Characterization of reservoir fluids is important for developing a strategy tomanage the reservoir production scheme effectively and efficiently. Reservoirfluid properties (e.g., density, viscosity, gas/oil ratio, bubble-pointpressure, compressibility, and formation volume factor) are crucial for bothreservoir and petroleum engineering; they are the fundamental inputs formaterial balance calculation, determination of oil reservoir volumes, andestimation of oil recovery with the use of a reservoir simulator. Ideally, thereservoir fluid properties are determined from laboratory studies on thebottomhole samples or on the recombined separator oil and gas samples. Whenonly field measurements or limited laboratory data are available, empiricalblack oil correlations can be used to determine the essential fluid propertieswithout the knowledge of fluid compositions. In the past few decades, withlarge sets of petroleum fluid data at various reservoir conditions andproperties, the development of black oil correlations forpressure-volume-temperature (PVT) analysis study has been researchedextensively. Consequently, numerous correlations that are applicable to varioustypes of oil have been proposed and published. In this paper, we compare andprovide guideline for the various correlations that were used to determine theblack oil fluid properties. For this study, more than 30 theoretical and empirical black oil correlationsfor bubble-point pressure, gas/oil ratio and oil formation volume factor werereviewed and validated; variations of the calculated fluid properties versusinput parameters were studied and compared across the stated ranges ofapplicability. The comparison results are presented graphically. Thecorrelations of this study are also summarized in tables that can be used toguide PVT users in selecting the most appropriate black oil correlation forspecific reservoir fluids and conditions. Introduction The physical properties of the reservoir fluids are very important input datain reservoir engineering calculations. Well characterized reservoir fluidproperties are crucial for a good estimate of oil or gas reserves, productionforecasts and the efficiency of enhanced oil recovery (EOR) methods. It is notalways the case that reservoir fluid samples are available and thoroughlystudied to characterize the reservoir fluid properties in the most accuratemanner. In situations where no samples are available, one must rely onempirically derived correlations to estimate the physical properties ofreservoir fluid. This paper reviews the existing black oil correlations thathave been published in the literature and elaborates how they are used in ourin-house consolidated pressure-volume-temperature (PVT) library. There are many parameters to be considered for reservoir characterization andmodeling; however in this paper we focus and discuss on those publishedcorrelations for bubble-point pressure, gas/oil ratio and oil formation volumefactor. The decision was made as these parameters are more influential in theaccuracy of fluid properties calculation and facilities planning than otherssuch as fluid compressibility, viscosity, density and etc. In the first part of this paper, we present a literature review of variouscorrelations for bubble-point pressure, gas/oil ratio and oil formation volumefactor. For each correlation, the origin of oil used for the developedcorrelation is presented, its range of applicability and any related potentialissues are discussed. In the second part, the studied correlations that havebeen used in our in-house consolidated PVT library are summarized, compared anddiscussed, together with their applicability.
In this study, a transient multiphase simulator has been used to characterize the fluid-hammer effects of well shut-in and start-up on the coupled subsurface and surface systems. The original work was performed by applying sensitivity analysis on a typical production system that includes well completion, wellbore, downhole equipment like packer etc., and the associated surface equipment like flowline, riser and valves. The data used in the study was taken from the published literature to summarize the general course of key factors that worsen the fluid-hammer effects. Fluid-hammer is also known as water hammer, a shock wave produced by the sudden stoppage or reduction in fluid flow. Field operations such as pressure transient analysis, facility maintenance and workover require well shut-in process. For a typical production system, the resulted sudden rises in pressure can be critical because it has direct impact on equipment including unsetting of packer and may also cause possible damages to instrumentations. This paper provides estimates of the typical ratio of transient shock in pressure and flowrate over pre-condition values, and the duration of such pressure shocks. It also proposes the best location of the shut-in valve and the length of flowline to reduce the fluid-hammer effects. This is a pioneering approach to integrate multiphase flow modeling of transient fluid-hammer effects, targeting flow assurance issues. This approach also can be applied to surface facility design and served as guidance in field operation to avoid hydrocarbon leaks.
Nowadays the oil and gas industry devotes great attention and efforts to unconventional hydrocarbon resources. Production operations on these resources are often challenging due to possible complex risks, and flow reliability can become a key concern upon high intervention costs. Understanding and managing the related risks require detailed multidisciplinary engineering analysis involving accurate fluid characterization and advanced multiphase flow simulations. This practice of ensuring successful and economical flow of hydrocarbons is called Flow Assurance (FA); which alsohas become a substantial consideration in reservoir management. This paper firstly presents an innovative rating system covering all types of FA problems by Design of Experiments (DoE) and Fuzzy Logic methods respectively. With the emerging digital field technologies, this work can subsequently propose an integrated management workflow on addressing various FA issues. Supported by a case study, this paper demonstrates the importance of this decision-making process in light of the proposed workflow. A remedy for one identified FA problem may result negative side effects for a production system over years, and subsequently decrease the reserves and the project profitability.
Field development planning for an asset requires close interaction between different domains and departments, to reduce any potential uncertainties within the studied asset. Reducing uncertainties is crucial in investment preparation for a new green field development. By adopting an integrated asset approach, such cross-department interactions can be further improved by breaking down the barriers and assembling an integrated asset team with a common goal. This paper summarizes the construction of an integrated asset study for an offshore green field and compares the study against those obtained from the standalone-domain models. In this study, a reservoir simulation model was coupled to the wells and network models, which were further integrated to the processing facilities models and the asset economics evaluation model.The aim of the study was to evaluate an existing field development plan (based on the traditional standalone approach) with an integrated asset approach to identify any possible constraints and potential deviations, enabling proactive actions to be taken on the asset management for future operations. The work presented here encompasses the use of various numerical simulation software applications working together in a single simulation environment, which allowed sensitivity analysis on different elements of the asset and evaluation of any possible impacts among the studied elements, such as manifold choke sizing and gas lifting parameters.This assessment consists of a study from reservoir to economics, taking into account of wells, pipelines, surface equipment, production networks and downstream process facilities. The study demonstrated any components of the production network system and topside operating condition could impose constraints on the reservoir deliverability. Apart from evaluating various operating scenarios to best utilize the emerging capacity and to investigate back-out efforts and other challenges during the field development, it also provided guidance on how to further optimize the production system in terms of finding choke sizes over time and adjusting gas lift injection according to gas availability and operating pressure constraint. With its integrated asset approach, this study also presented a base case that could be extended with inclusion of gas lift distribution system to enable a more comprehensive analysis and asset field development study.
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