14.) Alternatively, the expected change can be modeled as the difference between synthetic data sets computed from two flow-simulator runs corresponding to the acquisition years of the base survey and the anticipated repeat survey. Fig. 1 illustrates the approach described above (and visualizes a 3D-wedge model). The final step is now to determine if it is possible to interpret the seismic changes, in the presence of noise, between the candidate base survey and the simulated repeat survey. To this end, one can perform time-shift measurements between the base and simulated repeat surveys, as well as measurements on seismic attributes (like maximum amplitude, area, or width of the seismic wiggle between two consecutive zero crossings) using any proposed interpretation techniques. Detailed Description and Illustration of the Method In this section, we discuss the method in detail and we illustrate it using examples from the onshore Yibal field in Oman and the Brent and Draugen fields in the North Sea.
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Su, Ho-Jeen y Ali H. Dogru. "Modeling of Equalizer Production System and Smart-Well Applications in Full-Field Studies". SPE Reservoir Evaluation & Engineering 12, n.º 02 (14 de abril de 2009): 318–28. http://dx.doi.org/10.2118/111288-pa.
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Summary Equalizer production systems and inflow control devices are used to mitigate water or gas-coning problems for mature fields. We have developed new modeling methods to simulate equalizer and interval control valve (ICV) performance in full-field multimillion-cell reservoir models under a parallel computational environment. The authors present single-well performance predictions with and without an equalizer, and the results are significantly different in some cases. Full-field modeling with equalizers and ICV controls for several examples has been conducted. In such cases, many individual wells would have significantly improved performance. At full-field level, however, using equalizers or smart well applications without total field optimization would not improve performance much, for reasons discussed in this paper. The frictional pressure loss across an equalizer can be considered as a skin, and we have developed an analytical well equation to include it. With this theoretical development, it is now possible to confirm or monitor equalizer performance in terms of pressure drop from pressure transient analysis. Introduction With high oil prices prevailing, producers are more willing than ever to buy advanced wellbore equipment to improve well performance (Salamy et al. 2006; Lorentz et al. 2006; Williamson et al. 2000). Fig. 1 illustrates an equalizer production system, sometimes called an inflow control device (ICD). At sandface, fluids are forced to go through some kind of flow-restriction mechanism before entering the production tubing. Flow restriction is achieved by different means, such as spiral channels and narrow-gauge orifice to artificially generate extra frictional pressure drop at chosen downhole locations where early water or gas breakthrough may occur. Current equalizer production systems are built into the tubing or casing and cannot be adjusted or moved once installed. Because the exact well-completion interval (where early water or gas breakthrough occurs) cannot be predicted, most manufacturers recommend a uniform design (e.g., an equalizer device every 40 or 80 feet [ft]). The manufacturers claim a uniform design has a self-regulating function; whereby, high-producing zones are cut back automatically to allow a higher influx from low-producing zones. The self-regulating property comes from the rate-dependent skin characteristics of the ICD. The flow resistence provided by constrictions is exponentially proportional to the flow rate. However, the authors illustrate that equalizer placement can be optimized to have a more uniform production profile if the reservoir permeability along the wellbore can be quantified by means of an openhole flowmeter survey shortly after drilling. Gamma ray log, drillstem testing (DST) tests, and modular formation dynamics tester (MDT) tests also provide useful permeability data. In general, equalizer application can result in a more uniform production profile, with better reservoir drainage for a very long horizontal well penetrating multiple isolated compartments. Some field trials have shown that equalizer application can improve the well productivity index (PI). A twofold oil production rate increase had been reported (Al-Qudaihy et al. 2006). In theory, this observation does not reflect reality, because an equalizer introduces extra pressure losses, causing the total pressure drawdown for a given rate to be greater than before. The only reasonable explanation for improved PI is a formation damage cleaning effect (i.e., equalizer application promotes flow from low-production [damaged] zones) thus helping remove debris from drilling mud and completion fluids. A typical smart-well application for multilateral wells is to control lateral flow rates by a downhole choke (Fig. 2). If water cut or gas/oil ratio (GOR) values exceed a preset value in any lateral, then the downhole choke is controlled remotely to cut down production in the affected lateral. For horizontal wells, we can group completion intervals into different sections. As in lateral control, the section ICV reduces production if a given section registers a high water cut or GOR value. If the well performance does not improve after several rate-reduction actions, the operator may shut down production completely for a given lateral or section if the economical limit, such as 95% water cut, is reached.
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Looyestijn, Wim J. y Jan Hofman. "Wettability-Index Determination by Nuclear Magnetic Resonance". SPE Reservoir Evaluation & Engineering 9, n.º 02 (1 de abril de 2006): 146–53. http://dx.doi.org/10.2118/93624-pa.
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Summary Knowing the wetting condition of a reservoir at an early stage is crucial for selecting optimum field-development options. Paying insufficient attention to the wetting condition (e.g., assuming water-wet behavior) may result in incorrect oil-in-place estimates and in unexpected dynamic behavior (e.g., under-waterflooding). A novel method is presented to determine the wettability of rocks from nuclear-magnetic-resonance (NMR) data. The method is based on the additional nuclear relaxation that fluids experience when in direct contact with the rock surface. Reduction of oil relaxation time away from its bulk value is generally known as a qualitative wettability indicator, assuming external factors to be negligible and/or invariant from one experiment to another. Through detailed modeling of the NMR response, this concept has been developed further to provide a quantitative wettability index. It is based on a model for the microscopic distribution of the crude oil and the wetting state of the rock at any given overall saturation. The method requires an NMR measurement on a sample containing two reservoir fluids (i.e., brine and crude oil). Multiacquisition schemes including diffusion effects make the interpretation more robust, but a normal NMR acquisition suffices as can be made with all available NMR tools (wireline and while-drilling). The new NMR-based method has been verified extensively on core data against standard wettability tests. Application to NMR logs is in progress. Introduction Importance of Wettability Determination. Wettability relates to the relative attraction of the rock to either water or oil and, thus, has a strong impact on the dynamic properties of the rock. Wettability ranges from pure water-wet (through intermediate-wet, or neutral) to oil-wet. Sandstone reservoirs have a tendency toward being water-wet to neutral, whereas carbonates are often neutral to oil-wet. However, there are too many exceptions to make reliable assumptions. Moreover, the wettability is likely to vary over the reservoir, and possibly also over time as a result of changing saturations during production. In current practice, wettability is poorly known; if identified at all, it is determined on a few core samples, and variation in 3D is hardly known. The purpose of the NMR wettability research is to take a first step toward alleviating these shortcomings by developing the results of recent work into a practical tool for use in reservoir studies. Wettability is rated as one of the critical uncertainties in many fields, particularly the Middle East carbonate fields. The ability to obtain wettability information at an early stage of field development is a significant improvement over current practices.
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Meisingset, K. K. "Uncertainties in Reservoir Fluid Description for Reservoir Modeling". SPE Reservoir Evaluation & Engineering 2, n.º 05 (1 de octubre de 1999): 431–35. http://dx.doi.org/10.2118/57886-pa.
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Summary The objective of the present paper is to communicate the basic knowledge needed for estimating the uncertainty in reservoir fluid parameters for prospects, discoveries, and producing oil and gas/condensate fields. Uncertainties associated with laboratory analysis, fluid sampling, process description, and variations over the reservoirs are discussed, based on experience from the North Sea. Introduction Reliable prediction of the oil and gas production is essential for the optimization of development plans for offshore oil and gas reservoirs. Because large investments have to be made early in the life of the fields, the uncertainty in the in-place volumes and production profiles may have a direct impact on important economical decisions. The uncertainties in the description of reservoir fluid composition and properties contribute to the total uncertainty in the reservoir description, and are of special importance for the optimization of the processing capacities of oil and gas, as well as for planning the transport and marketing of the products from the field. Rules of thumb for estimating the uncertainties in the reservoir fluid description, based on field experience, may therefore be of significant value for the petroleum industry. The discussion in the present paper is based on experience from the fields and discoveries where Statoil is an operator or partner, including almost all fields on the Norwegian Continental Shelf,1,2 and all types of reservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 (below 20° API). Fluid Parameters in the Reservoir Model The following parameters are used to describe the reservoir fluid in a "black oil" reservoir simulation model:densities at standard conditions of stabilized oil, condensate, gas, and water;viscosity (?O) oil formation volume factor (B O) and gas-oil ratio (RS) of reservoir oil;viscosity (?G) gas formation volume factor (B G) and condensate/gas ratio (RSG) of reservoir gas;viscosity (?W) formation volume factor (BW) and compressibility of formation water; andsaturation pressures: bubblepoint for reservoir oil, dew point for reservoir gas. The actual input is usually slightly more complex, with saturation pressure given as a function of depth, with RS and R SG defined as a function of saturation pressure, and with oil and gas viscosities and formation volume factors given as a function of reservoir pressure for a range of saturation pressure values. However, minor changes in saturation pressure versus depth are usually neglected, and the oil dissolved in the reservoir gas can also be neglected (RSG=0) when the solubility is small. Uncertainties in the modeling of other fluid parameters (interfacial tension may for instance be of importance, because of its effect on the capillary pressure), or compositional effects like revaporization of oil into injection gas, are not discussed here. Uncertainties in viscosity, formation volume factor and compressibility of formation water, and density of gas at standard conditions, are judged to be of minor importance for the total uncertainties in the reservoir model. The uncertainty in the salinity of the formation water is discussed here instead, because it is used for calculations of water resistivity for log interpretation, and therefore, affects the estimates of initial water saturation in the reservoir. In a compositional reservoir simulation model, the composition of reservoir oil and gas (with, typically, 4 to 10 pseudocomponents) is given as a function of depth, while phase equilibria and fluid properties are calculated by use of an equation of state. However, the uncertainties in the fluid description can be described in approximately the same way as for a "black oil" model. Quantified uncertainty ranges in the present paper are coarse estimates, aiming at covering 80% of the probability range for each parameter (estimated value plus/minus an uncertainty estimate defining the range between the 10% and 90% probability values3). Prospect Evaluation Assessments of the uncertainties in the reservoir description, as a basis for economic evaluation, are made in all phases of exploration and production. Of course, the complexity in the fluid description increases strongly from prospect evaluation through the exploration phase and further into the production phase, but the main fluid parameters in the reservoir model are the same. The prediction of fluid parameters in the prospect evaluation phase, before the first well has been drilled, is based on reservoir fluid data from discoveries near by, information about source rocks and migration, and empirical correlations. The uncertainties vary strongly from prospect to prospect. The probability as a function of volume for the presence of reservoir oil and gas is usually the most important fluid parameter. The probability for predicting the correct hydrocarbon phase varies from 50% (equal probability for reservoir oil and gas) to 90% (in regions where either oil or gas reservoirs are strongly dominating, or when the reservoir fluid can be expected to be the same as in another discovery near by). For formation volume factors, gas/liquid ratios, viscosities, and densities, an estimate for the most probable value as well as for a high and low possible value is commonly given. The range between the high and low value is often designed to include 80% of the probability range for the parameter, but accurate uncertainty estimates can seldom be made. The ratio of the high and low value is, typically, 1.5 to 50 for R SG 1.1 to 1.5 for B G 1.1 to 2.5 for ?G 1.2 to 3 for RS 1.1 to 2 for BO 1.5 to 5 for (?O and 1.03 to 1.1 for densities of stabilized oil and condensate. From Discovery to Production After a discovery has been made, the fluid description is based on laboratory analyses of reservoir fluid samples from drill-stem tests, production tests, and wireline sampling (RFT, FMT, MDT) in exploration and production wells. Pressure gradients in the reservoirs from measurements during wireline and drill-stem tests, analysis of residual hydrocarbons in core material from various depths, measurements of gas/oil ratio during drill-stem and production tests, and measurements of product streams from the field, give important supplementary information.
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FERNANDEZ, LAURA GABRIELA, Esteban Gonzalez, A. Pizarro, S. Abrigo, J. Choque y M. Tealdi. "NANOFLUID INJECTIVITY STUDY FOR ITS APPLICATION IN A PROCESS OF ENHANCED OIL RECOVERY (CEOR)". Latin American Applied Research - An international journal 49, n.º 2 (29 de marzo de 2019): 125–30. http://dx.doi.org/10.52292/j.laar.2019.37.
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The application of tertiary recovery techniques through chemical injection (CEOR) is in full development in the mature oil fields of Argentina. An experimental study of nanofluids intended for enhanced oil recovery is presented in this work. A polyacrylamide solution prepared in brine with addition of silica nanoparticles was used as the focus of the study. Dynamic sweep tests of the displacement fluids in a laboratory-scale triaxial cell using a standard Berea sandstone cores that simulates the formation of the reservoir allow the calculation of parameters related to its injectivity, which take into account damage to the formation and blockade of poral throats , such as the resistance factor (FR), the residual resistance factor (FRR), the inaccessible pore volume (VPI) and the dynamic retention of the nanofluid (RD). The injection of the nanofluid has not produced an increase in the damage of the porous medium, so it is potential for its application in the displacement of crude oil.
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Taggart, I. J. y H. A. Salisch. "FRACTAL GEOMETRY, RESERVOIR CHARACTERISATION AND OIL RECOVERY". APPEA Journal 31, n.º 1 (1991): 377. http://dx.doi.org/10.1071/aj90030.
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Reservoir heterogeneity is a dominant factor in determining large-scale fluid flow behaviour in reservoirs. Engineering estimates of oil production rates need to acknowledge and incorporate the effect of such heterogeneities. This work examines the use of fractal-based scaling techniques aimed at characterising heterogeneous reservoirs for simulation purposes. Well log data provide suitable fine-scale information for estimating the fractal dimension of reservoirs as well as providing known end- point data for interwell property value interpolation. Fractal techniques allow this interpolation to be performed in a manner which reproduces the same correlation structure as that found in the original well logs. Conditional simulation in these property fields allows the interaction between reservoir heterogeneity and fluid flow to be studied on a range of scales up to the interwell spacing. Analysis of results allows the calculation of effective reservoir properties which characterise the reservoir in terms of large-scale performance.
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Shevchenko, Oksana N. "Study of Fluid Flow to a Horizontal Well". Недропользование 21, n.º 2 (1 de abril de 2021): 64–70. http://dx.doi.org/10.15593/2712-8008/2021.2.3.
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Recently, it is necessary to note the presence of negative dynamics in the deterioration of the reserves structure for newly discovered fields, and most of the them are classified as hard-to-recover, confined to deposits with a complex geological structure, low permeability, high oil viscosity, complicated by the presence of faults, active bottom waters and gas caps. Hard-to-recover reserves are drilled with horizontal wells. This is primarily because horizontal wells make it possible to multiply the area of fluid filtration due to the increase in the drainage area, due to the extensive contact of the horizontal well section with the rock, allowing to increase the well flow rate many times over. Summarizing the above, horizontal wells are used to develop fields with the following parameters: fields with a thin oilsaturated rim (up to 15 m), with a gas cap and bottom water; fields of heavy oil, with a viscosity of more than 30 mPa·s; fields with low reservoir permeability (less than 0.002 μm2). Under these conditions, linear Darcy’s law cannot describe fluid filtration. Under the conditions of high-viscosity oil and lowpermeability reservoir existence, a certain initial pressure gradient is determined, due to the rheological properties of the filtering fluid and high values of the surface friction coefficient. Under conditions of a thin oil rim and an increased gas factor, the limiting filtration rates due to the dissolved gas regime are observed, and a nonlinear law describes the fluid inflow. One of the main parameters in the preparation of the technical and economic assessment of the reservoir is the flow rate of each individual horizontal well. Analytical methods for calculating the horizontal well flow rate show a high error. It is proposed to take a fresh look at the problem of determining the predicted flow rate of a horizontal well, using well-known approaches for solving this issue. It is rather difficult to reliably predict the parameters of reservoir operation: the horizontal wells productivity obtained with the help of modern hydrodynamic stimulators turns out to be unreliable, which leads to the formation of an insufficiently rational development system. And the arising complications during operation in field conditions have to be eliminated due to significant volumes of material and labor resources. Thus, the development of methods that contribute to obtaining a reliable calculation of production is an urgent task for the oil industry.
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Shen, Pingping, Jialu Wang, Shiyi Yuan, Taixian Zhong y Xu Jia. "Study of Enhanced-Oil-Recovery Mechanism of Alkali/Surfactant/Polymer Flooding in Porous Media From Experiments". SPE Journal 14, n.º 02 (31 de mayo de 2009): 237–44. http://dx.doi.org/10.2118/126128-pa.
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Summary The fluid-flow mechanism of enhanced oil recovery (EOR) in porous media by alkali/surfactant/polymer (ASP) flooding is investigated by measuring the production performance, pressure, and saturation distributions through the installed differential-pressure transducers and saturation-measurement probes in a physical model of a vertical heterogeneous reservoir. The fluid-flow variation in the reservoir is one of the main mechanisms of EOR of ASP flooding, and the nonlinear coupling and interaction between pressure and saturation fields results in the fluid-flow variation in the reservoir. In the vertical heterogeneous reservoir, the ASP agents flow initially in the high-permeability layer. Later, the flow direction changes toward the low- and middle-permeability layers because the resistance in the high-permeability layer increases on physical and chemical reactions such as adsorption, retention, and emulsion. ASP flooding displaces not only the residual oil in the high-permeability layer but also the remaining oil in the low- and middle-permeability layers by increasing both swept volume and displacement efficiency. Introduction Currently, most oil fields in China are in the later production period and the water cut increases rapidly, even to more than 80%. Waterflooding no longer meets the demands of oilfield production. Thus, it is inevitable that a new technology will replace waterflooding. The new technique of ASP flooding has been developed on the basis of alkali-, surfactant-, and polymer-flooding research in the late 1980s. ASP flooding uses the benefits of the three flooding methods simultaneously, and oil recovery is greatly enhanced by decreasing interfacial tension (IFT), increasing the capillary number, enhancing microscopic displacing efficiency, improving the mobility ratio, and increasing macroscopic sweeping efficiency (Shen and Yu 2002; Wang et al. 2000; Wang et al. 2002; Sui et al. 2000). Recently, much intensive research has been done on ASP flooding both in China and worldwide, achieving some important accomplishments that lay a solid foundation for the extension of this technique to practical application in oil fields (Baviere et al. 1995; Thomas 2005; Yang et al. 2003; Li et al. 2003). In previous work, the ASP-flooding mechanism was studied visually by using a microscopic-scale model and double-pane glass models with sand (Liu et al. 2003; Zhang 1991). In these experiments, the water-viscosity finger, the residual-oil distribution after waterflooding, and the oil bank formed by microscopic emulsion flooding were observed. In Tong et al. (1998) and Guo (1990), deformation, threading, emulsion (oil/water), and strapping were observed as the main mechanisms of ASP flooding in a water-wetting reservoir, while the interface-producing emulsion (oil/water), bridging between inner pore and outer pore, is the main mechanism of ASP flooding in an oil-wetting reservoir. For a vertical heterogeneous reservoir, ASP flooding increases displacement efficiency by displacing residual oil through decreased IFT, simultaneously improving sweep efficiency by extending the swept area in both vertical and horizontal directions. Some physical and chemical phenomena, such as emulsion, scale deposition, and chromatographic separation, occur during ASP flooding (Arihara et al. 1999; Guo 1999). Because ASP flooding in porous media involves many complicated physicochemical properties, many oil-recovery mechanisms still need to be investigated. Most research has been performed on the microscopic displacement mechanism of ASP flooding, while the fluid-flow mechanism in porous media at the macroscopic scale lacks sufficient study. In this paper, a vertical-heterogeneous-reservoir model is established, and differential-pressure transducers and saturation-measuring probes are installed. The fluid-flow mechanism of increasing both macroscopic sweep efficiency and microscopic displacement efficiency is studied by measuring the production performance and the variation of pressure and saturation distributions in the ASP-flooding experiment. An experimental database of ASP flooding also is set up and provides an experimental base for numerical simulation.
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Liu, Yang, Jiawei Fan y Qinglin Cheng. "Mathematical modeling of large floating roof reservoir temperature arena". Polish Journal of Chemical Technology 20, n.º 1 (1 de marzo de 2018): 67–74. http://dx.doi.org/10.2478/pjct-2018-0010.
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Abstract The current study is a simplification of related components of large floating roof tank and modeling for three dimensional temperature field of large floating roof tank. The heat transfer involves its transfer between the hot fluid in the oil tank, between the hot fluid and the tank wall and between the tank wall and the external environment. The mathematical model of heat transfer and flow of oil in the tank simulates the temperature field of oil in tank. Oil temperature field of large floating roof tank is obtained by numerical simulation, map the curve of central temperature dynamics with time and analyze axial and radial temperature of storage tank. It determines the distribution of low temperature storage tank location based on the thickness of the reservoir temperature. Finally, it compared the calculated results and the field test data; eventually validated the calculated results based on the experimental results.
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Qassamipour, Mehdi, Elnaz Khodapanah y Seyyed Alireza Tabatabaei-Nezhad. "An integrated procedure for reservoir connectivity study between neighboring fields". Journal of Petroleum Exploration and Production Technology 10, n.º 8 (29 de agosto de 2020): 3179–90. http://dx.doi.org/10.1007/s13202-020-00995-1.
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Abstract Reservoir connectivity has a considerable effect on reservoir characterization, plans for field developments and production forecasts. Reducing the uncertainties about the lateral and vertical extension of different pay zones is the main step in developing and managing the reservoirs. Nearly all the proposed methodologies for the verification of reservoir connectivity are limited to the study of the communication of different compartments in one field. In the presented paper, first a comprehensive procedure is proposed to study the reservoir connectivity between nearby fields. The steps in this procedure are not necessarily hierarchy, but all the considerations in each step are studied to cover all the uncertainties that affect the reservoir communication. This procedure mainly comprises the study of reservoir extension, pressure communication in the hydrocarbon column, fluid similarity, top seal efficiency and faults sealing. Then, to apply this procedure for proving the communication between nearby fields, a case study of Ilam Formation in southwest of Iran is presented. The results confirm the lateral connectivity of the three pre-explored distinctive oil fields in Ilam Formation. The established connectivity leads to an increase in the pre-estimated oil-in-place volumes. This incorporated case study demonstrates how different data including geophysics, structural and petroleum geology, production and reservoir engineering are integrated to prove the communication of Ilam reservoir between these fields. This manifested technique is a powerful road map for other cases worldwide and is extremely recommended to be performed before developing those fields that are suspicious to lateral connectivity.
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Xu, Jianping, Yuanda Yuan, Qing Xie y Xuegang Wei. "Research on the application of molecular simulation technology in enhanced oil-gas recovery engineering". E3S Web of Conferences 233 (2021): 01124. http://dx.doi.org/10.1051/e3sconf/202123301124.
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In recent years, molecular simulations have received extensive attention in the study of reservoir fluid and rock properties, interactions, and related phenomena at the atomistic scale. For example, in molecular dynamics simulation, interesting properties are taken out of the time evolution analysis of atomic positions and velocities by numerical solution of Newtonian equations for all atomic motion in the system. These technologies assists conducting “computer experiments” that might instead of be impossible, very costly, or even extremely perilous to carry out. Whether it is from the primary oil recovery to the tertiary oil recovery or from laboratory experiment to field test, it is difficult to clarify the oil displacement flow mechanism of underground reservoirs. Computer molecular simulation reveals the seepage mechanism of a certain oil displacement at the microscopic scale, and enriches the specific oil displacement flow theory system. And the molecular design and effect prediction of a certain oil-displacing agent were studied, and its role in the reservoir was simulated, and the most suitable oil-displacing agent and the best molecular structure of the most suitable oil-displacing agent were obtained. To give a theoretical basic for the development of oilfield flooding technology and enhanced oil/gas recovery. This paper presents an overview of molecular simulation techniques and its applications to explore enhanced oil/gas recovery engineering research, which will provide useful instructions for characterizing the reservoir fluid and rock and their behaviors in various oil-gas reserves, and it greatly contribute to perform optimal operation and better design of production plants.
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Wang, Yarlong y Carl C. Chen. "Enhanced Oil Production Owing to Sand Flow in Conventional and Heavy-Oil Reservoirs". SPE Reservoir Evaluation & Engineering 4, n.º 05 (1 de octubre de 2001): 366–74. http://dx.doi.org/10.2118/73827-pa.
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Summary A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy-oil reservoirs (northwestern Canada) and conventional oil reservoirs (i.e., North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are calculated, and the effects of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake area (Lloydminster, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced oil production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, (2) by higher mobility of the fluid caused by the movement of the sand particles, and (3) by foamy oil flow. A relative permeability reduction after a certain period of production may result in a pressure-gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall sand/fluid slurry production. Our numerical results simulate the fact that sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, generating a high-mobility zone with a negative skin near the wellbore. Such an improvement reduces the near-well pressure gradient so that the sanding potential is weakened, and it permits an easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement is a key factor for controlling the cumulative sand production, a crucial factor that determines the success of a cold production operation and improved well completion. Introduction Field results from many heavy-oil reservoirs in northwestern Canada, such as Lindbergh and Frog Lake in the Lloydminster fields, suggest that primary recovery is governed mainly by the processes of sand production and foamy-oil flow.1–3 To manage production in such reservoirs, the challenge we face is optimizing production so that sand production is under control. For decades, industries have developed various highly effective tools for sand control. In practice, however, sand control often results in reduced oil flow or no production at all, particularly in heavy-oil reservoirs. For example, it has been observed that an average oil production of only 0.0 to 1.5 m3/d can be achieved in a well in which no sand production is allowed, while 7 to 15 m3/d oil may be produced with sand production.4 A significant improvement in production also has been reported by allowing a certain amount of sand produced before gravel packing in the high-rate production well in conventional reservoirs.5 It seems that sanding corresponds to a high oil production in these reservoirs, as sand production either increases the reservoir mobility or allows the development of highly permeable zones such as channels (wormholes).1 Encouraging sand production to enhance oil production, on the other hand, increases oil production costs owing to environmental problems. Consequently, neither trying to eliminate the sand production completely nor letting sand be produced freely, we attempt to develop a quantified model linking sand rate and reservoir enhancement so that we can forecast the economic outcome of such an operation. The investigation of sand production has been extensive, but it has been limited primarily to the areas of incipience of sand production and control. Sand arching and production initiation from a cavity simulating a perforating tunnel were studied, and a critical flow rate before sanding was found for single-phase steady-state flow.6 Such a study was extended to gas reservoirs, in which the gas density is a function of pressure,7 and to those formations subject to nonhydrostatic loading.8,9 Studying the enhanced production and the cumulative sand production, a series of simplified models for massive sand production have been developed.10,11 Similar models based on a coupled classic geomechanics model were also proposed thereafter.12,13 Because these aforementioned sand-production models are somewhat restricted by the fact that they are simplified by analytical methods, and in reality reservoir formations are much more complex (i.e. nonlinear behaviors), a numerical model coupling a multiphase transient fluid flow to elastoplastic geomechanical deformation is thus developed in this article; its purpose is to simulate these major nonlinear effects. According to the proposed model, a corresponding plastic yielding zone (or a disturbed zone) propagates into reservoir formation because of the transient fluid pressure diffusion, and the corresponding effective stresses change near a wellbore. A possible absolute permeability change inside the yielding zone is also considered, as dilatant deformation developed may enhance the permeability in the plastic zone. As a primary unknown, saturation is assumed to change with the induced pore-pressure change. The relative permeability is updated by the saturation, which in turn changes the response of the pore pressure and the skeleton deformation. A continuum mechanics approach is used in our calculation. Rather than characterizing each random wormhole proposed,1,4,5 we impose a homogeneous medium with an average permeability to make the numerical solutions manageable. The wormholes or geomechanical dilatation zone can be represented by a higher-permeability region in the plastic yielding zone owing to porosity enhancement,1 and solid flow is considered as a continuous moving phase along the transient fluid flow. Alternatively, a sand erosion model was introduced, and the geomechanics coupling to a single-phase flow was presented previously.14,15
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Perez, Felipe y Deepak Devegowda. "A Molecular Dynamics Study of Soaking During Enhanced Oil Recovery in Shale Organic Pores". SPE Journal 25, n.º 02 (10 de enero de 2020): 832–41. http://dx.doi.org/10.2118/199879-pa.
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Summary In this work we use molecular dynamics simulations to investigate the interactions during soaking time between an organic solvent (pure ethane) initially in a microfracture and a mixture of hydrocarbons representative of a volatile oil, and other reservoir fluids such as carbon dioxide and water, originally saturating an organic pore network with a predominant pore size of 2.5 nm. We present evidence of the in-situ fractionation in liquid-rich shales and its implications in enhanced oil recovery (EOR) projects. We also discuss the behavior of the larger and heavier molecules in the fluid mixture while the solvent interacts with them. Notably, prior to solvent invasion of the pores and further mixing with the reservoir fluids, the heavier hydrocarbons in the mixture are initially adsorbed onto the pore surface and pore throats surface, partially clogging them. We show that the porous structure of kerogen and the presence of adsorbed molecules of asphaltenes and resins in the pore throats act as a molecular sieve and may be one of the reasons for the fractionation of the reservoir fluids. The differing ability of the solvent to desorb and mix with different hydrocarbon species is another reason for the fractionation occurring during soaking. Our simulations show that the production of reservoir fluids occurs due to a countercurrent diffusive flow from the organic pore network to the microfracture driven by the concentration gradient between the two regions.
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Hashem, M. N., E. C. Thomas, R. I. McNeil y Oliver Mullins. "Determination of Producible Hydrocarbon Type and Oil Quality in Wells Drilled With Synthetic Oil-Based Muds". SPE Reservoir Evaluation & Engineering 2, n.º 02 (1 de abril de 1999): 125–33. http://dx.doi.org/10.2118/55959-pa.
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Summary Determination of the type and quality of hydrocarbon fluid that can be produced from a formation prior to construction of production facilities is of equal economic importance to predicting the fluid rate and flowing pressure. We have become adept at making such estimates for formations drilled with water-based muds, using open-hole formation evaluation procedures. However, these standard open-hole methods are somewhat handicapped in wells drilled with synthetic oil-based mud because of the chemical and physical similarity between the synthetic oil-based filtrate and any producible oil that may be present. Also complicating the prediction is that in situ hydrocarbons will be miscibly displaced away from the wellbore by the invading oil-based mud filtrate, leaving little or no trace of the original hydrocarbon in the invaded zone. Thus, normal methods that sample fluids in the invaded zone will be of little use in predicting the in situ type and quality of hydrocarbons deeper in the formation. Only when we can pump significant volume of filtrate from the invaded zone to reconnect and sample the virgin fluids are we successful. However, since the in situ oil and filtrate are miscible, diffusion mixes the materials and blurs the interface; as mud filtrate is pumped from the formation into the borehole, the degree of contamination is greater than one might expect, and it is difficult to know when to stop pumping and start sampling. What level of filtrate contamination in the in situ fluid is tolerable? We propose a procedure for enhancing the value of the data derived from a particular open-hole wireline formation tester by quantitatively evaluating in real time the quality of the fluid being collected. The approach focuses on expanding the display of the spectroscopic data as a function of time on a more sensitive scale than has been used previously. This enhanced sensitivity allows one to confidently decide when in the pumping cycle to begin the sampling procedure. The study also utilizes laboratory determined PVT information on collected samples to form a data set that we use to correlate to the wireline derived spectroscopic data. The accuracy of these correlations has been verified with subsequent predictions and corroborated with laboratory measurements. Lastly, we provide a guideline for predicting the pump-out time needed to obtain a fluid sample of a pre-determined level of contamination when sampling conditions fall within our range of empirical data. Conclusions This empirical study validates that PVT quality hydrocarbon samples can be obtained from boreholes drilled with synthetic oil-based mud utilizing wireline formation testers deployed with downhole pump-out and optical analyzer modules. The data set for this study has the following boundary conditions: samples were obtained in the Gulf of Mexico area; the rock formations are unconsolidated to slightly consolidated, clean to slightly shaly sandstones; the in situ hydrocarbons and the synthetic oil-based mud filtrate have measurable differences in their visible and/or near infrared spectra. Specifically, this study demonstrates that during the pump-out phase of operations we can use the optical analyzer response to predict the API gravity and gas/oil ratio of the reservoir hydrocarbons prior to securing a downhole sample. Additionally, we can predict the pump out time required to obtain a reservoir sample with less than 10% mud filtrate contamination if we know or can estimate reservoir fluid viscosity and formation permeability. Extension of this method to other formations and locales should be possible using similar empirical correlation methodology. Introduction The high cost of offshore production facilities construction and deployment require accurate prediction of hydrocarbon PVT properties prior to fabrication. In the offshore Gulf of Mexico, one method to obtain a PVT quality hydrocarbon sample is to use a cased hole drill stem test. However, this procedure is usually quite costly due to the need for sand control. Shell has been an advocate of eliminating this costly step by utilizing openhole wireline test tools to obtain the PVT quality sample of the reservoir hydrocarbon. The success of this approach depends upon the availability of a wireline tool with a downhole pump that permits removal of the mud filtrate contamination prior to sampling the reservoir fluids, and a downhole fluid analyzer that can distinguish reservoir fluid from filtrate. One such tool is the Modular Formation Dynamics Tester (MDT).1 The optical fluid analyzer module of the MDT functions by subjecting the fluids being pumped to absorption spectroscopy in the visible and near-infrared (NIR) ranges. Interpretation of these spectra is the subject of this paper. Tool descriptions and basic theory of operations were presented in an earlier text.2 The concept of using visible and/or NIR spectroscopy to characterize the fluids being sampled while pumping is straightforward when there are measurable differences in the spectra of the mud filtrate and the reservoir hydrocarbons. As shown in Fig. 1, there are well known areas3,4 of the NIR spectrum (800-2000 nm) that are diagnostic of water and oil. The optical fluid analyzer module (OFA) of the MDT has channels tuned at 10 locations as indicated in Fig. 1, and thus the response in channels 6, 8, and 9 can be used to discern water from hydrocarbon. Another section of the OFA is designed to detect gas by measuring reflected polarized light from the pumped fluids, but we do not discuss its operation further except to say that it is a reliable gas indicator.
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Breaux, E. J., S. A. Monroe, L. S. Blank, D. W. Yarberry y S. A. Al-Umran. "Application of a Reservoir Simulator Interfaced With a Surface Facility Network: A Case History". Society of Petroleum Engineers Journal 25, n.º 03 (1 de junio de 1985): 397–404. http://dx.doi.org/10.2118/11479-pa.
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Summary Management requires dependable information upon which to base decisions regarding large investments. The system discussed in this paper proves to be a viable tool for effectively managing reservoir development and provides several alternatives upon which management could base such decisions. A three-dimensional (3D), three-phase reservoir simulator is interfaced with a surface facility network simulator. The results are used in determining an integrated field development and operating plan for producing an onshore-offshore oil reservoir at a specified producing an onshore-offshore oil reservoir at a specified rate. Various aspects of alternative development and facility installation scenarios are investigated with the interfaced system. The requirements and sizing of major surface facilities and a drilling and workover program are determined over a 25-year study period. The most efficient development plan is one that combines cost-effective drilling and facilities scheduling while at the same time providing maximum operating flexibility and balanced providing maximum operating flexibility and balanced reservoir development. This technique has been applied to the future development planning of existing fields but is equally applicable to planning the development of new fields in any environment by altering the producing rules controls and reservoir and network models to account for the appropriate circumstances. Introduction Complex alternative development plans are evaluated in a decreased amount of time with a reservoir simulator interfaced with a surface facility network model. This study differs from typical reservoir simulation studies by recognizing surface facility and gathering system constraints and by responding to those constraints during the same timestep. The calculation procedure and example application of a reservoir simulator interfaced with a surface facility network simulator is presented by Emanuel and Ranney. The specific application of such a system to assist in planning the overall development of a major onshore offshore planning the overall development of a major onshore offshore oil reservoir is presented in this paper. The interfaced system simulates surface and subsurface pressures and three-phase fluid flow behavior throughout the system, allowing for the study of various operating strategies. The reservoir studied is an elongated anticline with several domes and underlies a surface area located onshore and offshore. This is an undersaturated oil reservoir with low GOR and saturation pressure. There is a multiple energy drive mechanism, active water drive in the south and fluid and rock expansion with limited water drive in the north. The current options for maintaining production from the field are limited to continued drilling and workovers. Production must be essentially dry and under natural Production must be essentially dry and under natural depletion since no water removal or artificial lift facilities are available. Production is being processed through three gas/oil separation plants. Primary development is along the crest of the structure, with drilling conducted from multiwell platforms. Future options for maintaining production are water removal, gas lift, trunkline and facility expansions, water injection, additional drilling, and well workovers. The reservoir simulator is a finite-difference, black-oil simulator that uses a 3D, three-phase formulation with an option for an implicit pressure/explicit saturation (IMPES) solution. Producing facilities are modeled using a multiphase producing facility simulator. This program simulates producing facility simulator. This program simulates steadystate, single- or multiphase fluid flow in wells, pipes, another equipment. Pressure loss calculations can be pipes, another equipment. Pressure loss calculations can be performed by a variety of methods published in the literature. performed by a variety of methods published in the literature. Fluid properties can be derived from generalized correlations, laboratory data, or compositional three-phase equilibrium calculations. A variety of network solution techniques are available; choice of technique depends on network complexity and fluid properties. The interface links the surface network simulator to the reservoir simulator through a suite of coupling routines. The simulators used in this system are a reservoir simulator for all subsurface calculations and a surface-facility network simulator for all vertical, wellbore, and surface fluid flow computations. SPEJ P. 397
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Pratiwi, Dian y Agung Wiyono. "PEMANTAUAN PROSES INJEKSI AIR PADA LAPANGAN “SMR” CEKUNGAN SUMATERA TENGAH BERDASARKAN DATA ANOMALI TIME-LAPSE MICROGRAVITY". Jurnal Geofisika Eksplorasi 4, n.º 1 (17 de enero de 2020): 112–25. http://dx.doi.org/10.23960/jge.v4i1.10.
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There had been done a regional research about monitoring of injection process in "SMR" field of Central Sumatera Basin using microgravity method. The time-lapse microgravity method is the development of the gravity method (x, y, z) by adding the fourth dimension of time (t). Monitoring is carried out on production fields that have performed EOR (Enchanced Oil Recovery) ie the process of injecting water into the reservoir to push and drain the remnants of oil in the pores of the reservoir rock to the production well. The microgravity data processing is done by finding the difference between observed gravity values between the first and the second measurements, then performing the spectral analysis to separate the anomaly at reservoir depth and noise. The time-lapse microgravity anomaly has a value of -132.28 μGal to 54.89 μGal. Positive anomalies are related to the injection process, whereas the negative anomalies are related to the production process in the study area. Filtering analysis shows that there are two zones of fluid dynamics, which is due to the process of surface water dynamics (groundwater above reservoir) and that occurs in the reservoir. Fluid reduction zones occur in areas with more production wells than injection wells. Density reduction occurs in the reservoir layer at a depth of 600 m to 1000 m with a maximum reduction value of -3.1x10-3 gr / cm3. The gravity time-lapse inversion model shows the existence of several injection wells that are less effective and therefore need to be stopped injecting.
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Pan, Huanquan, Yuguang Chen, Jonathan Sheffield, Yih-Bor Chang y Dengen Zhou. "Phase-Behavior Modeling and Flow Simulation for Low-Temperature CO2 Injection". SPE Reservoir Evaluation & Engineering 18, n.º 02 (9 de abril de 2015): 250–63. http://dx.doi.org/10.2118/170903-pa.
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Summary CO2 injection into an oil reservoir at low temperatures (less than 120 °F) can form three hydrocarbon phases—a vapor phase, an oil-rich liquid, and a CO2-rich liquid phase. Most available reservoir simulators cannot handle three-hydrocarbon-phase flash, and the use of two-phase flash may cause significant numerical instability. The issue has been recognized in the industry for a long time. Studies to include three-hydrocarbon-phase flash in compositional simulations exist in the literature. However, this approach results in substantial increases of model complexity and computational cost; thus, it may not be realistic for practical applications (at least for now). In this work, we propose a new pressure/volume/temperature (PVT) modeling procedure to eliminate the three-hydrocarbon-phase region for reservoir-fluid/CO2 mixtures at low temperatures and to study its implication for flow simulation. In our method, the acentric factors of pseudocomponents are adjusted to eliminate the three-hydrocarbon-phase region, which was not considered in any of the previous studies. Then, the experimental data for reservoir-fluid PVT, CO2 swelling test, and minimum miscibility pressure are also matched by adjusting further binary-interaction coefficients, volume-shift parameters, and critical volumes of the pseudocomponents. The procedure is applicable for cases with relatively small three-phase regions (e.g., some fields in west Texas), and can be applied with any PVT simulation software and conventional two-hydrocarbon-phase simulators. The method is considered for two sector models from oil fields in west Texas, with fine-scale (more than 600,000 gridblocks) and upscaled models. Compared with the standard characterization, in which the three-hydrocarbon phases exist, the new fluid model significantly improves the stability of flow simulation, demonstrating the robustness and efficiency of the new procedure. One can view the method as a practical approximation to field-scale simulations of CO2 injection at low temperatures.
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Ahmadi, Pouyan, Ehsan Ghandi, Masoud Riazi y Mohammad Reza Malayeri. "Experimental and CFD studies on determination of injection and production wells location considering reservoir heterogeneity and capillary number". Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 4. http://dx.doi.org/10.2516/ogst/2018078.
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The in-depth knowledge of reservoir heterogeneity is imperative for identifying the location of production and injection wells. The present study aimed at experimentally investigating the process of water flooding in the viscous oil-saturated glass micromodels, which contain layers with different permeability where the fractures were placed in different locations. Computational Fluid Dynamics (CFD) simulations of flooding were also conducted to study the impact of different water flow rates and wettability states. The results showed that the fractures, which have a deviation with the trend of maximum pressure gradient line, would widen the water path and vice versa. The performance of injection wells would increase the recovery factor by 18% if these would be located in the zones with high permeability for low flow rates of water. With changes in wettability state from water to oil wet conditions, the oil production will increase by 11%. Computational Fluid Dynamics results also indicated that an increase in the capillary number from 0.8 × 10−6 to 1.6 × 10−5, would cause the recovery factor to decrease as much as 14.34% while further increase from 1.6 × 10−5 to 2.24 × 10−5, the oil production will increase by 9.5%. Comparison between the obtained oil recoveries indicates that the maximum oil recoveries will happen when the injector well is located in the zone where ascending permeability, capillary number greater than 4.81 × 10−6 and also fracture with the most deviation with pressure gradient line (i.e. angular pattern) are gathered in an area between the injection and production wells.
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Al-Fattah, Saud M. y Hamad A. Al-Naim. "Artificial-Intelligence Technology Predicts Relative Permeability of Giant Carbonate Reservoirs". SPE Reservoir Evaluation & Engineering 12, n.º 01 (26 de febrero de 2009): 96–103. http://dx.doi.org/10.2118/109018-pa.
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Summary Determination of relative permeability data is required for almost all calculations of fluid flow in petroleum reservoirs. Water/oil relative permeability data play important roles in characterizing the simultaneous two-phase flow in porous rocks and predicting the performance of immiscible displacement processes in oil reservoirs. They are used, among other applications, for determining fluid distributions and residual saturations, predicting future reservoir performance, and estimating ultimate recovery. Undoubtedly, these data are considered probably the most valuable information required in reservoir simulation studies. Estimates of relative permeability are generally obtained from laboratory experiments with reservoir core samples. In the absence of the laboratory measurement of relative permeability data, developing empirical correlations for obtaining accurate estimates of relative permeability data showed limited success, and proved difficult, especially for carbonate reservoir rocks. Artificial-neural-network (ANN) technology has proved successful and useful in solving complex structured and nonlinear problems. This paper presents a new modeling technology to predict accurately water/oil relative permeability using ANN. The ANN models of relative permeability were developed using experimental data from waterflood-core-tests samples collected from carbonate reservoirs of giant Saudi Arabian oil fields. Three groups of data sets were used for training, verification, and testing the ANN models. Analysis of results of the testing data set show excellent agreement with the experimental data of relative permeability. In addition, error analyses show that the ANN models developed in this study outperform all published correlations. The benefits of this work include meeting the increased demand for conducting special core analysis (SCAL), optimizing the number of laboratory measurements, integrating into reservoir simulation and reservoir management studies, and providing significant cost savings on extensive lab work and substantial required time.
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Dou, Hong'en, Changchun Chen, Yu Wen Chang, Yanjun Fang, Xinbin Chen y Wenxin Cai. "Analysis and Comparison of Decline Models: A Field Case Study for the Intercampo Oil Field, Venezuela". SPE Reservoir Evaluation & Engineering 12, n.º 01 (26 de febrero de 2009): 68–78. http://dx.doi.org/10.2118/106440-pa.
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Summary Intercampo oil field, which contains unconsolidated reservoirs driven by edge water and bottom water, is characterized by heavy oil with mid-high permeability and high oil saturation. The three classical models of the Arps model were applied in 13 horizontal and vertical wells in the oil field; also, the paper introduces two models that are not widely applied for decline analysis and forecasting in the wells. Decline features between vertical and horizontal wells were compared. The results accord well with the actual data from the oil field. The authors point out that these decline analysis models are applicable not only for vertical wells but also for horizontal wells. The authors would like to emphasize that four decline models discussed in the paper. In regard to screening and comparison of decline analysis models, this paper illustrates how to select and use a model, as well as the model's application conditions and their features. The screened models are recommended for production performance analysis of wells, reservoirs and oil fields. Introduction Existing decline curve analysis techniques, which include three Arps models (exponential, hyperbolic, and harmonic, 1945), and the Fetkovich model (1980), are derived empirically; the Arps models are still the preferred method for forecasting oil production and proven reserve. These methods have played a very important role in the exploration and development of oil fields worldwide (Arps 1945, Arps 1956, Fetkovich et al. 1980, Fetkovich et al. 1987, Fetkovich et al. 1996). Gentry and McCray (1978) presented a method to define decline curve. They claimed their equation might be superior to the Arps equations by defining certain decline curves. However, the model was derived from the hyperbolic model of the Arps model; their equation has a parameter qi of initial production rate computed by the Darcy Law. This means that the application of their method requires more parameters, such as relative permeability curve, radius of drainage, formation thickness, reservoir pressure at external drainage radius, and well bore terminal pressure. On this point, in their example the extrapolation with their model is not seen because the method is not a pure production-time relationship. Furthermore, use of this model to extrapolate future production is restricted by the data requirements. Li and Horne (2002, 2005) developed an analytical model, called the Li-Horne model, based on fluid flow mechanisms. The model was developed under the spontaneous water imbibition condition. Li and Horne also thought it difficult to predict which Arps equation a reservoir would follow. However, they made a conceptual error in their reasoning of the Arps models. In fact, we need to judge the decline type before using the Arps model to make production decline analysis. Li and Horne used only two special cases of decline exponent, n = 0 and 1, then compared the exponential model and harmonic model with any models. Hence, we think Li and Horne's comparison of several oil fields is not meaningful in cases where they did not get a concrete decline exponent n. When the Li-Horne model was applied to the actual oil fields, the values of a0 and b0 were regressed from the actual oilfield data, but not the calculation values from their equations. Because the models constants of the Arps and Li-Horne model regress from the actual oil fields, they include different reservoir type and fluid flow information (high permeability, low permeability, naturally fractured low permeability, complex, fault reservoir, etc.; single flow and multiphase flow, etc.). Therefore, the decline analysis models based on purely statistical models do not have any association with fluid flow mechanism, reservoir types, fluids characteristics, steady or unsteady flow, and single or multiphase flow. We are inclined to refer to this as an empirical rather than an analytical model. The other two decline analysis models introduced in this paper, the Orstrand-Weng model (Arps 1945, Weng 1992) and the T model, were both proposed for predicting oil field production in China during the 1980s. The main purpose of this paper is to compare application conditions and results among four models: Arps, Orstrand-Weng, T and the Li-Horne model.
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Weber, K. J. y Hans Dronkert. "Screening Criteria to Evaluate the Development Potential of Remaining Oil in Mature Fields". SPE Reservoir Evaluation & Engineering 2, n.º 05 (1 de octubre de 1999): 405–11. http://dx.doi.org/10.2118/57873-pa.
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Summary Continuing reservoir management at mature stages often concentrates on delineating pockets of remaining mobile oil. This is becoming a major task for reservoir geologists and petrophysicists. Many old fields are coming up for reactivation as investment opportunities and there is an overall expectation that modern techniques can lead to additional recovery of between 10 and 20%. In this article we will discuss the screening criteria related to reservoir architecture, accumulation condition and production history. The mobile oil remaining can be found in a number of predictable locations in reservoirs depending on their structural style and facies. Attic oil along faults is perhaps the most simple configuration but sizeable volumes of remaining oil can also occur as a function of reservoir stratification and lateral discontinuity. A systematic overview of the different play types has been compiled based on structural or stratigraphic lateral continuity and vertical reservoir connectivity. Screening criteria have been derived on the basis of field examples and models for four play types. The screening criteria specify minimum conditions which may lead to economic re-development with horizontal sidetracks from existing wells. In addition recommendations are given with respect to data gathering to confirm the presence of economically viable targets. Introduction Numerous oil fields that have been in production for many years are currently being reviewed to evaluate options for increasing their ultimate recovery. The task involves determination of the volume and location of remaining mobile oil and subsequently the technical and economic assessment of methods to recover this oil. The first part of this task is often difficult because of the poor quality of the data often associated with old fields. Nevertheless, certain basic data are usually available and the purpose of this article is to provide first round screening criteria based on these data in order to select those reservoirs for which re-development schemes are more likely to be economical. For the reservoirs selected, further study and some additional data acquisition will be warranted. The data that may be expected to be present consist of well logs, limited core measurements, basic facies descriptions, original oil-in-place and cumulative production figures, structure maps and well positions. Having access to well completion data is also essential. Individual well performance data are often difficult to obtain. The proposed screening scheme is based on a classification of the types of remaining oil configurations. Once such a potential oil pocket has been recognized, an attempt is made to assess its economic value by estimating a number of parameters with a limited degree of accuracy. Dip, original accumulation conditions, bedding thickness, reservoir profile, porosity distribution and original oil saturation can often be determined satisfactorily. More detailed reservoir architecture and particularly permeability distributions are more difficult to obtain. The classification scheme for mobile remaining oil pockets consists of a division into reservoirs with either high or low vertical permeability/connectivity and a further subdivision into types with a high and low horizontal connectivity. In this article four major types of mobile remaining oil configurations, representing the four combinations of high and low vertical and horizontal conductivity, are discussed. The screening criteria presented are based on re-development with pairs of horizontal sidetracks from existing wells. A cost of $1,000,000 has been assumed per job for re-entering the hole, milling the casing and drilling and completion of the two sidetracks each of 300 m length. This is based on a variety of cost estimates obtained for land operations. The economic analysis based on this method and on the cost level shows a remarkably large scope for re-development of reservoirs with oil rims, attic oil cases in faulted reservoirs and layer cake reservoirs with beds of contrasting permeability. Fluvial labyrinth type reservoirs1 are much more difficult to re-develop but a number of observations are made to suggest more favorable configurations. Classification of Remaining Mobile Oil Configurations The retention of mobile oil in sufficiently large volumes to allow economic re-development is largely controlled by the presence of heterogeneous pressure distribution and the fluid density and viscosity contrasts. This article is restricted to sandstone reservoirs containing light oil that have been developed with vertical wells and produced under reasonable draw-down conditions. In view of the potential for recompletion and infill drilling, the most important heterogeneities are faults, boundaries of genetic units, large permeability contrasts and baffles to flow such as shale intercalations. Following the subdivisions of clastic reservoirs into layer cake, jigsaw puzzle and labyrinth types one can already predict a number of typical oil displacement patterns. By considering major large scale heterogeneities we can subdivide the reservoirs into types with a high vertical conductivity and those in which stratification and low permeable intercalations result in low vertical conductivity. Next we can make a further distinction between layer cake reservoirs with a high degree of lateral continuity of the beds and reservoirs where the lateral continuity is limited by faults or pinchouts of the sand bodies. This leads to the scheme shown in Fig. 1. To the first category, A, we can attribute oil-rim reservoirs with a high vertical conductivity in which unproducible oil columns are left between the vertical wells as a result of cusping and coning. Poor lateral continuity can be formed by a normal fault (B1) which, even when nonsealing over the juxtaposed reservoir interval, traps oil in the up-thrown block against the caprock in the down-thrown block. Depending on the throw of the fault, the structural dip and the distance of the vertical wells from the fault, a volume of oil will remain when the well water runs out. In labyrinth reservoirs one finds updip stratigraphic traps (B2) especially in low net/gross (N/G) cases. In such cases we also encounter poor sweep efficiency unless the well spacing is small (D). Poor sweep can also result from stratification with large permeability contrast between the beds, particularly when these are separated by impermeable intercalations (C). This situation is quite common in layer cake reservoirs. Even without impermeable separations crossflow may be limited if the vertical permeability of the low permeability layer is low. This situation frequently occurs in fluvial labyrinth reservoirs and this can occur in combination with configurations B1 and D.
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Bui, Khoa, I. Yucel Akkutlu, Andrei S. Zelenev, W. A. Hill, Christian Griman, Trudy C. Boudreaux y James A. Silas. "Microemulsion Effects on Oil Recovery From Kerogen Using Molecular-Dynamics Simulation". SPE Journal 24, n.º 06 (12 de julio de 2019): 2541–54. http://dx.doi.org/10.2118/191719-pa.
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Summary Source rocks contain significant volumes of hydrocarbon fluids trapped in kerogen, but effective recovery is challenged because of amplified fluid/wall interactions and the nanopore–confinement effect on the hydrocarbon–fluid composition. Enhanced oil production can be achieved by modifying the existing molecular forces in a kerogen pore network using custom–designed targeted–chemistry technologies. The objective of this paper is to show that the maturation of kerogen during catagenesis relates to the qualities of the kerogen pore network, such as pore size, shape, and connectivity, and plays an important role in the recovery of hydrocarbons. Furthermore, using molecular–dynamics (MD) simulations, we investigated how the transport of hydrocarbons in kerogen and hydrocarbon recovery can be altered with the delivery of microemulsion and surfactant micelles into the pore network. New 3D kerogen models are presented using atomistic modeling and molecular simulations. These models possess important chemical and physical characteristics of the organic matter of the source rock. A replica of Type II kerogen representative of the source rocks in the Permian Basin in the US is used for the subsequent recovery simulations. Oil–saturated kerogen is modeled as consisting of nine different types of molecules: dimethyl naphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane, and methane. The delivered microemulsion is an aqueous dispersion of solvent–swollen surfactant micelles. The solvent and nonionic surfactant present in the microemulsion are modeled as d–limonene and dodecanol heptaethyl ether (C12E7), respectively. MD simulation experiments include two stages: injection of an aqueous–phase microemulsion treatment fluid into the oil–saturated kerogen pore network, and transient flowback of the fluids in the pore network. The used 3D kerogen models were developed using a representative oil–sample composition (hydrogen, carbon, oxygen, sulfur, and nitrogen) from the region. Simulation results show that microemulsions affect the reservoir by means of two different mechanisms. First, during the injection, microemulsion droplets possess elastic properties that allow them to squeeze through inorganic pores smaller than the droplet's own diameter and to adsorb at the kerogen surfaces. The solvent dissolves in the oil phase and alters the physical and transport properties of the phase. Second, the surfactant molecules modify the wettability of the solid kerogen surfaces. Consequently, the recovery effectiveness of heavier oil fractions is improved compared with the recovery effectiveness achieved with surfactant micelles without the solubilized solvent. The results indicate that solubilized solvent and surfactant can be effectively delivered into organic–rich nanoporous formations as part of a microemulsion droplet and aid in the mobilization of the kerogen oil.
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Li, Kewen y Roland N. Horne. "A Decline Curve Analysis Model Based on Fluid Flow Mechanisms". SPE Reservoir Evaluation & Engineering 8, n.º 03 (1 de junio de 2005): 197–204. http://dx.doi.org/10.2118/83470-pa.
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Summary Decline-curve-analysis models are used frequently but still have many limitations. Approaches of decline-curve analysis used for naturally fractured reservoirs developed by waterflooding have been few. To this end, a decline-analysis model derived on the basis of fluid-flow mechanisms was proposed and used to analyze the oil-production data from naturally fractured reservoirs developed by waterflooding. Relative permeability and capillary pressure were included in this model. The model reveals a linear relationship between the oil-production rate and the reciprocal of the oil recovery or the accumulated oil production. We applied the model to the oil-production data from different types of reservoirs and found a linear relationship between the production rate and the reciprocal of the oil recovery as foreseen by the model, especially at the late period of production. The values of maximum oil recovery for the example reservoirs were evaluated with the parameters determined from the linear relationship. An analytical oil-recovery model was also proposed. The results showed that the analytical model could match the oil-production data satisfactorily. We also demonstrated that the frequently used nonlinear type curves could be transformed to linear relationships in a log-log plot. This may facilitate the production-decline analysis. Finally, the analytical model was compared with conventional models. Introduction Estimating reserves and predicting production in reservoirs has been a challenge for many years. Many methods have been developed in the last several decades. One frequently used technique is the decline-curve-analysis approach. There have been a great number of papers on this subject. Most of the existing decline-curve-analysis techniques are based on the empirical Arps equations: exponential, hyperbolic, and harmonic. It is difficult to foresee which equation the reservoir will follow. On the other hand, each approach has some disadvantages. For example, the exponential decline curve tends to underestimate reserves and production rates; the harmonic decline curve has a tendency to overpredict the reservoir performance. In some cases, production-decline data do not follow any model but cross over the entire set of curves. Fetkovich combined the transient rate and the pseudosteady-state decline curves in a single graph. He also related the empirical equations of Arps to the single-phase-flow solutions and attempted to provide a theoretical basis for the Arps equations. This was realized by developing the connection between the material balance and the flow-rate equations on the basis of his previous papers. Many derivations were based on the assumption of single-phase oil flow in closed-boundary systems. These solutions were suitable only for undersaturated(single-phase) oil flow. However, many oil fields are developed by waterflooding. Therefore, two-phase fluid flow (rather than single-phase flow)occurs. In this case, Lefkovits and Matthews derived the exponential decline form for gravity-drainage reservoirs with a free surface by neglecting capillary pressure. Fetkovich et al. included gas/oil relative permeability effects on oil production for solution-gas drive through the pressure-ratio term. This assumes that the oil relative permeability is a function of pressure. It is known that gas/oil relative permeability is a function of fluid saturation, which depends on fluid/rock properties.
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Huseby, Olaf K., Mona Andersen, Idar Svorstol y Oyvind Dugstad. "Improved Understanding of Reservoir Fluid Dynamics in the North Sea Snorre Field by Combining Tracers, 4D Seismic, and Production Data". SPE Reservoir Evaluation & Engineering 11, n.º 04 (1 de agosto de 2008): 768–77. http://dx.doi.org/10.2118/105288-pa.
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Summary To obtain improved oil recovery (IOR), it is crucial to have a best-possible description of the reservoir and the reservoir dynamics. In addition to production data, information can be obtained from 4D seismic and from tracer monitoring. Interwell tracer testing (IWTT) has been established as a proven and efficient technology to obtain information on well-to-well communication, heterogeneities, and fluid dynamics. During such tests, chemical or radioactive tracers are used to label water or gas from specific wells. The tracers then are used to trace the fluids as they move through the reservoir together with the injection phase. At first tracer breakthrough, IWTT yields immediate and unambiguous information on injector/producer communication. Nevertheless, IWTT is still underused in the petroleum industry, and data may not be used to their full capacity--most tracer data are used in a qualitative manner (Du and Guan 2005). To improve this situation, we combine tracer-data evaluation, 4D seismic, and available production data in an integrated process. The integration is demonstrated using data from the Snorre field in the North Sea. In addition to production data, extensive tracer data (dating back to 1993) and results from three seismic surveys acquired in 1983, 1997, and 2001 were considered. Briefly this study shows thatSeismic and tracer data applied in combination can reduce the uncertainties in interpretations of the drainage patterns.Waterfronts interpreted independently by tracer response and seismic dimming compare well.Seismic brightening interpreted as gas accumulation is supported by the gas-tracer responses. Introduction The Snorre field is located in the Tampen Spur area on the Norwegian continental shelf and is a system of rotated fault blocks with beds dipping 4 to 10° toward the northwest. The reservoir sections are truncated by the Base Cretaceous unconformity. The reservoir sections consist of fluvial deposits of the Statfjord and Lunde formations. The reservoir units contain thin sand layers with alternating shale in a complex fault pattern. A challenge regarding optimization of the reservoir drainage, as well as oil production, is to understand how the different sand layers communicate and to what degree the faults act as barriers or not. The present work concentrates on the integration of 4D-seismic and tracer methods to obtain information on fluid flow in the Upper Statfjord (US) and Lower Statfjord (LS) formations in the Central Fault Block (CFB). The outline of this fault block is indicated in Fig. 1. The net/gross ratio is higher and the reservoir quality is generally better in the US than the LS formation. The CFB is produced by water-alternating-gas (WAG) injection as the drive mechanism, where the injectors are placed downdip and the producers updip. The average reservoir pressure in the CFB is 300 bar, and the reservoir temperature is 90°C. Tracer data are used to understand fluid flow in the reservoir. The data give valuable information about the dynamic behavior and well communication, but in some cases the interpretation may be complicated by reinjection of produced gas and water. Tracer studies in the Snorre field have been presented previously in several papers (Dugstad et al. 1999; Ali et al. 2000; Aurdal et al. 2001). To use the data fully, however, integration with other types of reservoir data is important. The main objectives of the seismic monitoring of Snorre are to contribute to increased oil recovery and to optimize placement of new wells. 4D analysis, together with tracers, should potentially increase the multidisciplinary understanding of the drainage pattern in the reservoirs. The results should, in addition to all the reservoir and production data, be used actively in target-remaining-oil processes and in well planning. In addition, the 4D data can give input to update the geological model and simulation model (history matching) and to identify possible well interventions. There is also a potential to include the data in workflows to identify lithology changes.
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Mardashov, Dmitry V., Mikhail K. Rogachev, Yury V. Zeigman y Vyacheslav V. Mukhametshin. "Well Killing Technology before Workover Operation in Complicated Conditions". Energies 14, n.º 3 (28 de enero de 2021): 654. http://dx.doi.org/10.3390/en14030654.
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Well killing is an important technological stage before conducting workover operation, one of the tasks of which is to preserve and restore the natural filtration characteristics of the bottomhole formation zone (BFZ). Special attention should be paid to the choice of well killing technologies and development of wells in complicated conditions, which include abnormally low reservoir pressure, high oil-gas ratio and carbonate reservoir type. To preserve the filtration characteristics of the productive formation and prevent fluid losses in producing wells during well killing operation, blocking compositions are used. At the same time, an informed choice of the most effective well killing technologies is required. Consequently, there is a need to conduct laboratory physicochemical and coreflood experiments simulating geological, physical, and technological conditions of field development, as similar as possible to actual reservoir conditions. The article presents the results of experimental studies on the development well killing technologies of producing wells during workover operation in various geological, physical, and technological conditions of oil field development. Physicochemical and coreflood laboratory experiments were carried out with the simulation of the processes of well killing and development of wells in reservoir conditions with the use of modern high-technology equipment in the Enhanced Oil Recovery Laboratory of the Department of Development and Operation of Oil and Gas Fields at St. Petersburg Mining University. As a result of the experimental studies, new compositions of well killing and stimulation fluids were developed, which ensure to prevent fluid loss, gas breakthrough, as well as the preservation, restoration and improvement of the filtration characteristics of the BFZ in the conditions of terrigenous and carbonate reservoirs at different stages of oil field development. It is determined that the developed process fluids, which include surfactants (YALAN-E2 and NG-1), have a hydrophobic effect on the porous medium of reservoir rocks, which ultimately contributes to the preservation, restoration and improvement of the filtration characteristics of the BFZ. The value of the presented research results is relevant for practice and confirmed by the fact that, as a result of field tests of the technology for blocking the BFZ with the composition of inverse water–oil emulsion during well killing before workover operation, an improvement in the efficiency of wells operation was obtained in the form of an increase in their oil production rate by an average of 5–10 m3/day, reducing the time required for the well to start operating up to 1–3 days and reducing the water cut of formation fluid by 20–30%.
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Kaufman, R. L., H. Dashti, C. S. Kabir, J. M. Pederson, M. S. Moon, R. Quttainah y H. Al-Wael. "Characterizing the Greater Burgan Field: Use of Geochemistry and Oil Fingerprinting". SPE Reservoir Evaluation & Engineering 5, n.º 03 (1 de junio de 2002): 190–96. http://dx.doi.org/10.2118/78129-pa.
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Summary This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are:evaluation of vertical and lateral hydrocarbon continuity,identification of production problems caused by leaky tubing strings or leaks behind casing, andallocation of production to individual zones in commingled wells. Results from this study show that while oils from the major reservoir units are different from each other, the differences are small. Furthermore, a number of wells were identified in which mixed oils were produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data show that Third Burgan oils are different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supports the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study in both size and scope. Introduction This paper describes the results from a joint project by Chevron- Texaco Overseas Petroleum, the Kuwait Oil Co. (KOC), and the Kuwait Inst. for Scientific Research (KISR). Approximately 50 oils were analyzed to assess the feasibility of applying reservoir geochemistry in the Burgan field. All analytical work was performed at KISR. In this study, we report on a subset of these oils that contain primarily single-zone production samples. Reservoir geochemistry involves the study of reservoir fluids (oil, gas, and water) to determine reservoir properties and to understand the filling history of the field. Many established methods for exploration geochemistry can be used for this purpose. Reservoir geochemistry differs from other reservoir characterization methods by dealing primarily with the detailed molecular properties of the fluids in the C1-C35+ region rather than the physical properties. Larter and Aplin1 offer a review of many of these methods. Geochemistry techniques have been used to help solve reservoir problems for many years. During this time, oil geochemistry has been applied to the following reservoir characterization and management problems:Evaluation of hydrocarbon continuity.Analysis of commingled oils for production allocation.Identification of wellbore mechanical problems.Evaluation of workovers.Production monitoring for enhanced oil recovery (EOR).Identification of reservoir fluid type from rock extracts.Characterization of reservoir bitumens and tar mats. Many different analytical techniques have been used in these reservoir geochemistry studies. One of the most widely used is gas chromatography (GC). When used for oil correlation, it is often referred to as oil fingerprinting. In most reservoirs, the oil composition represents a unique fingerprint of the oil that can be used for correlation purposes.2 This is an inexpensive method and can be very cost-effective when compared to many production-logging methods. Of course, we recommend verifying this technique with other methods before reducing these more costly measurements. A number of papers have documented the application of oil fingerprinting to Middle East oil fields.3–7 Based on these studies, we felt that there was a high probability of success in using reservoir geochemistry in Kuwait's Burgan field. Three applications were of specific importance. Reservoir Continuity. The Burgan field contains several major producing horizons: the Wara, Third Burgan (Upper, Middle, and Lower), and Fourth Burgan reservoirs. Each of these is further subdivided into several reservoir layers. Vertical compartmentalization of the field, both in geologic and production time frames, is possible. In addition, a number of faults have been mapped in the field, and these may act as lateral barriers to fluid flow. The most significant faulting occurs in the central graben fault complex that separates the Burgan and Magwa/Ahmadi sectors of the field. Oil fingerprinting, along with other oilfield data, will be used to evaluate vertical and lateral compartmentalization in the field. Tubing-String Leaks. In many older fields, the integrity of casing strings and cement bonding is often a problem. If multiple pay zones are present, oil may leak into or behind the casing string from zones other than the completion interval. Many wells in the Burgan field produce from two reservoirs. Some wells, for example, produce Wara oil up the annulus and Third Burgan oil up the tubing string. When fingerprints of the individual oil zones have been identified, wellhead samples of the two production streams can be analyzed to determine if a mechanical problem is present.2,8 Production Allocation. It has been shown that the relative proportions of individual oils in an oil mixture can be determined with GC.9,10 Using this method to analyze production streams provides a rapid means of production allocation and does not require that wells be taken off production. In the Burgan field, this method will be applied to evaluate the extent of oil mixing either in the wellbore, owing to mechanical problems, or in the reservoir because of crossflow from deeper, higher-pressure reservoirs. The Burgan Oil Field The Greater Burgan oil field lies within the Arabian basin in the state of Kuwait. General reviews of the geology and producing history of the field are described by Brennan11 and by Kirby et al.12 The field is subdivided into the Burgan, Magwa, and Ahmadi sectors, based on the presence of three structural domes. Fig. 1 shows that the northern Magwa and Ahmadi sectors are separated from the southern Burgan sector by a central graben fault complex.
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Manceau, E., E. Delamaide, J. C. Sabathier, S. Jullian, F. Kalaydjian, J. E. Ladron De Guevara, J. L. Sanchez Bujanos y F. D. Rodriguez. "Implementing Convection in a Reservoir Simulator: A Key Feature in Adequately Modeling the Exploitation of the Cantarell Complex". SPE Reservoir Evaluation & Engineering 4, n.º 02 (1 de abril de 2001): 128–34. http://dx.doi.org/10.2118/71303-pa.
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Summary As with some thick and highly fractured Iranian fields, the Cantarell complex located offshore Mexico presents features [decreases in the production gas/oil ratio (GOR) and bubblepoint pressure with time] that reveal the effect of convection. This effect on the past homogenization of fluid properties is discussed and supported by a thorough characterization of the thermodynamic properties of actual reservoir fluids. To model convection, the reservoir simulator used for this study was purpose adapted. Sensitivity runs were performed to demonstrate the necessity of accounting for convection when matching the past history of the Akal field, which is part of the Cantarell complex. Introduction Presentation of the Cantarell Complex. The Cantarell complex is the most important oil field in Mexico, and the sixth-largest in the world. To economically optimize its value, it has been decided to initiate a major recovery process by injecting nitrogen for pressure-maintenance purposes. Cantarell field is a thick, highly fractured reservoir; therefore, it is the kind of reservoir where convection phenomena may occur. Convection is a complex process that is characterized by a vertical homogenization of fluid properties in the fractures. This may have an essential impact on production and injection profiles, in particular on the quantity of nitrogen in the effluents as well as nitrogen breakthrough times, and therefore on the overall nitrogen-injection efficiency. The Cantarell complex is located offshore approximately 85 km from Ciudad del Carmen. It includes four adjacent oil fields known as Akal, Chac, Kutz, and Nohoch. Akal is the largest oil accumulation, with more than 90% of the 35 billion barrels of oil in place. The reservoir is an anticline producing from the fractured carbonates of the Cretaceous and upper Jurassic formations, which also contain many vugs and caves. The Upper Cretaceous is the most fractured and brecciated. Fracturing decreases with depth in the Middle and Lower Cretaceous. The average thickness of the whole reservoir is about 775 m, and the depth of the top Cretaceous ranges between 1100 and 3600 m true vertical depth subsea (SS). Below the Cretaceous sequence, the Upper Jurassic (Oxfordian, Kimmeridjian, Tithonian) is a stratigraphic reservoir with poor reservoir characteristics. Field production started in June 1979, reaching a peak of 1.157 MMBOPD in April 1981, with 40 producing wells. A total of 184 wells were drilled in Cantarell, among them 173 wells in Akal alone. Cantarell crude is a 19 to 22°API Maya type, with an initial bubblepoint pressure close to 150 bar. Initially, the reservoir pressure was above the bubblepoint pressure and was equal to 266 bar at 2300 mSS; therefore, there was no initial gas cap. The reservoir pressure rapidly reached the bubblepoint pressure, and a secondary gas cap appeared in 1981. The gas/oil contact (GOC) was located at 1800 mSS in 1997. The corresponding cumulative oil production was around 5.5 billion STB. Accounting for Convection in Cantarell Complex. Cantarell field appears to have all the characteristics of a reservoir where convection may occur. As observed, for instance, in a major Iranian field,1 convection is a complex phenomenon that occurs in thick and highly fractured reservoirs. As explained in detail by Saidi,2 it results from a combination of thermal gradients, gas liberation at the GOC, and gravity segregation, and it is made possible by high vertical permeabilities. When the oil initially reaches the bubblepoint pressure, it liberates gas in solution, thus becoming heavier. Because of the high vertical permeability, this heavier oil can move downward while lighter oil heated from below expands and rises. A convection flux is then established, finally leading to a fast homogenization of the oil properties along the vertical depth. This leads to a reduction of the bubblepoint pressure in a vertical oil column. Indications that convection is taking place include more homogeneous oil properties and temperature on the vertical, change of the oil composition with time, and decline of bubblepoint pressure and production GOR with time. For Akal, producing GOR's were plotted vs. time for each well. The initial mean GOR value is approximately 90 vol/vol. The wells were organized into four classes: wells with decreasing then increasing GOR, wells with increasing GOR, wells with a constant GOR, and wells with a decreasing GOR. Fig. 1 shows a typical well with a decreasing behavior. Such a well generally begins producing with an initial GOR value of 90 vol/vol, then its GOR slowly decreases down to around 60 vol/vol. This means that the oil produced becomes heavier with time. Typically, this can be explained by convection. Fig. 2 shows the location of all the wells on the Cantarell field with their classification as of 1993. The corresponding GOC is also drawn. One can observe that the major part of the wells areally allocated close to the top of the structure, despite the vertical position of their completion, shows a GOR behavior other than constant as the reservoir pressure goes down, while the wells allocated through the flanks of the structure show a constant GOR behavior. This means that a complex phenomenon affecting the original fluid properties is taking place. Even though there is no evidence of convection, it is assumed that convection also takes place in the gas cap, leading to a faster homogenization in this area. However, this is not the main focus of this paper. To confirm this statement, three oil samples were taken in 1997 from three different zones of the reservoir: sample 1.07 was found close to the GOC, sample 1.11 was at an intermediate location, and sample 1.16 was in a deep zone, close to the water/oil contact (WOC). The bubblepoint pressures, as well as the flash GOR measured for each oil sample, are presented in Table 1. It can be observed that, for each crude sample, the oil is heavier than the initial oil in place and that the deeper the oil, the lighter it is.
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Andersen, Pål Østebø, Yangyang Qiao, Dag Chun Standnes y Steinar Evje. "Cocurrent Spontaneous Imbibition In Porous Media With the Dynamics of Viscous Coupling and Capillary Backpressure". SPE Journal 24, n.º 01 (26 de agosto de 2018): 158–77. http://dx.doi.org/10.2118/190267-pa.
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Summary This paper presents a numerical study of water displacing oil using combined cocurrent/countercurrent spontaneous imbibition (SI) of water displacing oil from a water-wet matrix block exposed to water on one side and oil on the other. Countercurrent flows can induce a stronger viscous coupling than during cocurrent flows, leading to deceleration of the phases. Even as water displaces oil cocurrently, the saturation gradient in the block induces countercurrent capillary diffusion. The extent of countercurrent flow may dominate the domain of the matrix block near the water-exposed surfaces while cocurrent imbibition may dominate the domain near the oil-exposed surfaces, implying that one unique effective relative permeability curve for each phase does not adequately represent the system. Because relative permeabilities are routinely measured cocurrently, it is an open question whether the imbibition rates in the reservoir (depending on a variety of flow regimes and parameters) will in fact be correctly predicted. We present a generalized model of two-phase flow dependent on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media because of fluid/rock interaction (friction) and fluid/fluid interaction (drag). These momentum equations effectively replace and generalize Darcy's law. The model is parameterized using experimental data from the literature. We consider a water-wet matrix block in one dimension that is exposed to oil on one side and water on the other side. This setup favors cocurrent SI. We also account for the fact that oil produced countercurrently into water must overcome the so-called capillary backpressure, which represents a resistance for oil to be produced as droplets. This parameter can thus influence the extent of countercurrent production and hence viscous coupling. This complex mixture of flow regimes implies that it is not straightforward to model the system by a single set of relative permeabilities, but rather relies on a generalized momentum-equation model that couples the two phases. In particular, directly applying cocurrently measured relative permeability curves gives significantly different predictions than the generalized model. It is seen that at high water/oil-mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less countercurrent to more cocurrent compared with conventional modeling. Although the viscous-coupling effects are triggered by countercurrent flow, reducing or eliminating countercurrent production by means of the capillary backpressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard cocurrent-imbibition setups.
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Kornberger, Martin y Marco R. Thiele. "Experiences With an Efficient Rate-Management Approach for the 8th Tortonian Reservoir in the Vienna Basin". SPE Reservoir Evaluation & Engineering 17, n.º 02 (27 de marzo de 2014): 165–76. http://dx.doi.org/10.2118/166393-pa.
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Summary Active well-rate management to promote the efficient use of injected fluids and to demote fluid cycling is a simple way to increase recovery in brown fields while minimizing costs and preserving existing field/well-fluid-handling constraints. In this work, we present the application of an efficient flow-based surveillance technique to drive rate-management decisions for the 8th Tortonian reservoir in the Vienna basin, Austria. The 8th Tortonian is a typical example of a decade-long peripheral waterflood on a long, steady decline for which it is difficult to justify expensive drilling/workover programs. Active rate management to improve pattern sweep presents an inexpensive solution to increase recovery. In case of the 8th Tortonian, EUR 10 000 (USD 13,000) was spent to modify well rates, resulting in approximately 5700-m3 (approximately 35,000-STB) incremental oil recovered during a 30-month period. The current oil rate remains higher than the oil rate before the start of the project. Our approach takes advantage of streamline-derived well-allocation factors (WAFs) to quantify injector/producer connections. It is simple and efficient to estimate WAFs with total historical well-fluid rates, well locations, and a geological model. With the WAFs, the ratio of produced oil to injected water (efficiency) of each injector/producer pair can be estimated. Well-pair efficiencies are the starting point for the rate-management approach described in this work. A simple, single-homogeneous-layer system was used in conjunction with historical rates and well locations to estimate the WAFs for the 8th Tortonian reservoir. Connections were compared with available tracer data, and an area of interest was subsequently selected in which both streamlines and tracer data confirmed oil recovery by injected water. A key constraint was to maintain the total gross rate of the area selected at current capacity. New target rates were determined and implemented, resulting in a 30% increase of oil rate during a 30-month period. Considering the simplicity and efficiency of the approach, this is a notable result. The production response of the selected wells showed an increased recovery in conjunction with a relatively constant water cut, suggesting contact with previously unswept oil. All operations and modifications were performed at minimal cost. There were no perforation changes or acidizing jobs involved, and rate changes were obtained simply by changing pump sizes or increasing the number of strokes by changing the V-belt pulley.