Alvord [3000 ft Strawn] LPG Flood Design and Performance Evaluation
Abstract: Mitchell Energy Corp. has implemented a liquefied petroleum gas (LPG)/drive-gas miscible process in the Alvord (3000 ft Strawn) Unit in Wise County, TX, utilizing the U.S. DOE tertiary incentive program. The field has been waterflooded for 14 years and was producing near its economic limit at the time this project was started.This paper presents the results of the reservoir simulation study that was conducted to evaluate pattern configuration and operating alternatives to maximize LPG containment and oil recov… Show more
Search citation statements
Paper Sections
Citation Types
Year Published
Publication Types
Relationship
Authors
Journals
Cited by 3 publications
References 7 publications
A multicomponent, three-phase, three-dimensional (3D)reservoir simulator has been developed for predicting miscible flood performance with particular emphasis onCO2 flooding. Several features, not all normally found represented in either a black-oil or compositional simulator, are represented in the simulator described here. These features include (1) heavy-end dropout and concomitant reduction in phase mobility, (2) water blocking of oil from an invading solvent, (3) viscous instability(fingering) at the CO2 displacement front, (4) miscible/immiscible transition as a function of pressure and composition, and (5) loss of CO2 to the aqueous phase. The solution scheme employs an implicit in pressure, explicit in saturation and composition time integrationscheme (IMPES). This scheme allows for ready use ofa second-order correct spatial discretization. We havefound that for field applications, a numerical grid fine enough to represent waterflood performance accuratelyis usually sufficient for representing CO2-miscible-typeprocesses as well. The program automatically employsa stabilized Runge-Kutta time discretization to alleviatethe usual stability limitations imposed by the IMPES procedure. Up to 49 times the usual stable timestep size canbe employed for seven times as much computing work. Work required to simulate a given time period when stability is limiting was improved overall by a factor of seven. To date, we have not encountered a pattern flood displacement simulation where the increased timestep size provided by the Runge-Kutta scheme has not been adequate to maintain stability for time steps chosen so as to limit truncation error. The CO2 flood simulator described has been in application for 4 years. The simulator has been used for design of CO2 EOR projects and interpretation of CO2injectivity tests in several low-temperature west Texas SanAndres dolomite reservoirs as well as high-temperature sandstone reservoirs. In addition to CO2 applications, the simulator has been used for the design of liquefied petroleum gas/dry gas flooding processes and for examining the effect of injection gas composition on oil recovery performance for immiscible gas drives. Introduction In a previous paper, we reported on the results of a study aimed at determining modeling requirements for numerical simulation of CO2 recovery processes. The study included a review of the open literature as well as a composite of ideas and suggestions offered by research groups of 11 major oil companies. The study concluded that although both black-oil and compositional simulators have characteristics that are desirable, neither is truly suitable for predicting all of the significant features of the CO2-flood recovery process. Drawing from both models, specifications were suggested for a field-orientednumerical simulator. The aim of this simulator would beto reproduce the displacement characteristics that are significant relative to prediction of oil recovery performance by CO2 injection for realistic reservoir descriptions. In this paper, we describe a numerical simulator constructed essentially on these specifications. Modeling Assumptions Our CO2 flood simulator has been designed to reproduce the effects of the major mass transfer and phase transport phenomena known to be associated with CO2 EOR processes. For immiscible conditions, phase equilibria may be entered in the simulator so as to represent EORmechanisms of oil-phase swelling with condensed CO2 and vaporization (or extraction) of hydrocarbon fractionsinto the CO2-rich phase. Multicontact miscible (MCM)displacement may be represented explicitly with the program by entering appropriate phase equilibrium data. However, the philosophy of the modeling technique employed in the program is to maintain segregated CO2-rich and oil-rich regions. By controlling the degree of segregation of these regions through the mixing parameter approach, the important phenomenon of viscous fingering, characteristic of highly unfavorable mobility ratio displacements, may be represented without describing the detailed structure of the unstable frontal advance. Local miscibility is determined by comparing computed pressure with a miscibility pressure entered intothe program as a function of composition. Here, again, the philosophy is to represent miscible displacement andmiscible/immiscible transition without describing the detailed compositional path required for explicitly representing MCM. The motivation, both for using the mixing parameter model for representing unstable frontal advance and themiscibility-pressure approach for representing MCM, isto allow predictions of field performances with realistic reservoir descriptions using reasonable numbers of gridblocks. In fact, a numerical grid fine enough to describe waterflooding performance accurately in most cases will be adequate for predicting CO2 flood performance with this simulator. SPEJ P. 597^
A multicomponent, three-phase, three-dimensional (3D)reservoir simulator has been developed for predicting miscible flood performance with particular emphasis onCO2 flooding. Several features, not all normally found represented in either a black-oil or compositional simulator, are represented in the simulator described here. These features include (1) heavy-end dropout and concomitant reduction in phase mobility, (2) water blocking of oil from an invading solvent, (3) viscous instability(fingering) at the CO2 displacement front, (4) miscible/immiscible transition as a function of pressure and composition, and (5) loss of CO2 to the aqueous phase. The solution scheme employs an implicit in pressure, explicit in saturation and composition time integrationscheme (IMPES). This scheme allows for ready use ofa second-order correct spatial discretization. We havefound that for field applications, a numerical grid fine enough to represent waterflood performance accuratelyis usually sufficient for representing CO2-miscible-typeprocesses as well. The program automatically employsa stabilized Runge-Kutta time discretization to alleviatethe usual stability limitations imposed by the IMPES procedure. Up to 49 times the usual stable timestep size canbe employed for seven times as much computing work. Work required to simulate a given time period when stability is limiting was improved overall by a factor of seven. To date, we have not encountered a pattern flood displacement simulation where the increased timestep size provided by the Runge-Kutta scheme has not been adequate to maintain stability for time steps chosen so as to limit truncation error. The CO2 flood simulator described has been in application for 4 years. The simulator has been used for design of CO2 EOR projects and interpretation of CO2injectivity tests in several low-temperature west Texas SanAndres dolomite reservoirs as well as high-temperature sandstone reservoirs. In addition to CO2 applications, the simulator has been used for the design of liquefied petroleum gas/dry gas flooding processes and for examining the effect of injection gas composition on oil recovery performance for immiscible gas drives. Introduction In a previous paper, we reported on the results of a study aimed at determining modeling requirements for numerical simulation of CO2 recovery processes. The study included a review of the open literature as well as a composite of ideas and suggestions offered by research groups of 11 major oil companies. The study concluded that although both black-oil and compositional simulators have characteristics that are desirable, neither is truly suitable for predicting all of the significant features of the CO2-flood recovery process. Drawing from both models, specifications were suggested for a field-orientednumerical simulator. The aim of this simulator would beto reproduce the displacement characteristics that are significant relative to prediction of oil recovery performance by CO2 injection for realistic reservoir descriptions. In this paper, we describe a numerical simulator constructed essentially on these specifications. Modeling Assumptions Our CO2 flood simulator has been designed to reproduce the effects of the major mass transfer and phase transport phenomena known to be associated with CO2 EOR processes. For immiscible conditions, phase equilibria may be entered in the simulator so as to represent EORmechanisms of oil-phase swelling with condensed CO2 and vaporization (or extraction) of hydrocarbon fractionsinto the CO2-rich phase. Multicontact miscible (MCM)displacement may be represented explicitly with the program by entering appropriate phase equilibrium data. However, the philosophy of the modeling technique employed in the program is to maintain segregated CO2-rich and oil-rich regions. By controlling the degree of segregation of these regions through the mixing parameter approach, the important phenomenon of viscous fingering, characteristic of highly unfavorable mobility ratio displacements, may be represented without describing the detailed structure of the unstable frontal advance. Local miscibility is determined by comparing computed pressure with a miscibility pressure entered intothe program as a function of composition. Here, again, the philosophy is to represent miscible displacement andmiscible/immiscible transition without describing the detailed compositional path required for explicitly representing MCM. The motivation, both for using the mixing parameter model for representing unstable frontal advance and themiscibility-pressure approach for representing MCM, isto allow predictions of field performances with realistic reservoir descriptions using reasonable numbers of gridblocks. In fact, a numerical grid fine enough to describe waterflooding performance accurately in most cases will be adequate for predicting CO2 flood performance with this simulator. SPEJ P. 597^
SPE Member Abstract This paper discusses the role reservoir simulators play in formulating initial development plans, history play in formulating initial development plans, history matching and optimising future production and in planning and designing enhanced oil recovery projects. The Hibernia Field in Canada and the Hassi R'Mel in Algeria illustrate how simulation can be used to assist in initial reservoir development. The Lookout Butte Rundle (Alberta) and other are cited to exemplify optimisation of future production plans with the aid of simulation. Finally, applications to plans with the aid of simulation. Finally, applications to several reported EOR projects are briefly discussed with major emphasis concentrating on the Bati Raman Field in Turkey. Introduction The purpose of this paper is to provide an overview on the role of reservoir simulation in managing hydrocarbon reservoirs. As pointed out by Coats, reservoir simulation, in the broad sense, has been practiced, since the 1930's, when some of the first calculational procedures were developed to predict reservoir performance. Here, however, we take a predict reservoir performance. Here, however, we take a narrower view, and restrict our discussion to applications of numerical reservoir simulation. This involves solving large sets of algebraic equations on digital computers to approximate transient, multiphase or multicomponent flow in heterogeneous media. This technology started in the mid to late 1950's and, within the last twenty years, has played an increasingly important role in the development, planning and management of gas and oil reservoirs. In the following, we first discuss the role of reservoir simulation as a tool in planning the initial development of a reservoir. The discussion then turns to their uses as predictive tools when investigating various future operating strategies. Finally, some attention is devoted to their utility in planning and executing enhanced oil recovery schemes. Illustrations in the form of case histories are provided, albeit these are necessarily not detailed because of space limitations. Nevertheless, sufficient references to recent literature on the -subject are given for the interested reader. SIMULATION AND VIRGIN RESERVOIR DEVELOPMENT When a reservoir simulator is employed to assist in planning the development of a virgin reservoir, the planning the development of a virgin reservoir, the reservoir description is typically limited. Consequently, only a minimal degree of optimisation is possible. Nevertheless, some useful insights can be obtained with the aid of a simulator that can minimise the number of decisions one must make in planning field development. In particular, the simulator can and should be used to assess sensitivity in computed results to uncertainties in the reservoir description and rock-fluid data. It is surprising how often variations in input data over reasonable ranges of uncertainty, for some reservoirs, yield modest changes in the computed result. On the other hand, it is useful to know, in the early stages of development, where the greatest effort should be concentrated to obtain those data that affect calculated performance the most. performance the most. Simulation studies at the development stage, because of the uncertainties involved, are regarded as preliminary. Typically, they are periodically updated as preliminary. Typically, they are periodically updated as more information becomes available. This means that early development plans arising from the first simulation studies should be sufficiently flexible to accommodate future contingencies as one learns more about the reservoir. This presents a severe challenge where the reservoir in question is highly complex, large in extent or in a hostile environment all of which may require large investments to put it on production. In cases where the reservoir description and rock-fluid properties are reasonably defined, one can use a simulator to plan well locations and densities assuming voidage replacement by injection to maintain pressure. Such strategic,, can be compared to primary depletion through the same number of wells to arrive at the best development policy for the reservoir. Application to the Hibernia Field To illustrate, we cite the Hibernia Field off the eastern coast of Canada. The field lies about 320 km southeast of St. John's, Newfoundland in a water depth of 80 m. Five wells were drilled to confirm the existence of substantial hydrocarbon reserves in at least two reservoirs, the Avalon and the Hibernia sandstones. P. 13
A great deal of information has been published on the use of surfactants in CO2 foam published on the use of surfactants in CO2 foam flooding applications. However, generally the chemical composition of the surfactant has not been specified and little work describing the relationship of surfactant chemical structure and physical properties to foaming agent performance physical properties to foaming agent performance has been reported. This laboratory study examines the performance of more than 40 surfactants in 1 atmosphere foaming experiments. Several classes of surfactants were studied including alcohol ethoxylates, alcohol ethoxysulfates, alcohol ethoxyethylsulfonates and alcohol ethoxyglyceryl-sulfonates. Surfactants which performed well in the 1 atmosphere (1.01 × 105 Pa) foaming experiment were also good foaming agents in sight cell and core flood experiments performed in the presence of CO2 and reservoir fluids under realistic reservoir temperature and pressure conditions. Introduction Many miscible floods have exhibited early breakthrough of injected fluids and concomitant poor volumetric sweep efficiency and lower than poor volumetric sweep efficiency and lower than predicted oil recovery. Viscous fingering of predicted oil recovery. Viscous fingering of fluids has been studied extensively in the laboratory. Water-alternate-gas (WAG) injection to decrease carbon dioxide (CO2) mobility has been widely used. Stalkup has reviewed results of several CO2 floods and concluded that the WAG process was only "partially successful in process was only "partially successful in moderating CO2 production." Other methods of increasing the injected gas breakthrough time and reducing the produced gas:oil ratio (GOR) include zone isolation, decreasing the gas injection rate, and use of horizontal injection and production wells. production wells. The use of foams to reduce CO2 mobility was initially patented by Bernard and Holm and has been the subject of a number of publications since that time. Foam exhibits higher apparent viscosity and lower mobility within a formation than its separate constituents. This lower mobility may often be achieved by the inclusion of less than 0.01% surfactant in the liquid phase of the foam. Among the surfactants phase of the foam. Among the surfactants that have been studied for miscible gas mobility control are ethoxylated alcohols particularly those in the C12-15 range, sulfate and sulfonate esters of ethoxylated linear alcohols, alkylphenol ethoxylates, and low molecular weigh ethylene oxide—propylene oxide copolymers. While 1 atmosphere foaming experiments permitted the screening of large numbers of permitted the screening of large numbers of surfactants, conclusions drawn from data were often not specific enough to permit surfactant optimization. Often, results were not extended to study foam behavior under realistic reservoir conditions. Design and optimization of chemical structure and compositions of foaming agents in the presence of brines and crude oil under realistic reservoir temperature and pressure conditions has been carried out by Wellington. During the course of this work, he developed a one atmosphere foam stability screening test. In this paper, the one atmosphere screening test (modified as described below) is used to relate surfactant foaming properties to chemical structure, to rank large numbers of surfactants in terms of foam stability and to observe the foam sensitivity to the presence of crude oil, aqueous fluid salinity and pH, and temperature. The best surfactants were then studied under reservoir temperature and pressure conditions using a sight cell and pressure conditions using a sight cell and evaluated further using carefully designed core flood experiments.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
Contact Info
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Product
Resources
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.
