J.Sheng Enhanced Oil Recovery Field Case Studies

1. Auflage 2013
ISBN: 978-0-12-386546-5
Verlag: Elsevier Science & Techn.
Format: EPUB
Kopierschutz: 6 - ePub Watermark

E-Book, Englisch, 712 Seiten

Enhanced Oil Recovery Field Case Studies bridges the gap between theory and practice in a range of real-world EOR settings. Areas covered include steam and polymer flooding, use of foam, in situ combustion, microorganisms, 'smart water'-based EOR in carbonates and sandstones, and many more. Oil industry professionals know that the key to a successful enhanced oil recovery project lies in anticipating the differences between plans and the realities found in the field. This book aids that effort, providing valuable case studies from more than 250 EOR pilot and field applications in a variety of oil fields. The case studies cover practical problems, underlying theoretical and modeling methods, operational parameters, solutions and sensitivity studies, and performance optimization strategies, benefitting academicians and oil company practitioners alike. - Strikes an ideal balance between theory and practice - Focuses on practical problems, underlying theoretical and modeling methods, and operational parameters - Designed for technical professionals, covering the fundamental as well as the advanced aspects of EOR

Autoren/Hrsg.

J. Sheng, James

Leseproben

Chapter 1 Gas Flooding
Russell T. Johns1 and Birol Dindoruk2, 1The Pennsylvania State University, Department of Energy and Mineral Engineering, School of Earth Sciences Energy Institute, University Park, PA 16802, USA, 2Shell Exploration and Production Inc., Houston, TX, USA This chapter first defines what gas flooding is, and explains how recovery is enhanced by increasing both sweep and displacement efficiencies. The basic steps in gas flood design are described followed by the important technical parameters and scoping economics used in screening the best reservoirs for a gas flood. It is shown how gas is injected in wells through slug, continuous, or water-alternating-gas schemes. The importance of phase behavior on miscibility and equation-of-state (EOS) tuning is stressed, along with experiments needed for proper fluid characterization. It is also discussed how miscibility is developed through a multicontact process either by a vaporizing, condensing, or a combined condensing and vaporizing mechanism. The best techniques to estimate the minimum miscibility pressure (MMP) are given. Finally, three case studies and an overall summary of field experience are presented. Field displacements considered are CO2 flooding, nitrogen flooding, and an immiscible gravity stable CO2 flood. 1.1 What is Gas Flooding?
Gas flooding is the injection of hydrocarbon or nonhydrocarbon components into oil reservoirs that are typically waterflooded to residual oil (and perhaps in some cases as a primary or secondary method). Injected components are usually vapors (gas phase) at atmospheric temperature and pressure and may include mixtures of hydrocarbons from methane to propane, and nonhydrocarbon components such as carbon dioxide, nitrogen, and even hydrogen sulfide or other exotic gases such as SO2. Although these components are usually vapors at atmospheric temperature and pressure, they may be supercritical fluids at reservoir temperature and pressure in that some of their properties may be more liquid-like. Carbon dioxide, for example, has a density similar to that of oil, but a viscosity more like vapor at most reservoir conditions. Gas injection today often means CO2 or rich hydrocarbon gas injection to recovery residual oil, and in some cases to also store or sequester CO2 from the atmosphere. The primary mechanism for oil recovery by high pressure gas flooding is through mass transfer of components in the oil between the flowing gas and oil phases, which increases when the gas and oil become more miscible. Secondary recovery mechanisms include swelling and viscosity reduction of oil as intermediate components in the gas condense into the oil. The key to gas flooding is to contact as much of the reservoir with the gas as possible and to recover most of the oil once contacted. Injection gases are designed to be miscible with the oil so that oil previously trapped by capillary forces mixes with the injected gas. The injected gas or hydrocarbon phase then drives the oil components to the production well. Ideally, miscible flow is piston-like in that whatever gas volume is injected displaces an approximately equal volume of reservoir hydrocarbon fluid. Unfortunately, in real field applications such piston-like behavior does not occur because reservoir heterogeneities and gravity override cause gas to cycle through one or more high-permeability layers, bypassing some oil and leading to poor sweep efficiency. Mixing of oil and gas components within a single phase will also lead to nonpiston-like behavior even without geological heterogeneities. A proper gas flood design will consider both the microscopic displacement efficiency and sweep efficiency. The profitability of that process is a function of the overall recovery, which is expressed by ER=EVED. EV is the volumetric sweep efficiency, which is the fraction of the reservoir that is contacted by the gas, while the displacement efficiency ED is the fraction of contacted oil that is displaced. Displacement efficiencies for miscible floods at field scale are often on the order of 70–90%, while sweep efficiencies can be much worse, leading to typical incremental recoveries above waterflood recovery of only between 10–20% OOIP. Gas flooding designs are limited by both economics and physics of displacement so that there is often a trade-off between the sweep and displacement efficiencies. Because it is not possible to give exact values for these efficiencies in the field, they are useful only to qualitatively explain how key parameters such as injection fluid viscosity, phase behavior, heterogeneities, and other fluid and rock properties affect recovery and the design of gas flooding processes. Each reservoir is unique so that an engineer must have a good understanding of the fundamental processes. 1.2 Gas Flood Design
The engineering steps in gas flood design depend on whether a flood is a small or large project. For a large project there is more risk involved so that the process involves three basic steps; screening, design, and implementation. The basic design steps for a large flood are the following: 1. Technical and economic screening to eliminate reservoirs under consideration before a more detailed study is done; 2. Reservoir/geologic study, including 2-D and 3-D reservoir simulation to make performance predictions; 3. Wells and surface facility design based on forecasted fluid volumes, compositions and reservoir continuity; 4. Economic studies where key input variables are varied to understand associated risks; 5. Management approval (or disapproval) of the gas flood based on uncertainties and economic considerations; and 6. Implementation of the gas flood design by making wellbore modifications as needed, installing field facilities and any required recycle plant (if one is not already nearby), and injecting initial gas. These steps often require iteration as more is learned about the field when new wells are drilled, and laboratory data is obtained. Iterations in the design may also be required to maximum present value profit, for example, by changing the volume of gas injected. Small projects require fewer steps than larger projects as detailed reservoir studies, simulations, and associated predictions and economics may not be done to reduce costs. The screening process (step 1) is typically used to provide required predictions and economics for small gas floods. 1.3 Technical and Economic Screening Process
The primary objectives of the screening process are to: 1. Rank potential candidate reservoirs for gas flooding; 2. Identify potential injection fluids; 3. Identify analogue fields; 4. Make some preliminary production rate estimates and scoping economic calculations; and 5. Identify which reservoirs should be examined in a later more detailed analysis, especially if the gas flood is a large project. A good screening process will consider several key technical factors in addition to investment and operating costs. Typical reservoir screening considerations include 1. Residual oil saturation to waterflooding; 2. Average reservoir pressure (and temperature); 3. Oil viscosity and minimum pressure for miscibility; 4. Available miscible gas source and cost; 5. Reservoir heterogeneity and conformance issues at injection well and well pattern scale; 6. Reservoir permeability and ability to inject and produce fluids at economic rates; and 7. Reservoir geometry and flow: gravity effects and vertical permeability. Most fields undergo waterflooding prior to gas injection. This is typically done to increase reservoir pressure and reduce risks associated with potential gas flood projects. Risk is reduced if a secondary waterflood is done first because much is learned about well connections within the reservoir during water injection, and facility costs associated with water injection are already built. Thus, one of the most important initial screening factors is the residual oil saturation to waterflooding. If residual oil saturation is small (say less than 0.15), then there is little oil left to recover by gas flooding. Other important key technical factors are the average reservoir pressure, minimum pressure for miscibility, and the oil viscosity. The reservoir pressure must usually be near or above the minimum pressure for miscibility to achieve good displacement efficiency. The MMP is typically smaller for low viscosity oils. Rough “rules of thumb” for oils with bubble-point viscosities less than about 10 cp and an API oil gravity of 25 or greater are that CO2 or enriched gases become miscible with the oil when the reservoir pressure is above 1000 psia, while methane can become miscible with light oils at pressures greater than about 3000 psia, and nitrogen at pressures greater than about 5000 psia. Of course, reservoir temperature and oil composition play an important role in this assessment as well. The miscible fluid chosen should be available and less costly than other alternatives. Reservoir heterogeneity and conformance also plays an important role in screening. Conformance is defined as injecting fluids where you want them to go, usually into the pay zone. If a waterflood had poor conformance, either at injection wells or at the...