Deepstar - Multiphase Flow

DEEPSTAR IV PROJECT

FLOW ASSURANCE DESIGN GUIDLINEFLOW ASSURANCE DESIGN GUIDLINE

DSIV CTR 4203b-1

April, 2001

INTEC ENGINEERING, INC. DEEPSTAR MULTIPHASE DESIGN GUIDELINE

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TABLE OF CONTENTS POLICY STATEMENT policy.pdf 1.0 INTRODUCTION Sec1.pdf 2.0 FLOW ASSURANCE SUMMARY AND FUNDAMENTALS Sec2.pdf 3.0 DESIGN PROCESS Sec3.pdf 4.0 FLUID PROPERTIES AND PHASE BEHAVIOR Sec4.pdf 5.0 MULTIPHASE FLOW Sec5.pdf 6.0 STEADY-STATE HYDRAULIC SIMULATION AND LINE SIZING Sec6.pdf 7.0 THERMAL MODELING Sec7.pdf 8.0 TRANSIENT OPERATIONS Sec8.pdf 9.0 HYDRATES Sec9.pdf 10.0 PARAFFIN WAXES Sec10.pdf 11.0 ASPHALTENES Sec11.pdf 12.0 EMULSIONS Sec12.pdf 13.0 SCALE Sec13.pdf 14.0 EROSION Sec14.pdf 15.0 CORROSION Sec15.pdf 16.0 SOLIDS TRANSPORT Sec16.pdf 17.0 SLUGGING Sec17.pdf 18.0 SLUGCATCHER DESIGN Sec18.pdf 19.0 PIGGING Sec19.pdf 20.0 OTHER OPERATIONS Sec20.pdf 21.0 (INTENTIONALLY LEFT BLANK)


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22.0 HOST FACILITY REQUIREMENTS Sec22.pdf 23.0 SYSTEM ECONOMICS AND RISK MANAGEMENT Sec23.pdf 24.0 DEEPWATER ISSUES AND CASE STUDIES Sec24.pdf 25.0 TYPICAL DESIGN PARAMETERS Sec25.pdf APPENDICES SECTION 9 APPENDIX A: GAS HYDRATE STRUCTURES, PROPERTIES, AND HOW THEY FORM Sec9 App A.pdf SECTION 9 APPENDIX B: USERS GUIDE FOR HYDOFF AND XPAND PROGRAMS Sec9 App B.pdf SECTION 9 APPENDIX C: HYDRATE BLOCKAGE AND REMEDIATION Sec9 App C.pdf SECTION 9 APPENDIX D: RULES OF THUMB SUMMARY Sec9 App D.pdf


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POLICY STATEMENT

The Flow Assurance Design Guide (FADG) is of a general nature. The FADG does not undertake to meet the duties of operators, manufacturers,

suppliers, or engineers to properly engineer and operate multiphase production systems.

The FADG is not meant to be an instructional tool; however, it can be used to supplement a course on flow assurance issues.

The FADG is primarily a tool for design engineers with a sound knowledge of flow assurance operations.

Nothing in the FADG is to be construed as a fixed rule without regard to sound engineering judgment.

The FADG is not intended to supersede or override any federal, state, or local regulation.

The FADG does not inhibit anyone from using any other guide. The FADG is not all encompassing. The guide does benchmark topics that are

typically addressed in a quality flow assurance analysis.


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1.0 INTRODUCTION

The Flow Assurance Design Guide (FADG) sets forth basic engineering requirements and recommended practice deemed necessary for the reliable and cost effective design and operation of multiphase production systems. Because flow assurance is a multi-discipline activity, the FADG addresses each discipline and explains how each fit in the overall design process. The major flow assurance technologies covered in the guide are:

PVT and fluid properties

Steady state and transient multiphase flow modeling Interface with the reservoir and the process equipment

Hydrate, paraffin, and asphaltene issues Corrosion, erosion, and sand control

Each technology area will be discussed at a moderate level of detail. Basic behaviors mathematical models, modeling techniques, experimental data, accuracy and uncertainty, design tips and internal checks will be discussed. Hallmarks of good design practice will be illustrated with numerous examples throughout the guide. Important reference documents and published papers will be listed at the end of each major section.

Design engineers with a sound knowledge of flow assurance are the intended audience for the FADG. The guide is not intended to be an introduction to flow assurance technology.


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2.0 THIS SECTION IS INTENTIONALLY BLANK.


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3.0 DESIGN PROCESS

This section describes the design methodology or process that the flow assurance engineer follows in developing a successful, cost effective subsea production system and its operating philosophy. The flow assurance design methodology flow chart is presented in Figure 3-1 and forms the basis for the discussion on the design process. Links to the relevant sections in the Flow Assurance Design Guide are also provided.

As illustrated in the design methodology chart, the flow assurance design process involves several major steps: Establish design basis Thermal-hydraulic design and assessment of fluid behavior

- Perform hydraulic design - Perform thermal design - Assess fluid thermodynamic/phase behavior - Assess transient thermal-hydraulic behavior

Interface with mechanical design Establish operating strategies Determine host facility requirements Assess system economics

Each step can be addressed individually; however, all steps will be considered collectively because they are inter-related. The chart shows some of the considerations and/or decisions involved with each step. For purposes of illustration, design process steps are generally shown to be sequential. However in practice, several of the steps will need to be addressed simultaneously.

The flow assurance design process starts early in the field development effort, potentially even before any wells have been drilled when the types and amounts of reservoir fluid samples are specified. The general sequence begins with the development of the design basis and then the thermal-hydraulic design and assessment of fluid behavior. During the thermal-hydraulic design phase, the flow assurance engineer will begin to interface with other design engineers, such as pipeline/flowline and facilities engineers. In what is typically a parallel effort, the flow assurance engineer will interface with the subsea mechanical designers and other engineers, will develop operating strategies, and will assist in determining host facility requirements. An over-riding consideration in the design process is system economics and risk management.


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The design process will be iterative due to inevitable changes in the design basis, interim results during the design, changes in system economics, and other changes. Such iterations are indicated in the design methodology flow chart at the decision points in which no would be the answer.

The flow assurance design process involves multiple technical interfaces. Reservoir engineering, completions engineering, pipeline/flowline mechanical design, subsea and controls engineering, facilities engineering, and operational personnel will all interact with flow assurance during the design process. The numerous interfaces necessitate effective project management.

3.1 Design Basis

The first major effort in the design process is to establish the design basis. The flow assurance engineer will be directly involved in terms of determining and documenting the fluid characteristics, in terms of both PVT behavior and the potential for solids formation. For the other aspects of the design basis, such as reservoir behavior, site characteristics, and host facilities, the flow assurance engineer will need to ensure that the data needed for the flow assurance analyses are included in the design basis. Thus the flow assurance engineer will need to interface with those responsible for reservoir engineering, metoceanic data, bathymetry, and surface facilities. These interfaces will continue throughout the project. It is important to note that the design basis will need to be built with conservatism to offset poor or missing data.

This step in the design process assumes that fluid samples have been collected. A substantial amount of laboratory work may be required to determine the characteristics of the fluid samples. Standard PVT measurements should be performed on the fluids, and then fluid characterizations should be developed for use in thermal-hydraulic and other modeling (reservoir and process). Section 4 discusses PVT behavior and fluid characterization. The fluids should also be tested for potential solids formation such as wax and asphaltenes.

3.2 Thermal-Hydraulic Design

The thermal-hydraulic design effort evaluates the lifecycle performance of the entire production system. All parts of the system and all interfaces must be considered throughout the operating lifetime of the development. This effort also should include assessment of the potential for flow reductions due to solids formation.


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At the beginning of this step, basic design and operating principles should be set. Examples include methods to be used to keep the production system out of the hydrate formation region. For oil systems this could mean insulation. For gas system this would require chemical inhibition. Another example would be to establish a lower limit on well production rate and/or to use insulated tubing to prevent wax deposition in wellbores during normal operation. This could be extended to the flowline, or wax may be managed in the flowline with pigging and chemical injection. Such principles help guide the flow assurance engineer through the design process; however, these principles should be continuously evaluated in light of system operability and economics.

3.2.1 Hydraulic Modeling

Most system design attributes can be set on the basis of steady state analyses. Steady-state hydraulic models are used to determine the diameters for production tubing, production flowlines, injection flowlines, and export pipelines. Criteria for line sizing include pressure constraints, flow rates, and erosional velocity limits. As part of the line sizing exercise and hydraulic assessment, changes in parameters such as production rates, water cut, and GOR during the field life need to be evaluated. Artificial lift may also be considered. Operating pressures will be calculated. Sections 5, 6, and 14 deal with multiphase flow, line sizing, and erosion.

3.2.2 Thermal Modeling

Thermal modeling is typically combined with hydraulic modeling, thus thermal-hydraulic modeling. Operating temperatures are calculated as a function of insulation level and other parameters initially via steady state analysis. Section 7 covers thermal modeling.

3.2.3 Assessment of Transient Thermal-Hydraulic Behavior

The operation of subsea production systems and transport systems involves transient processes, e.g. shutdowns, startups, and rate changes. It is during these transient operations that issues like hydrate control and liquid handling become important system design and operability drivers.

Examples of transient thermal-hydraulic modeling include wellbore warm-up with restart, flowline/riser cooldown upon shutdown, and depressurization. For deepwater oil systems, the cooldown time to hydrate conditions has typically driven the insulation level. Transient analysis may also include determining the potential for slugging and slug characterization. Slugging can impact selection of line size, and thus the hydraulic and line-sizing analysis may need to be re-iterated. Sections 8 and 17 cover transient operations and slugging, respectively.


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3.2.4 Assessment of Fluid Behavior and Solids Formation/Deposition

In this step, the thermodynamic behavior of the fluids is evaluated in view of the system thermal and hydraulic performance to assure design criteria are met. Hydrate dissociation curves are determined for the production fluids, and wax and asphaltene formation envelopes are developed. The operating temperatures and pressures are compared to these envelopes to predict when and where solid may form. Solids control is responsible for many of the features of subsea design and operation including insulation, chemical injection, pigging facilities, and special operating procedures for shutdown.

Methods for remediation of deposited solids also need to be developed. These methods may require specific facilities in the design (e.g. solvent lines in the umbilical for remediating asphaltene deposits in wellbores) and/or the development of special procedures. Sections 9, 10, 11, 12, and 13 discuss hydrates, wax, asphaltenes, emulsions, and scale.

3.3 Interface with Mechanical Design

Flow assurance engineers and the engineers responsible for the mechanical design of the subsea facilities must assure that characteristics such as line diameters, operating and shut-in pressures, required insulation levels, and operating temperatures are consistent within the system design. Information provided by the flow assurance effort is used in the design of flowlines, pipelines, risers, subsea equipment (trees and manifolds), umbilicals, and completions.

3.4 Operating Strategies

Operating strategies must be consistent with the system design and should be adaptable to suit new circumstances in the event that fluid characteristics or other system characteristics are found to be significantly different from those in the design basis. Development of operating strategies is presented in Section 21.

3.5 Host Facility Requirements

The host facilities are a key part of the subsea system design, and its requirements and capabilities must not be overlooked. Examples include the capacity, arrangement, and control of receiving equipment (separators, slugcatchers, surge tanks, and flare knockout drums), chemical injection storage and pumping, pigging equipment, normal and emergency power, and control. Instrumentation, controls, and facility capabilities have to be completely integrated into the overall system design and operability. Sections 18, 19,


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20, and 22 cover slugcatcher design, pigging, other operations, and host facility requirements.

3.6 System Economics

There are numerous detailed design and manufacture activities and considerations that are implicitly lumped into the Assess System Economics step. Section 23 covers system economics and risk management.


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Figure 3-1: FLOW ASSURANCE DESIGN PROCESS

ESTABLISH DESIGN BASIS

HYDRAULIC DESIGN THERMAL DESIGN

Thermal-Hydraulics andFluid Behavior

OK?

ASSESS FLUIDPHASE

BEHAVIOR

Processing Capabilities Processing Pres./Temps. Metering Storage Volumes Export Requirements PCS Chemical Injection Pumps Chemical Storage Flare Requirements Utility & Emergency Power Surge/Slug Volumes Surge/Slug Control

Procedures Valve Sequences Pump Sequences Chemical Injection Rates Activity Durations

Systemand Economics

Optimum?

ASSESS SYSTEMECONOMICS

DONE

Reservoir Behavioras f(t) Productivity Index Production Profiles Pres. vs. Depletion Temperature

Fluid Behavior PVT Characterization Hydrates Wax Asphaltenes

Flowline Routing Bathymetry Seabed Temp.

ModelFlowlines

Thermal-Hydraulics OK?

Select Tubingand Flowline

Diameters and# of Flowlines

Select Tubingand

FlowlineInsulation

Host Facilities Separator Pres. Acceptable Arrival Temp.

ASSESSTRANSIENTTHERMAL-

HYDRAULICS

FLOW SYSTEM THERMAL-HYDRAULIC DESIGN AND FLUIDBEHAVIOR

HydratesWax

AsphaltenesScale

PredictionControl

RemediationHOST FACILITY

REQUIREMENTS

CAPITAL COSTOPERATING COSTS

NET PRESENT VALUE

Reservoir, FlowSystem, and Host Design

Compatible?

OPERATINGSTRATEGIES

Plateau andEOL Conditions

Satisfied?

ModelWells

ModelFlowlines

ModelWells

No

Yes

Yes

No

No

Yes

Yes

Flowlines, Pipelines, & Risers Subsea Equipment Umbilicals Wellbores

INTERFACE WITHMECHANICAL DESIGN

Startup / WarmupShutdown / CooldownTurndown / Ramp-up

DepressurizationSlugging

No

No

Yes


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4.0 FLUID PROPERTIES AND PHASE BEHAVIOR

4.1 Introduction

Modeling of oil and gas production, processing, and transportation system requires knowledge of how the fluid behaves with changes in temperature and pressure. This modeling work will require not only fluid properties (densities, viscosities, heat capacities) but also the phase behavior of the fluids.

Multi-component phase behavior is a complex phenomenon, which requires accurate determination if two-phase pressure loss, hold-up and flow regime are to be determined with any degree of confidence.

The phase behavior will determine the vapor-liquid split and the thermodynamic properties of each of the phases present, and it is important for the designer of such a system to have a knowledge of what form this equilibrium takes, and how it may change in different parts of the pipeline. Since it is expected that both temperature and pressure will fall as fluids flow along the pipeline, it is possible that either condensation or evaporation will take place within the pipe. This can have a significant effect on liquid holdup and hence pressure drop. It also means that the CGR (or GOR) can vary significantly depending on whether it is based on pipeline inlet or outlet conditions, and it is therefore important to make it clear under what conditions it has been calculated.

In practice, experimentally determined phase behavior is often limited and one has to employ some method of prediction. There are two approaches commonly employed in the prediction of hydrocarbon phase behavior. These are the black oil method, which assumes that only two components, i.e. gas and liquid, make up the mixture, and the so-called compositional approach, in which each hydrocarbon component is taken into account. The methods have their own relative merits and are discussed in this section.

This section also addresses fluid sampling. Without appropriate sampling techniques, sample handling, and analysis methods, the predictive methods used in modeling of the production and processing of reservoir fluids will be in error.


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4.2 Reservoir Fluids

4.2.1 Phase Behavior

Reservoir fluids are often described in terms of their phase behavior, which can be defined as the relationship between the fluid phases (usually the gas and the oil/condensate) and how the phases change with variations in temperature and pressure.

Single Component Phase Behavior

In describing phase behavior, a system consisting of a single, pure substance is considered first. Such a system behaves differently from systems made up of more than one component. A phase diagram (or phase envelope) is a plot of pressure versus temperature showing the conditions under which the various phases will be present. Figure 4.2-1 shows a phase diagram for a single, pure substance.

Pure Component Phase Diagram

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Figure 4.2-1: Phase Diagram for a Single-Component System

This phase diagram shows the temperature and pressure conditions under which the vapor, liquid, and solid phases exist. Various components of the phase diagram are defined below.


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Vapor Pressure Curve

The curve that divides the vapor phase from the liquid phase is called the vapor pressure curve. At conditions above the curve only liquid will exist, and at conditions below the curve only vapor exists. At pressure-temperature points on the curve, vapor and liquid will co-exist.

Triple Point

The triple point is a unique point on the phase diagram at which vapor, liquid, and solid all coexist.

Critical Point

The upper limit of the vapor pressure curve is called the critical point. The temperature and pressure at this point are referred as to the critical temperature (Tc) and the critical pressure (Pc).

Sublimation and Melting Curves

The phase diagram also illustrates the sublimation curve and melting curve, which separate the solid and gas phases and the liquid and solid phases, respectively.

Multicomponent Phase Behavior

Reservoir fluids are multicomponent mixtures and exhibit more complex phase behavior than pure components. Figure 4.2-2 illustrates a phase diagram for a gas-condensate system. This diagram does not include potential solid phases that occur in reservoir fluids; the diagram focuses only on the vapor and liquid phases.

Instead of a single curve representing the vapor pressure curve as with single component fluids, there is a broad region in which vapor and liquid coexists. This region is called the two-phase region or phase envelope. The two-phase region is bounded on one side by the dew point curve and on the other by the bubble point curve. The two curves join at the critical point. Figure 4.2-2 also illustrates the dew and bubble point curves.


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Multiple Component Phase Diagram

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VAPOR FRACTION = 100 MOLE %

90MOLE %

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99MOLE %

QUALITYLINES

Figure 4.2-2: Multiple Component Phase Diagram.

Dew Point and Bubble Point

At a pressure below the dew point curve, the fluid will be single-phase vapor. As the pressure is increased at a constant temperature, the vapor compresses until the pressure reaches a point at which the first drop of liquid is formed. This is referred to as the dew point. The pressure at which the first liquid drop forms is called the dew point pressure. As the pressure is increased above the dew point pressure, more and more liquid forms.

At a pressure above the bubble point curve, the fluid will be single-phase liquid. As the pressure is reduced at a constant temperature, the liquid expands until the pressure reaches a point at which the first bubble of vapor is formed. This is referred to as the


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bubble point. The pressure at which the first gas is formed is the bubble point pressure. As the pressure is decreased below the bubble point pressure, more and more gas appears.

Critical Point

As can be seen when comparing Figures 4.2-1 and 4.2-2, the definition for the critical point for a single component is not the same as that for a multiple component mixture. A rigorous definition of the critical point is that it is the point at which all properties of the liquid and the gas become identical.

Cricondentherm and Cricondenbar

The highest temperature on the two-phase envelope is called the cricondentherm. The highest pressure on the two-phase envelope is called the cricondenbar. These are illustrated on Figure 4.2-2.

Quality Lines

Another feature in the two-phase envelope are quality lines. These lines indicate curves on constant vapor or liquid quantities within the two-phase region. In Figure 4.2-2 there are quality lines for 99, 95, 90 and 80 mole percent vapor. The quality lines all converge at the critical point.

Retrograde Condensation

For many multiple component mixtures a phenomenon called retrograde condensation can occur. If the mixture is at a pressure greater than the cricondenbar and at a temperature greater than the critical temperature, it will be single-phase gas. If the pressure is decreased isothermally, the dew point curve will be crossed and liquid will form. A decrease in pressure has caused liquid to form; this is the reverse of the behavior one would expect, hence the name retrograde condensation. As the pressure continues decreasing, more liquid will form until at some pressure the amount of liquid starts decreasing. Eventually the dew point curve will be crossed again.

Dense Phase Region

It is common practice to refer to the area above the cricondenbar as the dense phase region. In this region it possible to move from a temperature well below the critical temperature to one well above it without any discernible phase change having taken place. At the lower temperature the fluid would behave more like a liquid and at the


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higher temperature it would behave more like a vapor, but in between it would not exhibit any of the traditional signs of a phase change.

4.2.2 Components of Reservoir Fluids

Reservoir fluids contain a multitude of chemical components, which can be divided into two groups: hydrocarbons and non-hydrocarbons. The hydrocarbon components include:

Paraffins (straight chain and branched) Methane, ethane, propane, butanes, pentanes, hexanes, heptanes, octanes, etc. Waxes

Naphthenes Cyclopentane, cyclohexane, methylcyclohexane, etc.

Aromatics Benzene, toluene, xylenes, ethylbenzene, naphthalene, etc.

Resins and Asphaltenes Large molecules composed mainly of aromatic rings or carbon and hydrogen but

also can contain nitrogen, sulfur, oxygen, and metals

The non-hydrocarbon components of reservoir fluids include:

Water

Carbon dioxide (CO2) Sulfur compounds Hydrogen sulfide (H2S), mercaptans

Nitrogen (N2)

Helium Metals Vanadium, nickel

Mineral salts

4.2.3 Types of Reservoir Fluids

Fives types of reservoir fluids can be defined: black oil, volatile oil, retrograde gas, wet gas, and dry gas. These fives types of reservoir fluids have been defined because each requires different approaches for reservoir management and production system design.


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The reservoir fluid type can be confirmed only by observation in the laboratory; however, some rules of thumb can help identify the fluid type. Three properties that can be used with the rules of thumb are the initial producing gas-oil ratio, the gravity of the stock tank oil, and the color of the stock tank oil.

The behavior of a reservoir fluid during production is determined by the shape of its phase diagram and the position of its critical point. Each of the five reservoir fluid types can be described in terms of its phase diagram.

Black Oils

The phase diagram for a black oil is presented in Figure 4.2-3. Indicated on the phase diagram is the critical point and quality lines. The vertical line in the figure indicates the pressure reduction at constant temperature that occurs in the reservoir during production. As the reservoir of a black oil is produced, the pressure will eventually drop below the bubble point curve. Once below the bubble point, gas evolves from the oil and causes some shrinkage of the oil.

Black oils are characterized as having initial gas-oil ratios (GORs) of 2000 SCF/STB or less. The producing gas-oil ratio will increase during production when reservoir pressure drops below the bubble point pressure. The stock tank oil will usually have a gravity below 45API. The stock tank oil will be very dark due to the presence of heavy hydrocarbons.

Volatile Oils

The phase diagram for a typical volatile oil, Figure 4.2-4, is somewhat different from the black-oil phase diagram. The temperature range covered by the two-phase region is somewhat smaller, and the critical point is much lower than for a black oil and is relatively close to the reservoir temperature (but still greater than the reservoir temperature). The vertical line in the figure shows the reduction in reservoir pressure at constant temperature during production. For a volatile oil, a small reduction in pressure below the bubble point can cause a relatively large amount of gas to evolve.

The dividing line between black oils and volatile oils is somewhat arbitrary. Volatile oils may be identified as having initial producing GORs between 2000 and 3300 SCF/STB. The stock tank oil gravity is usually 40API or higher, and the stock tank oil is colored (usually brown, orange, or green).


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Retrograde Gases

The phase diagram of a retrograde gas, Figure 4.2-5, has a somewhat smaller temperature range than that for oils, and the critical point is further down the left side of the phase envelope. The changes are a result of retrograde gas containing fewer heavy hydrocarbons than the oils. Additionally, the critical temperature is less than the reservoir temperature, and the cricondentherm is greater than the reservoir temperature.

During initial production, the retrograde gas is single-phase gas in the reservoir. As the reservoir pressure declines, the dew point is reached, and liquid begins to condense from the gas and form a free liquid in the reservoir. This liquid will normally not flow and cannot be produced.

The initial producing GORs for a retrograde gas ranges from 3300 SCF/STB on the lower end to over 150,000 SCF/STB (the upper limit is not well defined). The producing GOR will increase after the reservoir pressure drops below the dew point. Stock tank gravities of the condensate are between 40 and 60API and increase as reservoir pressure drops below the dew point. The stock tank liquid will be lightly colored to clear.

Wet Gases

With wet gases the entire phase envelope will be below the reservoir temperature as illustrated in Figure 4.2-6. Wet gases contain predominately low molecular weight molecules. A wet gases will remain as single phase gas in the reservoir throughout the production life; however, the separator conditions do lie within the two-phase region. Thus, somewhere in the production system, the dew point curve will be crossed and liquid will condense from the gas.

Wet gases produce stock-tank liquids with gravities ranging from 40 to 60API; however, the gravity of the liquid does not change during the production life. Wet gases have very high GORs, typically more than 50,000 SCF/STB.

Dry Gases

Dry gases are primarily methane with some light intermediates. Figure 4.2-7 shows that the two-phase regions is less than the reservoir conditions and the separator conditions. Thus no liquid is formed in either the reservoir or the separator.


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Figure 4.2-3: Black Oil Phase Diagram

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Figure 4.2-4: Volatile Oil Phase Diagram.

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Figure 4.2-5: Retrograde Gas Phase Diagram.

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Figure 4.2-6: Wet Gas Phase Diagram.

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Figure 4.2-4: Dry Gas Phase Diagram.

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4.3 Black Oil Model

4.3.1 Black Oil Model

The black oil approach to the prediction of phase behavior ignores the fluid composition and simply considers the mixture as consisting of a gas and liquid phase in which the gas may be dissolved in the liquid. The basic assumption of a black oil model is that increasing system pressure (and reducing temperature) cause more gas to dissolve in the liquid phases, and, conversely, decreasing system pressure (and increasing temperature) cause gas to evaporate from the liquid phase. It was previously noted that retrograde condensation involves the conversion of gas to liquid on reducing pressure. This is contrary to the fundamental assumption of the black oil model and so the black oil approach is only valid for systems operating at conditions far removed from the retrograde region.

In a typical liquid reservoir, the reservoir condition is well to the left of the critical point and so the expansion process involves the continual evolution of gas, i.e. the operating point moves steadily across the quality lines to a condition of ever decreasing liquid content. This type of process would be adequately represented by a black oil model.

For the gas reservoir, the reservoir condition lies to the right of the critical point so that on expansion, (reducing pressure) the operating point moves across the quality lines to a condition of increasing liquid content, i.e. retrograde condensation. This process could not be represented by a black oil model.

As a general guide a black oil model should be adequate for describing crude oil-gas systems, while a compositional model is necessary to describe wet-gas, gas-condensate and dense phase systems.

The black oil model employs certain concepts and nomenclature, which require definition. These are discussed briefly below:

Producing Gas Oil Ratio (GOR)

This is the quantity of gas evolved when reservoir fluids are flashed to stock tank conditions. The units are standard cubic feet of gas per stock tank barrel of oil (SCF/STB) measured at 14.7 psia and 60F.

The GOR of a crude is obtained by experimental testing. However, the GOR will vary depending on how many flash stages are employed to get down to stock tank conditions.


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The normal convention is to calculate GOR from the sum of gas volumes evolved from a multistage flash procedure (normally this involves 2 or 3 flash stages). This more closely represents conditions in the field with the pressure and temperature conditions chosen for the first stage flash approximating to conditions likely to be experienced in the first stage separator in the field.

Solution Gas Oil Ratio (Rs)

This is the quantity of gas dissolved in the oil at any temperature and pressure. It represents the quantity of gas that would be evolved from the oil if its temperature and pressure were altered to stock tank conditions, 14.7 psia and 60F. Hence, by definition the Rs of stock tank oil is zero.

The Rs crude at its bubble point is equal to the producing GOR of the reservoir fluids. The volume of free gas present at any pressure and temperature is the difference between the GOR and the Rs. The volume of free gas is corrected for pressure, temperature and compressibility to compute the actual in-situ volume of gas and hence superficial gas velocity. Rs can be evaluated from standard correlations such as Glaso or Standing. These correlations require as input the oil and gas gravity and the pressure and temperature conditions.

Volume Formation Factor (Bo)

The volume formation factor is the ratio of the volume occupied by oil at any pressure and temperature to the volume occupied at stock tank conditions. The units are pipeline barrels per stock tank barrel (BBL/STB). The volume formation factor of stock tank oil is thus 1.0. Through use of Bo the volume flow rate and density of the liquid phase can be calculated. Standard correlations are available to compute Bo. These require as input the oil and gas density, the Rs of the liquid at the conditions of interest, and the pressure and temperature.

Live Oil Viscosity

The viscosity of the oil in a two-phase pipeline depends on the stock tank oil viscosity (dead oil viscosity), the solution gas oil ratio at the conditions of interest, and the pressure and temperature. Correlations are available to compute the live oil viscosity.

The correlations available for Rs, Bo and live oil viscosity will yield approximate values only and where laboratory or field data is available, these should be used to adjust and


H-0806.35 4-16 1-Dec-00

tune these correlations. The way in which the correlations are tuned will depend on the quantity of field data available.

The minimum physical property information required to run a black oil model is:

Stock tank oil gravity

Gas gravity

There is often some confusion about the definition of gas gravity and hence uncertainty about the value of this data item. The majority of the correlations are based upon multistage 23 stages) separation, and the gas gravity used should always be the total gravity based upon the weighted average gravity from each stage:

lG

GsggravitygasTotal

i

n

i

ii

n

i

1

1*

=

=

S

S=

where:

sgi = gravity of the ith separator stage off-gas

Gi = free gas GOR at the ith separator stage

n = number of stages in the separator train with the final stage at stock tank conditions.

Total producing GOR

This should be taken as the sum of the gas volumes evolved from each stage of a multistage flash.

4.3.2 Thermal-Hydraulic Simulation with the Black Oil Model

In thermal-hydraulic simulators, the black oil correlation models can be used to simulate the key PVT fluid properties of the oil/gas/water system. These empirical correlations treat the oil/gas system as a simple two-component system, unlike the more rigorous multi-component compositional model methods (equations of state). As previously described, the hydrocarbon is treated simply as an "oil" component (if present) and a "gas" component related to stock tank conditions. All that is needed for most


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applications is a minimum of production data: oil gravity, gas gravity, solution gas/oil ratio and, if water is present, the watercut.

When to Use Black Oil Fluid Modeling

Black oil fluid modeling is appropriate for a wide range of applications and hydrocarbon fluid systems. In general, the basic black oil correlations will provide reasonable accuracy in most PVT fluid property evaluations over the range of pressures and temperatures likely to be found in production or pipeline systems. However, care should be taken when applying the "black oil approach" to highly volatile crude oils or condensates where accurate modeling of the gaseous "light ends" is required. In this case, the modeler needs to consider using compositional modeling techniques, which describe the fluid as a multi-component system.

To increase the accuracy of the basic black oil correlations for modeling multiphase flow, thermal-hydraulic simulators typically provide the facility to adjust salient values of a number of the most important PVT fluid properties to match laboratory data. Specifically, the following points can be calibrated:

Oil saturated gas content at the bubble point (Rs)

Formation volume factor at the bubble point (Bo)

Formation volume factor at pressure above the bubble point to account for oil compressibility above bubble point

Live oil viscosity at the bubble point

The above fluid properties are considered the single most important parameters affecting the accuracy of multi-phase flow calculations. Calibration of these properties at the bubble point and above can increase the accuracy of the correlations over all pressures and temperatures.

This facility is typically optional, but the above calibrations will significantly improve the accuracy of the predicted gas/liquid ratio, the flowing oil density and the oil volume formation factor as a function of temperature and pressure. If the calibration data are omitted, however, the thermal-hydraulic simulators will calibrate on the basis of oil and gas gravity alone and thus, there will be a loss in accuracy. It should be noted that the


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Black Oil calibration is only applicable to oil fluid types as it is not appropriate for a gas fluid type.

4.4 Compositional Models

4.4.1 Equations of State

In a compositional model the predictions of gas and liquid physical properties are performed through use of an equation of state, EOS. Any equation correlating pressure (P), volume (V) and temperature (T) is known as an EOS. For an ideal gas the EOS is simply:

PV = nRT

where:

n = number of moles of gas R = Universal gas constant.

A gas is ideal if its molecules do not interact with each other and occupy no volume. This is obviously not true, but the behavior of most real gases does not deviate drastically from the behavior predicted by the ideal gas behavior. One way of writing an equation of state for a real gas is to insert a correction factor into the ideal gas equation. This results in:

PV = ZnRT

where the correction factor, Z, is known as the compressibility factor or z- factor. The compressibility factor is the ratio of the volume actually occupied by a real gas at a given pressure and temperature to the volume it would occupy at the same pressure and temperature if it behaved like an ideal gas. The compressibility factor is not a constant. It varies with changes in composition, pressure, and temperature.

To account for the non- ideality of most gas systems the ideal gas equation is modified to include various correlating constants. The most commonly used equations of state used in the oil and gas industry are called cubic equations of state because their mathematical forms are cubic in terms of density or the z- factor. The two most popular equations of state used in industry today are the Redlich-Kwong-Soave, the Peng-Robinson EOS, and modifications of them.


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These cubic equations of state include terms to correct pressure for the forces of attraction between the molecules. The actual pressure exerted by a real gas is less than that of an ideal gas. Additionally, the cubic equations of state attempt to correct the molar volume due to the volume occupied by the molecules.

The Peng-Robinson (PR) EOS, for example, is given by:

)()()(

bVbbVVTa

bVRT

P-++

--

=

where for any mixture :

iii

bb gS=

ig = mole mole fraction of component i

ib = empirical constant for component i. This parameter represents the volume occupied by the molecules.

jiijjiji

aakla )( -= gg

ijk = empirically determined interaction parameter for the two components, i

and j.

ji aa = empirical constants for components i and j. These are a function of

temperature and represent the pressure contribution from the attractive forces.

The cubic equations of state can model liquids as well as gases and can be used to calculate the vapor- liquid equilibria of hydrocarbon mixtures. The equation of state allows a thermodynamically consistent method to evaluate the gas and liquid properties when these two phases coexist.

The prediction of liquid densities was an area that needed improvement in original development of the cubic equations of state. An empirical but effective way to improve the accuracy of the liquid density predictions is to use the volume translation correction. The volume translation is a linear correction of the predicted EOS volumes which does not affect the equilibrium results from the original EOS. Therefore, this correction, which is sometimes referred to as the Peneloux correction, is thermodynamically consistent.


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Another equation of state that is sometimes used in the oil and gas industry is the Benedict-Weber-Rubin (BWR) equation and its derivative, the BWRS equation.

4.4.2 Viscosity

Viscosity, which is a transport property, cannot be evaluated from an EOS, but the EOS provides compositional and property data that is needed in the viscosity models. Two compositional methods to predict viscosity are commonly used: the LBC method (gas and liquid) and the Pedersen method (gas and liquid). Preliminary testing has shown the Pedersen method to be the most widely applicable and accurate for oil and gas viscosity predictions. The Pedersen method is based on the corresponding state theory, as is the LBC method.

Lower Alkanes

Predicted liquid viscosities using LBC and Pedersen methods have been compared to experimental data for methane and octane as a function of both temperature and pressure and for pentane as a function of temperature. For both methane and pentane the Pedersen method predictions show close agreement with experimental data. For octane, the Pedersen and LBC methods give comparable results. For the aromatic compound, ethyl benzene, the Pedersen method is not as good as the LBC method.

Higher Alkanes

The results for higher alkanes eicosane and triacontane are mixed: the Pedersen method is adequate for eicosane whereas the LBC method is slightly better than Pedersen for triacontane. For triacontane both LBC and the Pedersen methods are inadequate. However, in the majority of cases the higher hydrocarbons should be treated as petroleum fractions rather than as single named components.

Petroleum Fractions

The LBC method describes viscosity as a function of the fluid critical parameters, acentric factor and density. The LBC model is therefore very sensitive to both density and the characterization of the petroleum fractions.

Water

The Pedersen method suffers the same drawback as the LBC method in that it is unable to predict the temperature dependence of water, a polar molecule. To overcome this problem, the Pedersen method has been modified especially for water so that it can


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accurately model the viscosity of water in the liquid phase. This was achieved by the introduction of a temperature-dependent correction factor. However the prediction of the viscosity of the gas phase is also affected, though in only a minor way.

Methanol

Neither the LBC nor the Pederson method can deal with polar components with the Pederson method slightly worse than the LBC method. This is not surprising, as both methods were developed for non-polar components and mixtures. The Pedersen method works best with light alkanes and petroleum mixtures in the liquid phase. It performs as well or better than the LBC method in nearly all situations.

The choice of the equation of state has a large effect on the viscosities predicted by both methods. The LBC method is more sensitive to these equation of state effects than is the Pedersen method.

4.5 Fluid Characterization

Petroleum reservoir fluids consist of thousands of different hydrocarbon molecules. The diversity in chemical structure of the individual components increases with the carbon number. In reality it is not practical to analyze for all of the components that may exist in a reservoir fluid. Even if the separation and identification of each component present were possible, the usefulness of such information would be limited. From a modeling standpoint, it is desirable to keep the number of components small in using EOS to minimize computation time requirements and round-off errors.

Standard composition analyses often stop at C7, C10, or C20. The gas chromatographic analysis of pure hydrocarbon components up to C6 is routine. The physical and chemical properties of these compounds (as required by an EOS) are accurately known. However, compounds with higher carbon numbers are conventionally analyzed in terms of true boiling fractions. The analysis is usually done in a gas chromatograph and provides the mole fraction of all compounds that contain the same number of carbons in their structure.

There are components that are too heavy and/or polar and are not volatile enough to be separated by GC carbon number analysis. These components typically make up the residue that is reported as the last carbon number component, and this residue consists of all the components that have carbon numbers equal to or higher than the highest


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unseparable carbon number group. The residual group may be the C7+, C10+, C20+, or C30+ fraction.

Because the components with carbon numbers C7 and higher are not separated as pure compounds, their critical parameters are not known for use in EOS modeling. As a result, a process is used to develop a set of pseudo-components to represent these compounds and to determine the critical and other EOS parameters for these pseudo-components. This process is referred to as the fluid or oil characterization process. An EOS characterization refers to a list of hydrocarbon components and pseudo-components and their critical properties and molecular weights, and it includes the binary interaction parameters.

The fluid characterization procedure uses experimental data to assign equation of state parameters to a set of pseudo-components. The experimental data often originates from PVT experiments (e.g. constant mass expansion, constant volume depletion, differential liberation, multistage flashes) of the reservoir fluid of interest. Viscosity data may also be used. Because the characterization process will be using data for a specific reservoir fluid, the resulting characterization will only be valid for that reservoir fluid. There are no universal fluid characterizations.

The development of an EOS characterization proceeds through a series of steps:

All relevant experimental data is collected and reviewed. These data may include:

- Constant mass expansion

- Constant volume depletion

- Differential liberation

- Multistage flashes - Viscosity

- Compositional analysis

Built experimental data into PVT simulation package.

Obtain initial estimate of EOS characterization based on compositional analysis and select number of pseudo-components to be used.

In the PVT simulator, tune pseudo-component critical parameters to minimize error between experimental data and EOS predicted results based on fluid characterization.


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Tuning EOS models to the experimental PVT data can be more of an art than a science, and it requires the use of appropriate software programs. This is at least partially a result of the EOS models being highly nonlinear and the number of adjustable parameters in the regression being large. Additionally, there is no rigorous way to arrive at the global minimum of such a highly nonlinear function. Special non-linear regression techniques have been developed that allow adjusting the constants of the EOS and the critical properties of the pseudo-components to tune the EOS predictions to PVT measurements.

There are limitations associated with fluid characterizations. The pseudo-components are assumed to behave as single, lumped components in phase behavior, but in reality they do not. Some of the pure components lumped in a pseudo-component may not in reality move from one phase to another as the pseudo-component does in the simulation of the fluid. To overcome inaccuracies in the use of EOS to describe the phase behavior of reservoir fluids, characterization procedures need to be followed to generate the most appropriate set of pseudo-components and their relevant properties.

The EOS characterization may only be applicable to some of the processes the fluid may undergo (e.g. reservoir depletion, flowline transport, facilities processing). These processes may be those for which data were available and used in the development of the characterization. Thus, the range of applicability of the EOS characterization depends on the type of PVT data used and the pressure and temperature range of that data

4.6 Fluid Sampling Guidelines

The following guidelines are merely recommendations to encourage the reader to consider the implications and limitations of current technology when designing and implementing a fluid sampling program. Most are not so much new technology as they are common sense. These common sense guidelines were included because they are not consistently followed.

The oilfield environment involves high temperatures and pressures, and flammable liquids and gases. In such an environment, safety is the primary guideline. While some safety recommendations have been included in the following report, we have not attempted to fully address the issue. It is the responsibility of each company to implement these guidelines safely.


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4.6.1 Overview

Executive Summary

As field developments move to deeper water and subsea technology becomes more widely used, paraffin and asphaltenes become more of a real problem than an annoyance. Proper planning becomes critical and cannot be performed without data obtained from representative fluid samples. CTR 901 was formed to address the special considerations associated with collecting and handling fluid samples containing paraffins and asphaltenes.

These guidelines were expanded somewhat beyond the basic goal of fluid sampling for paraffin because it was recognized that in many instances the same sample would be used for multiple reservoir fluid studies by a wide range of disciplines.

The following guidelines were developed with input from industry experts and with vendor input. Issues related to sampling at surface facilities, sampling with downhole flowstream samplers and sampling with downhole formation testers were addressed individually.

Conclusions

In addition to the obvious concerns with obtaining a representative sample from the reservoir, other problem areas must be understood and carefully addressed. First, all equipment used in a sampling operation must be clean. Steam cleaning alone may not remove previously deposited solids and these solids, which precipitate from one sample, may dissolve in the next. Second, sample transfers are a major concern in the area of sampling. In general, transfers performed on samples stabilized at reservoir conditions of temperature and pressure should provide the greatest opportunity for representative transfer. Response from the vendor community is that this is a realistic and attainable goal. Consequently, vendor efforts have recently been directed toward the design and testing of such a system. Ideally, proper planning and equipment selection can minimize the number of transfers.

A major hindrance to getting samples to the lab exists in the area of availability of D.O.T. approved transportation cylinders. While laboratories are increasing their capabilities to analyze samples at reservoir pressure, the availability of suitable transportation cylinders is lagging, especially above 10,000 psi. Vendors report that the cost and time associated with obtaining D.O.T. approval for a specific cylinder design in the pressure ranges required for deepwater development is prohibitive. While some vendors are pursuing this


H-0806.35 4-25 1-Dec-00

approval, none are currently known which can transport a sample at pressures higher than 10,000 psi.

Recommendations

Investigate all reasonable sampling options and carefully plan and document all sampling operations. Coordinate planning efforts with all departments involved in acquiring the sample or in the use of the data that will come from the sample. Develop a prioritized analysis program for the sample detailing which analyses are the primary purpose of obtaining the sample. Communicate with all vendors involved in obtaining and analyzing the sample.

Condition the well to acquire a representative sample and minimize contamination.

Insist that sampling is performed by trained personnel.

Pay specific attention to equipment cleaning prior to sampling.

Minimize the number of transfers a sample will undergo. Perform transfers as near to reservoir conditions of temperature and pressure as possible.

Do whatever possible onsite to verify that a satisfactory sample has been obtained before concluding the sampling operation.

4.6.2 Introduction to Sampling Paraffinic and Asphaltic Fluids

Reservoir oils and condensate liquids may precipitate paraffins or asphaltenes upon reduction of pressure and/or temperature, or evolution of solution gas. This may occur in the formation, the tubing or surface facilities.

Precipitation in the Formation

Precipitation in the formation will preclude the acquisition of representative samples by any sampling technique. Bottomhole sampling may be successful only if the precipitate reaches an equilibrium state in the flowing fluid. Fortunately, while there are references to this type of precipitation in the literature, it unlikely with most Gulf of Mexico crudes.

Precipitation in the Tubing

In this situation, the sampler should be lowered in the hole to a depth below where precipitation is first known to occur. If the pressure at the sampler depth is at or below the bubble point pressure, surface sampling is advised below.


H-0806.35 4-26 1-Dec-00

Precipitation in Surface Facilities

Solid hydrocarbon precipitates could occur in surface separation facilities including separator liquid sampling lines. If bottomhole sampling is precluded, surface sampling would be the only option. However, traditional surface sampling techniques fail to yield representative separator liquid sample. The separator gas sample, however, is considered reliable. In this situation, the liquid sample is best obtained downhole. Upon retrieval to the surface the liquid sample will contain solution gas. The sample is flashed at the prevailing separator conditions of pressure and temperature to yield an equivalent separator liquid sample. Such sample will contain any hydrocarbon precipitates. Recombination with the separator gas sample in the produced gas-oil ratio should yield a representative reservoir fluid sample.

4.6.3 General Job Planning Considerations

Following are the items which one should consider when planning a fluid sampling job. Consideration of these items will help to define whether surface or downhole sampling is required as well as the volume of sample required. It is important to note that data from reservoir fluid studies are used by a wide variety of people. Any sampling effort should be coordinated with all involved parties.

As planning for a sampling job begins, it is important to define the goals and objectives of the job. This will help to ensure that everything needed from the job is obtained and no unnecessary costs are encountered. Following are some of the items of information commonly sought from fluid samples. Included in parentheses are brief statements of how that particular information is used. As can be seen from this list a large number of departments may have an interest in a particular sample. It is important to coordinate with all interested parties when planning a sampling job to promote maximum sample utilization.

1. Wax/Paraffin/Asphaltene/Flow-Separation Studies/Chemical Inhibitor Stud ies (System Design)

2. PVT/Reservoir Fluid Phase Behavior (Reservoir Management and System Design)

3. Hydrate Analysis (System Design)

4. PNA, SARA (Reservoir Management and System Design)

5. Geochemistry, Fingerprinting, etc. (Reservoir Management, Exploration)


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6. Water analysis, e.g. chlorides, scale, corrosion (Reservoir Management and System Design)

7. Crude Assay (Refinery Information, Product Value Determination)

Fluid types may or may not be known before sampling takes place. Certain sampling methods can be problematic for specific fluid types. In addition to the anticipated phase, information may also be available concerning contaminants like H2S, CO2, Sulfur, etc.

It is important to attempt to tabulate how much sample is needed to accomplish the goals and objectives listed above. In addition to the quantity needed for a specific set of goals and objectives, backup samples may be needed. A table is included in section 4.4.14 which may be of assistance in determining required sample volumes.

It is important to give prior thought to the equipment that will be needed or available for a particular job. This applies not only to sampling equipment but also to any site transfer and transportation equipment. Company policy and experience may limit choices in this area. It should be verified that all necessary equipment is available and suitable for the job. Among the things to check are:

Pressure and temperature ratings of all equipment. Verify with vendors that pressurized tools can be heated to the desired temperatures for site transfer as well as being rated for downhole conditions.

Verify that sample containers for transfer and storage meet the goals and objectives of the job. Items to consider in the selection of sample containers include:

- Whether atmospheric, low pressure (i.e. in the range of separator conditions) or high pressure (i.e. in the range of reservoir conditions) will be required. Verify that all cylinders will be pressure tested prior to use.

- Whether special cylinders are required (e.g. for H2S, Hg, etc.)

- In all but rare instances D.O.T. certification of transportation is required. Not all currently available equipment, especially in the higher pressure ranges, has been approved for transportation in the United States. Verify with the vendor that all necessary equipment has been D.O.T. certified (or exempted).

- A variety of transfer and displacement mechanisms are available in sampling and transportation equipment. Company policy and experience may limit the available choices as well as safety concerns. The following list details the available transfer


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mechanisms generally listed in order of preference. [Mercury is available but was not listed due to environmental and safety concerns. Gas can be used as a displaced fluid only (as opposed to a displacing fluid) but beware of the difficulty of accurately obtaining the required voidage for transportation.]

Piston or diaphragm

Formation or saturated brine

Distilled water - Not recommended for acid gas

Potable water - May contain unknown contaminants

Consider in advance any onsite transfer to transportation vessel needs. These may include:

- Having a sufficient quantity of equipment on hand including backup equipment in case of problems.

- Method and degree of heating. Coordination with sampling tool vendors will be necessary to obtain a heating program which is acceptable to all parties. Additional technology is needed in this area to provide heating methods that address the safety concerns of the vendors related to doing transfers at higher temperatures.

- Solvents and other supplies for cleaning all equipment prior to and during the sampling operation should be available along with proper disposal containers.

Make sure all vendor and field personnel are properly trained and understand the importance of your sampling job. Sampling in existing developments is sometimes performed by field personnel who may:

- not be properly trained in sampling

- not understand the importance of obtaining a representative sample and maintaining it during transfer and analysis, and

- not understand the importance of supplying proper documentation of the sampling effort.

Additionally, it is important in downhole sampling to make sure that the importance of the job is understood by all decision making personnel, e.g. in the drilling department, so that problems that arise can be properly handled.


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Make certain that the laboratories involved have the proper capabilities for the type of sample you are providing. The additional cost of taking a pressurized sample and transporting it under pressure to the lab is wasted if the lab must reduce the pressure of the sample to perform the transfer or to analyze the sample.

A key issue is onsite sample verification/validation. It is extremely valuable to verify onsite that a hydrocarbon sample has been taken and, if possible, that it is uncontaminated. In deep water developments in the exploratory phase it is extremely costly to return to a well to resample. Additional technology is needed in this area. Currently available technology and common sense methods include:

- Visual observation

Check for and report any leaks.

Fittings and connections should be observed during tool disassembly to note the presence of oil or mud. If only filtrate is found it can be observed under UV light for florescence.

A sight glass rated for the same temperature and pressure may be installed in the transfer assembly so that fluids may be observed during transfer.

- Verify that opening pressure and temperature are consistent with expectations. Check for a bubble-point at the surface and record the sample temperature during the check and subsequent transfer for validation at lab.

- Fluid analyzers are available in downhole tools which can give indication during sampling of what fluid is entering the tool.

- Verify proper mechanical operation of the tool including clocks, rupture disks, etc.

- Check the water cushion volume on formation testers to verify that a sample was taken.

- Bleed a minute amount of sample. This should only be done if there is a high level of confidence in the safety of the operation and in the ability to limit discharge.

Maximum utilization of sample is a key issue.

- Establish a priority of analysis and verify the results of key items before proceeding to lower priority items.


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- If possible avoid splitting sample until main goals are achieved. Splitting samples and recombining them has inherent opportunities for sample alteration.

Cost and time limitation are always a consideration and may limit the type and volume of sample taken.

- Reservoir and well specific characteristics will impact your sampling efforts. Following are some items to consider:

- Wellbore: hole diameter, rugosity, deviation, size of casing and other well bore equipment, drilling problems which have been encountered, etc.

- Again, verify that all equipment is rated for the reservoir temperature and pressure anticipated in this wellbore. Also, verify that all equipment is rated for any special contaminants anticipated.

- If possible make some prediction concerning the maximum drawdown that can be achieved without taking reservoir fluid through a phase change. Often this will not be possible.

- Formation: Formation pressure, permeability, formation consolidation and grain size.

- Mud system: Mud system, mudcake and their associated filtrates and fines. In some cases, critical sampling needs may dictate in advance that the mud system meet certain criteria, e.g. it is extremely unlikely that an uncontaminated oil sample can be acquired with formation testers if oil based mud is used in the drilling of the well. In some cases, it has been reported that even after two weeks of drill stem testing oil based mud contamination could still be detected in the flow stream.

Determine in advance what will be needed in the "Final Sampling Report" and communicate this to all relevant parties. Include specific requirements for presentation of data and conclusions as well as for onsite documentation of the sampling job.

4.6.4 Surface Sampling

Pre-job Preparation

Verify that the well is properly conditioned for sampling (See section 4.4.9).

Verify all equipment has been properly cleaned (See section 4.4.10).


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Verify that sufficient sample containers of appropriate type are available and on site.

Verify that all sampling equipment is prepared for sampling.

Job Execution

Sampling points on the surface depend on the objective of sampling and tests to be performed. Examples of sampling locations for various test objectives are as follows:

The wellhead or choke manifold may be the best sampling point when checking (qualitatively) for the existence of paraffins and asphaltenes. This would typically be the surface sampling point usually having the highest temperature and pressure with the least likelihood of deposition having occurred. Care must be taken with high pressure environments by using appropriate high pressure sampling cylinders. This sampling point is also feasible for dead oil sampling.

The separator is the most suitable place to sample if the objective is to reconstruct the reservoir fluid. This would be done for such tests as PVT, hydrates etc. Consider that the test separator may contain contaminants from previous testing. Attempt to properly size the separator to allow sufficient throughput to clean any residue left in the separator. The primary stage separator should be the one used for sampling. Sampling points on the separator include:

- Siphon tube - A siphon tube is available on some separators which extends from an external sampling valve down into the oil pan of the separator.

- Oil dump - oil

- Meter runs - oil or gas

- Top valve - gas

- Sight glass for oil or gas. This may not be preferred if it is cooler than the rest of the separator.

Various sampling equipment configurations and procedures can be used. Example configurations and procedures are given in section 4.4.10. These may aid in determining the preferred configuration for a given surface sampling case.


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Verify valves are plugged on arrival and for shipping. Sample containers should also be checked for leaks prior to shipping. This can be done by checking for bubbles after applying "Snoop", Soapy water, or by submersion in water.

Properly label all cylinders and document relevant details of the test. An example form has been included in the section 4.4.13 which may be sent to the location of the sampling job.

4.6.5 Formation Testers Run in Cased and Open Hole

Generally, issues for open-hole and cased-hole formation testers are the same. The primary difference lies in the method employed to isolate the tested interval.

Pre-job Preparation

Verify that well is properly prepared for sampling (See section 4.4.9).

Verify that all equipment has been properly cleaned (See section 4.4.10).

Pressure test sampling equipment to at least reservoir pressure plus 30 percent.

Give the vendor adequate time to prepare and verify proper operation of his equipment.

Verify that all activities are documented and reported to the customer. A sample documentation form is included in section 4.4.13.

Job Execution

Sampling points and methods depend on the objective of sampling and tests to be performed. Following are a list of issues to consider when executing your program:

The existence of a compositional gradient in the reservoir.

Existence of discrete lobes within the zone of interest.

Pressure gradient analysis for fluid density.

Location of the hydrocarbon sample with respect to the depth of the formation water level to assure a representative sample.


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Attempt to minimize filtrate contamination by flowing a volume of reservoir fluid out of the formation prior to taking a sample. This can be accomplished through such actions as the following:

Pump through modules or clean up chambers. The pump through modules allow flowing an unlimited amount of sample through the tool to remove near probe contamination. Clean up chambers allow flowing a limited volume of reservoir fluid to auxiliary chambers.

Use fluid analyzers which can detect various differences in the fluid flowing into the tool. Some currently available analyzers use either the resistivity or optical characteristics of the fluids to make this differentiation.

Minimize the pressure drop while filling the sample chamber. Effectively this involves the use of water cushions, throttling valves or chokes which may result in a longer sampling period. Coordination with the drilling department will be necessary to arrive at a mutually agreeable time period. Also, attempt to fill all void space within the tool with water to prevent excessive drawdown at the instant the tool is opened.

It would be desirable to only sample one zone per run, even with a multi-sampler tool to maximize the potential of taking an uncontaminated sample. These tools have portions of the flow path which will be used for every sample taken. Sampling multiple zones in a single run will cause some mixing of sample. The multi-sampler tools are better suited to taking larger amounts of sample from a single zone.

Caution should be used to prevent pressure release during tool disassembly and sample transfer at surface. This is a common sense statement but once pressure has accidentally been released the damage has been done. Always assume you have a quality sample during the transfer process even if downhole sensors or leakage at the surface suggest otherwise.

Record any indication during disassembly of tool of downhole fluids: oil, gas, mud, water, etc. This can be an early indication of whether hydrocarbons have been sampled or whether only drilling fluid has been sampled.

Keep detailed documentation of sampling job. An example form has been included in the appendix which may be sent to the location of the sampling job (See section 4.4.13).


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Onsite Quality Verification

It is important to do everything possible to identify the quality of the sample before the sampling equipment and/or rig leave the location. Returning for additional sampling will rarely be feasible in deepwater developments (See section 4.4.3).

Onsite Transfer

The following points related to doing onsite transfer to transportation vessels should be kept in mind:

Minimize number of transfers fluid will have to undergo. Every time sample is transferred the likelihood of having an altered sample increases. The following suggestions should be considered:

- Consider sampling tools with transportable D.O.T. certified sample chambers. Chambers which can be detached from the sampling tool and shipped to the lab with the sample intact prevent onsite transfers.

- If possible use transportation cylinders which can hold all of sample cylinder volume so lab recombination will not be necessary. Subsampling into multiple chambers means doing more onsite transfers and also more transfers when the transportation cylinders arrive at the lab.

Sample chambers should be heated to reservoir temperature to guarantee a complete remelt of crystallized paraffins in preparation for and during transfer of sample. Some vendors discourage heating their sampling tools above a certain temperature. This is typically related to concerns about uneven heating of the tool and not to temperature limitations of the tool components. Communication with the vendor will serve not only to educate the vendor to this need but also may result in a solution acceptable to the oil company and the vendor.

Agitate heated sample and return to single phase before transfer to promote homogeneity.

Verify sample quality after transfer if possible (See section 4.4.3).

Disassemble sample chamber and "swab" out all remaining oil and solids. Place these solids and the swabbing cloth in a D.O.T. certified glass container for later analysis. Report observations.


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Chemically rinse the sample chamber until clean and place these samples along with a virgin sample of the chemical used for rinsing in separate D.O.T. certified containers (not plastic) for later analysis. Advance coordination with the vendor will be necessary to identify appropriate cleaning solvents. For a more complete discussion on cleaning see section 4.4.10.

4.6.6 Cased-Hole Sampling (Issues specific to downhole flowstream samplers run on or in tubing)

Pre-job Preparation

Verify that the well is properly prepared for sampling (See section 4.4.9).

Verify that all equipment has been properly cleaned (See section 4.4.10).

Pressure test sampling equipment to at least reservoir pressure plus 30 percent.

Give the vendor adequate time to prepare and verify proper operation of his equipment.

Verify that all activities are documented and reported to the customer. A sample documentation form is included in section 4.4.13.

Job Execution

It is desirable to run the sampler with surface readout of pressure to identify ail fluid levels. This will aid in the proper positioning of the sampler in the fluid column to obtain the most representative fluid and to avoid water. If a surface pressure readout is not available then a separate run with a pressure gauge should be made first to identify fluid contacts. The sampling tool should be positioned above and as near to the perforations as possible.

The well may be sampled while shut- in but issues such as the following must be considered:

Compositional gradients may result in the static fluid column from the pressure and temperature gradient in that column.

Water may begin to settle in the bottom of the wellbore which may result in sampling water.

The well may be sampled while flowing but issues such as the following must be considered:


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Drawdown across the perforations may cause gas to be liberated and the resulting sample may be nonrepresentative.

At very low rates slugging may occur; again this may result in a nonrepresentative fluid sample.

Minimize the pressure drop while filling the sample chamber to increase your chance of sampling single phase fluid.

Caution should be used to prevent pressure release during tool disassembly and sample transfer at surface. This will limit the usefulness of the sample and could prove very costly in resampling.

Record any indication during disassembly of tool of downhole fluids: oil, gas, mud, water, etc. This can be an early indication of whether the proper fluid has been sampled (See also section 4.4.3).

Fluid should be compressed to maintain or obtain single phase condition during transfer.

Take backup surface samples if possible. This should be relatively inexpensive and may prove invaluable if the bottomhole sample quality is questionable.

Keep detailed documentation of sampling job. An example form has been included in section 4.4.13, which may be sent to the location of the sampling job.

4.6.7 Laboratory Transfer of Samples

Verify that all samples sent to the laboratory have been received and note condition of all samples. Check labels on sampling cylinders and sampling data sheets for accuracy.

Verify that transfer equipment and lab storage vessels are clean before transfer (See section 4.4.10).

Verify the transportation cylinder has not leaked.

Verify that opening pressure is the same as it was at the well site at the temperature at which it was performed at the wellsite.

Repeat P-V check (i.e. bubble-point) that was done on site and at that temperature.

Stabilize temperature and pressure of the live fluid samples at reservoir conditions.


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Agitate sample before transfer to promote sample homogeneity.

Disassemble transfer vessel and swab (if possible) all remaining oil and solids. Place these solids and the swabbing cloth in a glass container for later analysis.

Chemically rinse the sample chamber with an appropriate solvent until clean and place these samples along with a sample of the virgin solvent in separate containers for analysis.

Keep detailed documentation of lab site transfer and analysis.

4.6.8 Technology Gaps

CTR 901 believes that additional R&D and implementation are needed in the following areas. The items listed are either not currently available or don't exist in sufficient quantities to meet projected Gulf of Mexico needs. In some cases the technology exists but is not consistently implemented.

A sight glass in the transfer lines should be used during transfer to verify sample quality onsite.

D.O.T. approved transportation cylinders to 10,000 psi with piston displacement mechanisms.

D.O.T. approved high pressure cylinders (> 10,000 psi.) with or without piston displacement mechanisms.

Pressure compensated transportation cylinders - these are needed for situations where asphaltenes are suspected.

D.O.T. approved cylinders of sufficient volume to handle sample chambers are needed to prevent having to subsample onsite.

Sample chambers that are transportable and DOT certified, preferably that can remain at the lab for extended periods of time. These sample chambers would be part of the sampling tool that could be removed and transported to the lab without having to perform an onsite transfer. Ideally, they would remain at the lab until the priority tests are completed and verified, possibly 60 days or so. Some vendors currently offer this service. Unfortunately, not all vendors offe r this type of equipment and the equipment available is limited in quantity and size and priced at a level that makes storage at the lab during analysis very expensive.


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Single phase samplers - These samplers use a nitrogen cushion to maintain reservoir pressure on a sample as it is brought to the surface and cools. These are available in the international market but only on a limited basis in the domestic market.

Downhole fluid analyzers that can accurately detect the difference between hydrocarbons and all mud systems including oil based muds and synthetic oil muds.

Safe methods of heating sampling tools to 300F at the surface for transfers - Currently, safety concerns with uneven heating has prompted some vendors to limit the level to which they will allow their tools to be heated at the surface. Heating methods acceptable to the vendors and customers should be feasible.

Improved transfer systems are needed which address the concerns in the previous item. Also remote transfer capability is attractive from a safety standpoint.

Improved probe/reservoir interface in open-hole sampling tools. This is one of the more common points of failure in formation tester samples.

Ability to truly control drawdown - Formation testers are needed which provide for a reliable, predetermined drawdown. It is desirable to fill all void spaces in the tool and chamber with a non-contaminating fluid. Additionally, the ability to variably pressurize the pathways and chambers in the tool prior to and during sampling is desirable.

Enhanced wellsite analytical capabilities are needed to verify samples before the rig and sampling company leave the wellsite.

Variable rate downhole pump with ability to vent to annulus above top packer for cased hole formation testers - This would permit large quantities of reservoir fluid to be pumped away from sampling point to minimize contamination.

Improved agitation systems for transfers (balls, etc.) - Of

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