DOCSLIB.ORG

New Approach for In-Line Production Testing for Mature Oil Fields Using Clamp-On SONAR Flow Metering System

Total Page：16

File Type：pdf, Size：1020Kb

Download full-text PDF Read full-text
New Approach for In-Line Production Testing for Mature Oil Fields Using Clamp-On SONAR Flow Metering System New Approach For In-Line Production Testing for Mature Oil Fields Using Clamp-on SONAR Flow Metering System Giovanni Morra, Sara Scagliotti (Eni E&P) Dhia Naeem, Ali Al Alwan (South Oil Company Iraq) Siddesh Sridhar, Ahmed Hussein (Expro Meters) Abstract Monitoring produced oil, gas and water rates from individual wells plays an important role in reservoir management and production optimization. While beneficial, obtaining timely and accurate wellhead measurements can be challenging due to a range of factors. This paper describes a cost-effective and convenient approach to production surveillance of black oil wells using clamp-on flow meters (Sonar), integrated with a PVT and multiphase flow engine to calculate the properties of the produced fluids, and the individual phase flow rates. The PVT engine calculates the gas and liquid properties of the produced fluids, at the pressure and temperature conditions measured where the Sonar flow meter is clamped-on. The Sonar flow meter provides a direct measurement of the mixture flow velocity within the flow line. The mixture flow velocity is then interpreted in terms of actual gas and liquid flow rates. Once the gas and liquid flow rates are determined at actual conditions, the oil, water, and gas flow rates are reported at standard conditions based on the PVT data calculated by the PVT engine. The new approach was deployed in a mature field to test 6 different wells against existing conventional test separators as the reference. The tests showed that Sonar meters could be installed either upstream or downstream of the choke manifold thus allowing more flexibility in terms of field installation. Some of the wells were tested at fixed flowing conditions while others were tested at multiple choke settings. All data is found to be within acceptable limits. The results show that, overall, the new Sonar-based approach could perform within ±15% or better from the reference, depending on the accuracy of the input PVT data (including water cut) and the flowing conditions. The new clamp-on approach requires about 90 minutes for installation and commissioning which allows the possibility to perform multi-rate testing of the wells in one day. Therefore, the Sonar clamp-on methodology offers the opportunity to increase the well rate measurement frequency at a field-wide level thus allowing a field production back-allocation with consequent benefits in field/production management. Introduction Accurate measurement of net oil rate from individual wells is a critical component in effective oil field management, influencing production optimization strategies and allocation issues. The main equipment currently used for this purpose in the field is either the CTS (Conventional Test Separators) or the MPFM (conventional Multi Phase Flow Meter). The separators in the field DGS (De-Gassing Station), which were originally designed as test separators, are currently being used as Production Separators (PS).The field under investigation is characterized by both carbonate and sandstone reservoirs on production since more than 60 years. A total of 240 wells have been drilled, of which more than 100 (40 in natural flow and 60 completed with ESP) are on production and 40 are water injectors. Assuming that each producing well should be tested at least twice a year, more than 200 well tests need to be performed per year. Considering the fact that each test takes an average of 3 days, the consequences are quite significant: a. Multiple well test packages would be required to accomplish the desired testing frequency, which may not be available and may be cost prohibitive. b. The amount of gas and oil flared to the atmosphere may exceed environmentally accepted levels, unless the existing wellhead connections and well test equipment are modified. c. The production losses/deferral associated with traditional well testing methodologies may be significant. d. Shutting in wells to rig up test equipment can negatively impact the long-term performance of the well. e. Higher HSE risk associated with the increased number of well tests. The solution of re-injecting the produced fluids into the flow line has been already considered for the new well site facilities. To achieve this, it is necessary to have two gate valves in the production flow line, one to connect the well with the CTS and the other one for re-injection. The MPFM offers a flare-less alternative, but it is usable only where the two gate valve system has already been implemented at the well site. In order to address some of the shortcomings described above, it was decided to evaluate the capabilities of Sonar metering as an alternative for well testing. 2 To evaluate the feasibility of using the clamp-on Sonar as an alternative for well testing, it was initially decied to do a preliminary trial on two wells. The tests were carried out on wells A-01 and A-02 in conjunction with ongoing production testing activities. The CTS was used as a reference to check the Sonar meter accuracy. At the conclusion of the preliminary trial, it was deemed that the technology was suitable for the field, providing sufficient accuracy and easy handling in terms of field deployment and installation. It was consequentially decided to deploy Sonar metering on a larger scale in a field-wide well test campaign.The field-wide campaign comprised the testing of 94 wells (including 3 water injection wells) over a period of 108 days. The Sonar results from the individual producing wells were aggregated and compared to the total production rates as measured at the Degassing Stations. The aggregate Sonar production data was in reasonable agreement with the actual production rates as measured at the DGS and to hydraulic well models expectations. In order to address some differences seen between the Sonar test results and the expected flow rates, 4 wells were retested against the CTS at the conclusion of the Sonar field-wide campaign. Again, the results showed that the Sonar meters performed within expectations. This paper presents the results of the Sonar testing, including detailed comparisons between the Sonar and CTS oil, gas and water rates for the six wells where reference data is available. a. Production Allocation / Well Testing Worldwide, the majority of oil & gas production allocation is achieved using separator-based measurements. Test and production separators are generally used to allocate production from individual wells and fields. Most separator-based measurement methodologies rely on the assumption of complete separation of the gas and liquid phases prior to measurement. In practice, however, complete separation is often difficult, if not impractical, to achieve, the accuracy of separator- based measurements could be limited by flow instrumentation-related issues. On the flow measurement side, the test separator functionality may be limited by the quality of the incoming fluid stream, which many times requires further processing, such as de-sanding (or solids removal), in order to protect both the separator and the ancillary instrumentation. In addition, sanding and/or solids may cause the separator to be by-passed for certain periods of time, with no flow measurements available during the by-pass period. Another potential issue is incorrect selection and sizing of flow meters on the liquid and gas legs of the CTS (for example, wrong orifice plate size) which may yield inaccurate measurement results. The size and the cost associated with mobilizing and operating CTS packages in the field may also limit the number of wells to be tested. Therefore, for field management purposes, various schemes and models are often developed to infer the production rates for each well. These models are used to predict individual well performances and in turn to make selection of intervention and work-over methods based on incomplete data with regard to actual well performances. To reduce the uncertainties of the models and the consequent risk associated to the selection of the interventions, it is mandatory to strengthen them with measured data. This data has been provided efficiently by Sonar Clamp-on meter within the required timeframe. b. Overview of Technology Clamp-on Sonar-based flow meters utilize Sonar processing techniques to determine the speed at which naturally occurring, coherent flow structures convect past an array of sensors clamped-on to the outside of the pipe. Figure 1 illustrates the naturally occurring, self-generated, coherent structures present within turbulent pipe flows. Naturally occurring, self-generating, turbulent eddies are superimposed over the time-averaged velocity profiles. These coherent structures contain fluctuations with magnitudes on the order of 10 percent of the mean flow velocity and are carried along with the mean flow. These eddies remain coherent for many pipe diameters and convect at, or near, the volumetrically-averaged flow rate in the pipe. 3 Figure 1 : Sonar-based Flow Meters with Coherent Structures within Pipe Flows In Sonar array processing, the spatial/temporal frequency content of sound fields are often displayed using “K-ω" plots. K-ω plots are presented as surface plots in which the power of a sound field is allocated to bins corresponding to specific spatial wave numbers and temporal frequencies. On a k-ω plot, the power associated with coherent structures convecting along with the flow is distributed along “the convective ridge”. The slope of this ridge indicates the speed of the turbulent eddies. Thus, identifying the slope of the convective ridge determines volumetric flow rate. Slope – 34 ft/sec K Figure 2: K-w plot from a Clamp-on Sonar meter on a Gas Well Figure 2 shows an example of a k-ω plot generated from the diagnostic output of a Sonar flow meter clamped on to a 4-inch, schedule 80 pipe with black oil flowing at 30 barg. As shown, the k-ω plot exhibits a well-defined convective ridge.
Load more

Recommended publications
  • Production Management
    Process Solutions Guide Production Management Key Benefits Common Common GAS • Improve availability of wells and Header #1 Header #2 Gas Lift GAS facilities Production Separator OIL • Manage declining production and Well 1 Oil / Gas / Water WATER dynamic production characteristics Test Separator Flow • Improve reservoir modeling GAS Computer 3-Phase Separator OIL • Reduce cost of maintenance and Well 40 WATER operations 2-Phase GAS Turbine Water Cut Separator Meter Probe OIL & WATER Proven Coriolis Applications Net Oil Tank • Gas lift System Coriolis Computer Meter • Volume measure of oil, gas and MANUAL/AUTO produced water SAMPLING Process Diagram • Net oil / water cut Process Overview Production management involves establishing and maintaining optimal hydrocarbon production rates (oil / natural gas) while maximizing the overall recovery of the hydrocarbons available in the reservoir (yield). Production facilities are either oil or natural gas predominant and depending upon the type of reservoir or production methodology employed can produce various combinations and quantities of oil / condensate, natural gas and water. Well production is dependent upon the rate at which hydrocarbons flow toward the well bore and the reservoir pressure available to move the fluids to the surface for production. Over time, well production is typically assisted through artificial lift technology to help pump produced fluids to the surface. This can involve surface rod pumps, Electric Submersible Pumps, plunger lift or gas lift systems. Decline in reservoir pressure is countered with Secondary Recovery methods that involve the injection of natural gas or water back into the reservoir through injection wells to maintain reservoir pressure. The produced fluids from each well are measured to determine the volume production rate of oil, natural gas and water from each well in the field.
    [Show full text]
  • The Expanding Scope of Well Testing
    59605schD7R1.qxp:59605schD7R1 5/25/07 4:25 PM Page 44 The Expanding Scope of Well Testing Well testing has come a long way since the first drillstem test was run in 1926. From a simple composite packer and valve run on drillstring, the scope of well testing has blossomed into a broad array of sophisticated downhole and surface technologies. Hani Aghar Every E&P company wants to know what type of By measuring in-situ reservoir conditions and In Salah Gas (Joint venture of fluids its well will produce, what flow rates the fluids as they flow from the formation, the testing Sonatrach, BP and Statoil) well will deliver, and how long production can process gives E&P companies access to a variety Hassi-Messaoud, Algeria be sustained. Given the right planning, of dynamic and often unique measurements. technology and implementation, well testing can Depending on the scale of a test, some param - Mark Carie provide many answers to these important eters are measured at multiple points along the New Orleans, Louisiana, USA questions. In one form or another, well testing flow path, allowing engineers to compare Hani Elshahawi has been used to determine reservoir pressures, downhole pressures, temperatures and flow rates Shell International Exploration distance to boundaries, areal extent, fluid against surface measurements of the same and Production properties, permeability, flow rates, drawdown parameters (below). Through well testing, Houston, Texas, USA pressures, formation heterogeneities, vertical operators can extract reservoir fluid samples— layering, production capacity, formation damage, both downhole and at the surface—to observe Jaime Ricardo Gomez productivity index, completion efficiency changes in fluid properties and composition Jawaid Saeedi and more.
    [Show full text]
  • Well Testing Systems
    NORSOK STANDARD SYSTEM REQUIREMENTS WELL TESTING SYSTEMS D-SR-007 Rev.1, January 1996 Please note that whilst every effort has been made to ensure the accuracy of the NORSOK standards neither OLF nor TBL or any of their members will assume liability for any use thereof. Well testing systems D-SR-007 Rev. 1, January 1996 CONTENTS 1 FOREWORD 2 2 SCOPE 2 3 NORMATIVE REFERENCES 2 4 DEFINITIONS AND ABBREVIATIONS 3 4.1 Definitions 3 4.2 Abbreviations 3 5 FUNCTIONAL REQUIREMENTS 3 5.1 General 3 5.2 Products/services 3 5.3 Equipment/schematic 4 5.4 Performance/output 5 5.5 Regularity 5 5.6 Process/ambient conditions 5 5.7 Operational requirements 5 5.8 Maintenance requirements 7 5.9 Isolation and sectioning 7 5.10 Layout requirements 7 5.11 Interface requirements 7 5.12 Commissioning requirements 7 6 INFORMATIVE REFERENCES 8 ANNEX A SERVICE DATA SHEETS 9 ANNEX B EQUIPMENT DATA SHEET 19 NORSOK standard 1 of 38 Well testing systems D-SR-007 Rev. 1, January 1996 1 FOREWORD NORSOK (The competitive standing of the Norwegian offshore sector) is the industry initiative to add value, reduce cost and lead time and remove unnecessary activities in offshore field developments and operations. The NORSOK standards are developed by the Norwegian petroleum industry as a part of the NORSOK initiative and are jointly issued by OLF (The Norwegian Oil Industry Association) and TBL (The Federation of Norwegian Engineering Industries). NORSOK standards are administered by NTS (Norwegian Technology Standards Institution). The purpose of this industry standard is to replace the individual oil company specifications for use in existing and future petroleum industry developments, subject to the individual company's review and application.
    [Show full text]
  • Using Multi-Phase Flow Meters for Well Test Optimization in the New Digital Yet Cost Sensitive Environment
    Using Multi-Phase Flow Meters for Well Test Optimization in the new Digital yet Cost Sensitive Environment Daniel Sequeira Haimo America Inc. APR, 2020 Contents ❑ Conventional Well Testing ❑ Multiphase Meter Technology ❑ Why Multiphase Meters ❑ MPFM + AI in Well Testing ❑ Conclusions Conventional Well Testing Various types of well testing is conducted throughout the lifetime of producing wells • In the petroleum industry, a well test is the execution of a set of planned data acquisition activities. The acquired data is analyzed to broaden the knowledge and increase the understanding of the hydrocarbon properties therein and characteristics of the underground reservoir where the hydrocarbons are trapped….. The overall objective is identifying the reservoir's capacity to produce hydrocarbons, such as oil, natural gas and condensate. – Wikipedia • A “well test” is simply a period of time during which the production of the well is measured, either at the well head with portable well test equipment, or in a production facility – PetroWiki • Users of the well test data & information within the operator organization include amongst others Facilities, Production, Reservoir & Allocation Engineers, as also Hydrocarbon Accounting & senior management. Daily Well Testing - Allocation & Prod. Mgt Daily tests are conducted during production phase to obtain average daily production of oil, gas and water “Daily” test procedures usually require the rates of liquid, gas, pressure and temperature to be stable 24 hours or other fixed period. Due to "unstable" production conditions, and delays introduced by test separators, extended testing period is often required, sometimes reaching 5-7 days. Costs associated could be very high. Periodic well tests on the production plant is the conventional way to get an estimated or theoretical production contribution per phase fraction per well per month.
    [Show full text]
  • Well Integrity in Drilling and Well Operations
    NORSOK Standard D-010 Rev. 4, June 2013 Well integrity in drilling and well operations This NORSOK standard is developed with broad petroleum industry participation by interested parties in the Norwegian petroleum industry and is owned by the Norwegian petroleum industry represented by the Norwegian Oil and Gas Association and The Federation of Norwegian Industries. Please note that whilst every effort has been made to ensure the accuracy of this NORSOK standard, neither the Norwegian Oil and Gas Association nor The Federation of Norwegian Industries or any of their members will assume liability for any use thereof. Standards Norway is responsible for the administration and publication of this NORSOK standard. Standards Norway Telephone: + 47 67 83 86 00 Strandveien 18, P.O. Box 242 Fax: + 47 67 83 86 01 N-1326 Lysaker Email: [email protected] NORWAY Website: www.standard.no/petroleum Copyrights reserved Provided by Standard Online AS for Oljedirektoratet 2014-10-30 © NORSOK. Any enquiries regarding reproduction should be addressed to Standard Online AS. www.standard.no Provided by Standard Online AS for Oljedirektoratet 2014-10-30 D-010, Rev. 4, June 2013 NORSOK Standard D-010 Well integrity in drilling and well operations Contents 1 Scope ..................................................................................................................................................... 7 2 Normative and informative references ................................................................................................... 7 2.1
    [Show full text]
  • Guidance on Safety of Well Testing
    TECHNICAL REPORT MINERALS MANAGEMENT SERVICE (MMS) GUIDANCE ON SAFETY OF WELL TESTING REPORT NO. 4273776/DNV REVISION NO. 01 DET NORSKE VERITAS DET NORSKE VERITAS Report No:4273776/DNV rev. 01 TECHNICAL REPORT Date of first issue: Project No.: 2004-07-01 72501050 DET NORSKE V ERITAS Technology Services. N America Approved by: ~ Urqanisational unit: Ame Edvin L¢ken Marine & Process Systems 163.W Park Ten Place Head of Section Suite 100 Houston 7708-1 United Stairs c.;lient: Client ref.: Tel: + I 28 1 7'.! I 6600 Fa.: + I 18 1 7'.!I 6833 Minerals Management Service (MMS) Mathew Quinney hup //www dnv.com Summary: Based on a Joint Industry Project managed by DNV this report has been produced providing guidance on a number of key areas with respect to flow testing of wells. The guidance focuses on aspects of well testing which represent a departure from fairly traditional testing carried out in shallow water, and for which there is a relatively good safety record. The principal areas addressed include : • Testing from floating installations in deepwater • Testing of High Pressure High Temperature wells • Testing from Dynamically Positioned vessels • Temporary storage and offloading of crude oil • Testing in arctic areas The Guidance relates only to safety considerations and not operational efficiency. The Guidance is aimed at all the parties involved in a welJ test operation : - The Licensee (Operator) - Drilling Contractor - Service Company - Regulatory Inspector Reoort No.: Subject Group: 4273776/DNV Indexing terms RePort title: Kev words ervice Area Safety of Well Testing Safety Technical Well Testing Market ector Exploration D No distribution without permission from the client or responsible organisational unit D free distribution within DNV after 3 years D Strictly confidential Date of this revision: 15 Nov 2004 IZ! Unrestricted distribution Page i Rderence to part of this report which may kad to misinterpretation is nocpermissibk.
    [Show full text]
  • Occupational Safety and Health for Oil and Gas Well Drilling and Servicing Operations
    Occupational Safety and Health for Oil and Gas Well Drilling and Servicing Operations API RECOMMENDED PRACTICE 54 FOURTH EDITION, FEBRUARY 2019 Special Notes Neither API nor any of API’s employees, subcontractors, consultants, committees, or other assignees make any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assume any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication. Neither API nor any of API’s employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights. Classified areas may vary depending on the location, conditions, equipment, and substances involved in any given situation. Users of this Recommended Practice should consult with the appropriate authorities having jurisdiction. API is not undertaking to meet the duties of employers, manufacturers, or suppliers to warn and properly train and equip their employees, and others exposed, concerning health and safety risks and precautions, nor undertaking their obligations to comply with authorities having jurisdiction. Information concerning safety and health risks and proper precautions with respect to particular materials and conditions should be obtained from the employer, the manufacturer or supplier of that material, or the material safety data sheet. Where applicable, authorities having jurisdiction should be consulted. Work sites and equipment operations may differ. Users are solely responsible for assessing their specific equipment and premises in determining the appropriateness of applying the Recommended Practice. At all times users should employ sound business, scientific, engineering, and judgment safety when using this Recommended Practice.
    [Show full text]
  • Petroleum Extension-The University of Texas at Austin I
    Petroleum Extension-The University of Texas at Austin i The Beam Lift Handbook First Edition, Revised by Paul M. Bommer and A. L. Podio Petroleum Extension-The University of Texas at Austin published by The University of Texas at Austin PETROLEUM EXTENSION 2015 iii Contents Figures x Tables xviii Foreword xxi Preface xxiii Acknowledgments xxv About the Authors xxvii Introduction xxix Reference xxxi 1. Beam Lift Goals and System Design 1-1 Goals 1-1 Unconstrained Design 1-4 Example 1, Initial Reservoir Pressure Just Above the Bubble Point 1-4 Example 2, Shallow Well Pumping From Reservoir Undergoing Successful Waterflood 1-18 Constrained Design 1-22 Example 3, Casing Size Limits Tubing Size 1-22 Example 4, Maximum Production Using Available Equipment 1-25 Example 5, Gear Box Capacity Constraint 1-28 Example 6, Flowing While Pumping 1-30 Example 7, Coal Bed Methane Pumping 1-32 Example 8, Pumping From Highly Deviated Wells 1-33 References 1-38 Bibliography 1-38 2. Monitoring and Analysis of Performance 2-1 Recommended Practices for the Monitoring and Analysis of Pumping System Performance 2-1 Dynamometer Analysis 2-1 Collecting Dynamometer Data 2-6 Data Quality Control 2-7 Analyzing the Dynamometer Data 2-8 Polished Rod Power 2-8 Valve Test 2-11 Fluid Load and Working Fluid Level 2-11 Wellbore Pressures 2-12 Maximum Gear Box Torque and Counterbalance Condition 2-13 Permissible Load Diagram 2-16 PetroleumFluid Slippage Extension-The and TV Leakage University of Texas at2-16 Austin The TV Test 2-17 Leakage Rate Calculation 2-20 TV Test for
    [Show full text]
  • Best Practices for Real Time Monitoring of Offshore Well Construction
    Best Practices for Real Time Monitoring of Offshore Well Construction DRAFT REPORT v3.0 03-MARCH, 2017 Prepared by: Eric van Oort, Nathan Zenero, and Cesar Gongora on Behalf of: Ocean Energy Safety Institute 1470 William D Fitch Pkwy, College Station, TX 77845 Best Practices for Real Time Monitoring of Offshore Well Construction Statement of Purpose In 2016, new well-control rules were established (CFR § 250.724) whereby operators are required to provide real-time monitoring plans and capabilities for operations in the OCS detailing at least the following technical and operational capabilities: • How the RTM data will be transmitted onshore, how the data will be labeled and monitored by qualified onshore personnel, and how the data will be stored onshore; • A description of procedures for providing BSEE access, upon request, to the RTM data including, if applicable, the location of any onshore data monitoring or data storage facilities; • Onshore monitoring personnel qualifications; • Methods and procedures for communications between rig and onshore personnel; • Actions that will be taken in case of loss of RTM capabilities or rig-to-shore communications; and • A protocol for responding to significant or prolonged interruptions of RTM capabilities or communications, including procedures for notifying the District Manager of such interruptions. As written the rule is open to interpretation. Therefore, to provide additional clarity regarding § 250.724 OESI has provide a collection of recommendations that are likely to satisfy the spirit of the rule without imposing undue burdens on operators or prescribing specific technologies or practices. The central purpose of this document is two-fold: 1.
    [Show full text]
  • Role of Well Testing and Information in the Petroleum Industry- Testing in Multilayers Reservoirs Assoc
    ISSN XXXX XXXX © 2016 IJESC Research Article Volume 6 Issue No. 7 Role of Well Testing and Information in the Petroleum Industry- Testing in Multilayers Reservoirs Assoc. Prof. Nevton KODHELAJ M.Sc. Shkëlqim BOZGO Abstract: The actual demand for oil and gas so as their products shows a clear increasing trend, despite some fluctuation mostly because of the global economic negative situation as well as some other geostrategic impacts. The new drilling activities and progressing toward deeper formations require stronger and abundant financial support, and looks that the safest way remains the increase of the oil recovery factor in the existing oil and gas fields. Well testing and their numerical modelling, gives responses that support their exploitation optimization. In many cases the oil and gas fields, represents as very complex systems composed by a large number of thin layers. Generally, they represent very complex hydrodynamic systems. The classification systems of these reservoirs, the calculation of the most important parameters, the factors that impacts and determine their exploitation performance as well as some economic indicators, are subject of this paper. Key words: Well test, reservoir, petroleum engineering, production forecats, skin effect 1 INTRODUCTION The oil well test represents one of the basic disciplines of the Oil & Gas Wells Testing reservoir engineering. The information collected regarding the fluid flow and the drawdown testing in the formation Pressure Data’s plays a key role for the determination of the productive Average Pressure of the Formation Use for Material Balance Calculations capacities of the oil and gas fields. The drawdown test gives Evaluation of the Vertical and Horizontal Evaluation of the Vertical and Horizontal Permeability an important support regarding the determination of the Anisotropy of the Permeability average pressure of the formations.
    [Show full text]
  • MODELING of UNCONTROLLED FLUID FLOW in WELLBORE and ITS PREVENTION a Dissertation by RUOCHEN LIU Submitted to the Office Of
    MODELING OF UNCONTROLLED FLUID FLOW IN WELLBORE AND ITS PREVENTION A Dissertation by RUOCHEN LIU Submitted to the Office of Graduate and Professional Studies of Texas A&M University in partial fulfillment of the requirements for the degree of DOCTOR OF PHILOSOPHY Chair of Committee, M. Sam Mannan Co-Chair of Committee, A. Rashid Hasan Committee Members, M. Nazmul Krim Mahmoud El-Halwagi Head of Department, M. Nazmul Karim May 2016 Major Subject: Chemical Engineering Copyright 2016 Ruochen Liu ABSTRACT Uncontrolled fluid flow in the wellbore is one of the most critical safety concerns for the oil and gas industry. The major focus of this dissertation is on blowout events given the most severe consequences associated with such incidents. The past tragedies reflect a strong need for not only understanding the mechanisms of blowout to accurately estimate the consequence, but also the approaches to managing and controlling the risks, uncertainties, and hazards associated with blowout events. A fully integrated analytical model that couples the reservoir and wellbore has been proposed to investigate the fluid behaviors during the blowout events. This model could be used to simulate any potential blowout events for gas, oil, or oil/gas wells at onshore or offshore facilities. The reservoir, wellbore, and their interactions are coupled together to demonstrate a full picture of the potential well blowout incidents. The results reveal that understanding the importance of heat transfer and multi-phase flow behaviors is essential to accurately estimate the consequence of well blowouts. Well-established computational algorithms are developed to effectively estimate the blowout rate and total discharge amount during blowout incidents.
    [Show full text]