Hydrate handbook

Offshore Hydrate Engineering Handbook

a manuscript funded by ARC0 Exploration and Production Technology, Co.

E. Dendy Sloan, Jr. Center for Hydrate Research Colorado School of Mines Golden, Colorado 80401 assisted in production by M.B. Seefeldt

January 1, 1998

Table of Contents Topic

Table of Contents

Disclaimer and Acknowledgements.

.._.....................................

.......................................................................

II. Prevention by Design: How to Ensure Hydrates Won’t Fog

.v

1

Introduction ..........................................................................................................

I. Safety First: A Gallon of Prevention is Worth a Mile of Cure.. _.

..ii

.._......_.._.........

...............................

A. Where Do Hydrates Form in Offshore Systems?. ....................................

1

5 .6

B. A One Minute Estimate of Hydrate Formation (Accurate to *SO%). ....... .l 1 C. A Ten Minute Estimate ofFormation/Inhibition (Accurate to &25%).......12 1. Hydrate Formation Conditions by the Gas Gravity Method.. ........ 13 2. Estimating the Hydrate Inhibitor in the Free Water Phase ............ .14 16 3. Amount of Inhibitor Injected Into Pipeline .................................. 16 ............................................... a. Amount of Water Phase.. b. Amount of Inhibitor Lost to the Gas Phase ..................... .17 c. Amount of Inhibitor Lost to the Liquid Phase ................. .17 4. Example Calculation of Amount Methanol Injection .................... .17 .20 5. Computer Program for Second Approximation ........................... D. Most Accurate Calculation of Hydrate Formation/Inhibition. ................. .23 1. Hydrate Formation and Inhibitor Amounts in Water Phase ............ 23 2. Conversion ofMeOH to MEG Concentration in Water Phase........2 5 .25 3. Solubility of MeOH and MEG in the Gas .................................... 4. Solubility of MeOH and MEG in the Condensate ......................... .26 5. Best Calculation Technique for MeOH or MEG Injection ............ .26 E. Case Study: Prevention of Hydrates in Dog Lake Field Pipeline ............. .30 F. Hydrate Limits to Expansion through Valves or Restrictions ................... . 1 1. Rapid Calculation of Hydrate-Free Expansion Limits. .................. .33 2. More Accurate Calculation of Hydrate-Free Gas Expansion..........3 4 3. Methods to Prevent Hydrate Formation on Expansion ................ ..3 6

ii

G. Hydrate Control Through Chemical Inhibition and Heat Management .... 1. Inhibition with Methanol or Mono-ethylene Glycol.. ................... a. Methanol ...................................................................... b. Monoethylene Glycol.. .................................................. c. Comparison of Methanol and Glycol Injection ................. 2. Kinetic Control by Anti-Agglomerants and Kinetic Inhibitors ....... a. Anti-Agglomerants.. ..................................................... b. Kinetic Inhibition ........................................................... 3. Guidelines for Use of Chemical Inhibitors.. ................................ 4. Heat Management.. ................................................................... a Insulation Methods.. ...................................................... b Pipeline Heating Methods.. ............................................ H. Design Guidelines for Offshore Hydrate Prevention ...............................

III. Hydrate Plug Remediation.. ...........................................................................

..4 1 .42 .42 .44 .45 .45 ..4 6 .47 ..5 0 .53 ..5 4 ..5 5 .55

..5 8

A. How Do Hydrate Blockages Occur?. ................................................... ..5 9 1. Concept of Hydrate Particle and Blockage Formation ................. .59 2. Process Points of Hydrate Blockage.. ...................................... ..6 1 B. Techniques to Detect Hydrates.. ........................................................... .62 1. Early Warning Signs for Hydrates ............................................. .63 a. Early Warnings in Subsea Pipelines.. ............................... ..6 3 b. Early Warnings Topside on Platforms .............................. .66 2. Detection of Hydrates Blockage Locations.. .............................. ..6 7 a. Inhibitors or Mechanical/Optical Devices. ......................... .68 b. Pressure Location Techniques ......................................... .69 c Measuring Internal Pressure through External Sensors ....... .72 d. Recommended Procedure to Locate a Hydrate Plug .......... .73 C. Techniques to Remove a Hydrate Blockage.. ........................................ ..7 4 1. Depressurization of Hydrate Plugs.. .......................................... ..7 4 a. Conceptual Picture of Hydrate Depressurization ............... .75 b. Hydrate Depressurization from Both Sides of Plug ............ .77 c. Depressurization of Plugs with Significant Liquid Heads.....8 3 d. Depressurizing One Side of Plug(s) ................................. .85 2. Chemical Methods of Plug Removal. ......................................... ..8 8 3. Thermal Methods of Plug Removal.. ........................................ ..8 9 4. Mechanical Methods of Plug Removal.. ..................................... ..9 0 D. Avoiding Hydrates on Flowline Shut-in or Start-up ...............................

.91

E. Recommendations and Future Development Areas ................................. 1. Recommendation Summary for Hydrate Remediation .................. 2. Recommendations for Future Work.. ..........................................

IV. Economics ..................................................................................................

.93 .93 .94

..9 5

A, The Economics of Hydrate Safety.. ...................................................... ..9 5 B. The Economics of Hydrate Prevention.. ................................................ .95 1. Chemical Injection Economics.. ................................................. .95 a. Economics of Methanol and Mono-ethylene Glycol... ........ .96 b. Economics of New Types of Inhibitors.. ............................ 98 2. Heat Management Economics.. ................................................. 100 a. Economics of Insulation.. ............................................... 100 C. The Economics of Hydrate Remediation .............................................. ,101

Appendix A. Gas Hydrate Structures, Properties, and How They Form.. ............... .I03 1. Hydrate Crystal Structures.. ................................................................ 103 2. Properties Derive from Crystal Structures.. ......................................... ,104 a. Mechanical Properties of Hydrates ............................................ ,104 b. Guest: Cavity Size Ratio: a Basis for Property Understanding ...... 105 c. Phase Equilibrium Properties.. .................................................. ,106 d. Heat of Dissociation ................................................................ ,107 3. Formation Kinetics Relate to Hydrate Crystal Structures ...................... ,107 a. Conceptual Picture of Hydrate Growth. .................................... .I07

Appendix B. User’s Guide for HYDOFF and XPAND Programs.. ........................ B.l.HYDOFF.. .................................................................................... B.2. XF’AND.. ......................................................................................

Appendix C. Additional Case Studies of Hydrate Blockage and Remediation..

Appendix D. Compilation of Rules-of-Thumb

in Handbook .................................

References ........................................................................................................

iv

,109 .I09 ,123

128

.I45

149

DISCLAIMER The description, methods, and cases discussed in this manuscript are presented solely for educational purposes and are not intended to constitute design or operating guidelines or specifications. While every effort has been made to present current and accurate information, the author (and sponsoring and contributing organizations) assume no liability whatsoever for any loss or damage resulting from use of the material in this manuscript; or for any infringement of patents or violation of any federal, state, or municipal regulations. This manuscript was intended to supplement, but not to replace engineering judgment. Use of the information in these notes is solely at the risk of the reader.

ACKNOWLEDGEMENTS The by Mr. Ben is a paean engineering,

idea for the Handbook was conceived Bloys of ARC0 Exploration and Production Technology Co. This work to Mr. Bloys’ foresight regarding the state of knowledge in hydrate coupled with intelligence and a magnanimous perspective.

Two others have been fundamental to the project. Mr. Jim Chitwood of Texaco has ensured Deepstar hydrate-related reports (Phases I, II, and IIA) were made available to this project. The power of a multi-company consortium, demonstrated by Deepstar, has provided an invaluable supplement to the manuscript. Dr. John Cayias of Oryx Energy contributed by providing for visits to offshore platforms and by providing travels funds and funds for Mr. Seefeldt, the student worker who aided in production of the figures. Dr. Cayias’ questions have been very useful in re-thinking and re-stating the concepts summarized in the handbook. Other contributors order by company:

who have contributed generously are listed in alphabetical

Amoco’s Mssrs. George Shoup and J.J. Xiao provided hydrate plug transientflow simulation results and they reviewed the preliminary draft. At ARCO. in addition to Mr. Bloys’ continuous contributions, Mr. Phil Lynch (ARC0 British Ltd.) kindly provided the most detailed North Sea case study. British Petroleum contributed heavily through Drs. Carl Argo and Chris Osborne (Sunbury) and particularly Dr. Tony Edwards (Dimlington), who related North Sea commercial operating experiences with new inhibitors. Chevron’s Dr. Pat Shuler generously contributed his spreadsheet program HYDCALC to determine inhibition amounts, and he provided access to offshore engineers. Dr. Carl Gerdes reviewed the guidelines for safety, design, and operation. Conoco’s Mr. Stan Swearingen and Mobil’s Mr. Barry Ho&ran were helpful in reviewing both guidelines and manuscript drafts.

V

At Phillips Dr. Bill Parrish provided a hydrate perspective gamed over a quarter century of research and plant optimization. Dr. Parris’s collaboration provided an essential bridge between the theoretical and industrial perspectives. At Statoil’s Research Center in Trondheim, the Hydrate Team composed of Drs. T. Austvik (leader), L.-H. Gjertsen, 0. Urdahl and A. Lund (SINTEF) provided two fin1 days of interviews regarding hydrate prevention and remediation in the Norwegian sector of the North Sea. At Texaco, in addition to Mr. Chitwood’s tie-in with Deepstar, Dr. Phil Notz has been a hydrate colleague for over a decade, and he provided information on inhibitor economics, feedback on guidelines, and reviewed the draft of the manuscript. Mr Jack Todd at Texaco was extremely helpful in providing the Texaco Reliability Engineering Manual for operating personnel, and in arranging interview with Texaco offshore engineers. The efforts of the above personnel have contributed in an essential way to this handbook. Their efforts have been an invaluable supplement in moving the handbook toward industrial utility. This handbook is limited by a personal perspective, intended to assimilate and synthesize the above contributions and those in the literature. The readers’ constructive critiques are solicited with the goal of improving subsequent revisions.

vi

Introduction Natural gas hydrates are crystals formed by water with natural gases and associated liquids, in a ratio of 85 mole % water to 15% hydrocarbons. The hydrocarbons are encaged in ice-like solids which do not flow, but rapidly grow and agglomerate to sizes which can block flow lines. Hydrates can form anywhere and anytime that hydrocarbons and water are present at the right temperature and pressure, such as in wells, flow lines, or valves and meter discharges. Appendix A gives hydrate crystal details at the molecular level, along with similarities and differences from ice. The low temperatures and high pressures of the deepwater environment cause hydrate formation, as a function of gas and water composition. In a pipeline, hydrate masses usually form at the hydrocarbon-water interface, and accumulate as flow pushes them downstream. The resulting porous hydrate plugs have the unusual ability to transmit some degree of gas pressure, while they act as a flow hindrance. Both gas and liquid can frequently be transmitted through the plug; however, lower viscosity and surface tension favors the flow of gas. Depressurization of pipelines is the principal offshore tool for hydrate plug removal; depressurization sometimes prevents normal production for weeks. This handbook was written to provide the offshore facilities/design engineer with practical answers to the following four questions: • • • •

What are the safety problems associated with hydrates? (Section I) What are the best methods to prevent hydrates? (Section II) How are hydrate plugs best removed? (Section III) What are the economics for prevention and remediation? (Section IV)

Field case studies, pictures, diagrams, and example calculations are the basis for this handbook. Less pressing questions regarding hydrate structures, plug formation mechanism, etc. are considered as background material in Appendix A. A computer program disk and User’s Guide (Appendix B) are provided to enable prediction of hydrate conditions. Appendix C is a compilation of Case Studies not in the handbook body. A Russian hydrate perspective is presented in Makogon’s (1981, 1997) books. An in-depth, theoretical hydrate treatment is given by Sloan (1998).

I. Safety First: A Gallon of Prevention is Worth a Mile of Cure There are many examples of line rupture, sometimes accompanied by loss of life, attributed to the formation of hydrate plugs. Hydrate safety problems are caused by three characteristics: 1. Hydrate densities are like that of ice; a dislodged hydrate plug can be a projectile with high velocities. In the 1997 DeepStar Wyoming field tests, plugs ranged from 1

25-200 ft. with velocities between 60-270 ft/s. Such velocities and masses provide enough momentum to cause two types of failure at a pipeline restriction (orifice), obstruction (flange or valve), or sharp change in direction (bend, elbow, or tee) as shown in Figure 1. First, hydrate impact can fracture pipe, and second, extreme compression of gas can cause pipe rupture downstream of the hydrate path. 2. Hydrates can form either single or multiple plugs, with no method to predict which will occur. High differential pressures can be trapped between plugs, even when the discharge end of plugs are depressurized. 3. Hydrates contain as much as 180 volumes (STP) of gas per volume of hydrate. When hydrate plugs are dissociated by heating, any confinement causes rapid gas pressure increases. However, hydrate plug heating is not an offshore option due to the difficulty of locating the plug and economics of heating a submerged pipeline. Field engineers discuss the “hail-on-a-tin-roof” sounds when small hydrate particles hit a pipe wall. Such small, mobile particles can accumulate to large masses occupying a considerable volume, often filling the pipeline to tens or hundreds of feet in length. Attempts to “blow the plug out of the line” by increasing upstream pressure (see Rule-of-Thumb 18) will result in additional hydrate formation and perhaps pipeline rupture. When a plug is depressurized using a high differential pressure, the dislodged plug can be a dangerous projectile which can cause pipeline damage, as the below three case studies (from Mobil’s Kent and Coolen, 1992) indicate. _____________________________________________________________________ Case Study 1. 1991 Chevron Incident. A foreman and an operator were attempting to clear a hydrate plug in a sour gas flowline. They had bled down the pressure in the distant end from the wellhead. They were standing near the line when the line failed, probably from the impact of a moving hydrate mass. A large piece of pipe struck the foreman and the operator summoned help. An air ambulance was deployed; however the foreman was declared dead on arrival at the hospital. No pre-existing pipe defects were found. _____________________________________________________________________ _____________________________________________________________________ Case Study 2. 1991 Gulf Incident On January 10, 1991 the Rimbey gas plant was in the start-up mode. A hydrate or ice plug formed in the overhead line from the amine contactor. The line had been depressured to the flare system, downstream of the plug. The ambient temperature which had been -30oC, rose rapidly due to warming winds around midnight. At 2:00 a.m. the overhead line came apart, killing the chief operator. In addition, approximately $6 million damage was suffered by the plant.

2

Figure 1 - Safety Hazards of Moving Hydrate Plugs (From Chevron Canada Resources, 1992)

1a)

Where the pipe bends, the hydrate plug can rupture the flowline through projectile impact.

A hydrate plug moves down aflowline at very high velocites.

1b) A hydrate plug moves down a flowline at very high velocites.

Closed Valve

If the velocity is high enough, the momentum of the plug can cause pressures large enough to rupture theflowline.

Closed Valve

Contributing to this failure were pre-existing cracks in the pipeline. These cracks did not impair the piping’s pressure-containing ability under steady-state conditions, but they did reduce the piping strength under the transient (impact) conditions when the plug broke free. _____________________________________________________________________ _____________________________________________________________________ Case Study 3. 1991 Mobil Incident At 11:30 a.m. on January 2, 1991 two operators attempted to remove a blockage in a sour gas flowline, which had been plugged about three days. The downstream side of the plug had been completely depressured. The upstream portion of the line, originally at 1,100 psig, was completely depressured to a truck within a 5 minute period. At 12:15 p.m. the flowline failed and gas began flowing from somewhere around the casing. The leak was isolated at 3:18 p.m. by an employee of a well-control/firefighting company. The failure was caused by the eruption of a hydrate plug at a Schedule 40, 3 inch, screwed pipe nipple. Note that, because both ends of the hydrate plug were depressured, there may have been two end plugs, with intermediate plugs or pressure as shown in Figure 2a. _____________________________________________________________________ In the above three case studies several common equipment circumstances existed. The systems: 1. 2. 3. 4. 5.

Were out-of-service immediately prior to the incident. Did not have hydrate or freeze protection. Were pressurized while out-of-service. Were being restarted. Had high differential pressures across plugs for short periods.

The Chevron Canada Resources Hydrate Handling Guidelines (1992) suggest that the danger of line failure due to hydrate plug(s) is more prevalent when: • •

long lengths of pressurized gas are trapped upstream, low downstream pressures provide less cushion between a plug and restriction, and • restrictions/bends exist downstream of the plug. _____________________________________________________________________ Case Study 4. 1980’s Statoil Incident In the mid-1980’s a hydrate plug occurred topside on a platform in a Statoil oil Field in the Norwegian sector of the North Sea. The line section was valved-off and heat was applied to remove the plug. After some time of heating, the work crew went

3

Figure 2 - Safety Hazards of High Pressures Trapped by Hydrates (From Chevron Canada Resources, 1992)

2a)

Low Pressure

High Pressure

Hydrate Plug

Hydrate Plug

SATELLITE

WELLHEAD

2b)

Low Pressure

Heat Addition Gas Hydrate Plug

Pipeline Rupture

Gas Hydrate Plug

to lunch, intending to complete the task on their return. Upon their return the crew found that the section of line had exploded during their absence. Heat had apparently been applied to the mid-point of hydrate plug and the plug-end portions served to contain very high pressures until the line ruptured. Figure 2b is a schematic of such a situation. In Section II it is shown that pressure increases exponentially with temperature increases when hydrates are dissociated. _____________________________________________________________________ _____________________________________________________________________ Case Study 5. 1970’s Elf Incident In the 1970’s a plug occurred on a floating platform riser in the North Sea. Blocking valves were closed and the pipeline was disconnected downstream of the plug. The discharge end of the pipeline was aimed overboard, with the intent of using high upstream pressure to extrude the plug from the line. When the plug was expelled into the ocean, the force was so great that the platform was said to rise 20 cm in the ocean. _____________________________________________________________________ The Canadian Association of Petroleum Producers Hydrate Guidelines (1994) suggest three safety concerns in dealing with hydrate blockages: • • •

• •

Always assume multiple hydrate plugs; there may be pressure between the plugs. Attempting to move ice (hydrate) plugs can rupture pipes and vessels. While heating a plug is not normally an option for a subsea hydrate, any heating should always be done from the end of a plug, rather than heating the plug middle. The last recommendation could be expanded in consideration of a subsea line: Heating a subsea plug is not recommended due to the inability to determine the end of the plug as well as provide for gas expansion on plug heating, and Depressuring a plug gradually from both ends is recommended.

The above case studies warn that hydrates can be hazardous to health and to equipment. Yet hydrate plugs can be safely dissociated through the procedure indicated in the Remediation Section (III) of this handbook. The preferred procedure, from both safety and economic considerations, is to prevent the formation of hydrate plugs, through design and operating practices. While the usage of many gallons of inhibitors may be costly on a continuous basis, such expenses are easily overshadowed when plugs form and production is stopped. As the case studies in this handbook show, it is not uncommon for several hundred yards of hydrate plugs to form, preventing offshore production for a matter of weeks or months, during remediation.

4

II. Prevention by Design: How to Ensure Hydrates Won’t Form The purpose of the prevention section is (1) to indicate common offshore sites of hydrate formation, (2) to indicate design methods to provide hydrate protection, and (3) to provide designs to make remediation easier if a hydrate plug occurs. Three conditions are required for hydrate formation in offshore processes: a) Free water and natural gas are needed. Gas molecules ranging in size from methane to butane are typical hydrate components, including CO2, N2, and H2S. The water in hydrates can come from free water produced from the reservoir, or from water condensed by cooling the gas phase. Usually the pipeline residence time is insufficient for hydrates to form either from water vaporized into the gas, or from gas dissolved in the liquid water. b) Low temperatures are normally witnessed in hydrate formation; yet, while hydrates are 85 mole % water, the system temperature need not be below 32oF for hydrates to occur. Below about 3000 feet of water depth, the ocean bottom (mudline) temperature is remarkably uniform at 38-40oF and pipelined gas readily cools to this temperature within a few miles of the wellhead. Hydrates can easily form at 38-40oF as well as the higher temperatures of shallower water, at high pressure. c) High pressures commonly cause hydrate formation. At 38oF, common natural gases form hydrates at pressures as low as 100 psig; at 1500 psig, common gases form hydrates at 66oF. Since pipelines typically operate at higher pressures, hydrate prevention should be a primary consideration. The above three hydrate requirements lead to four classical thermodynamic prevention methods: 1. Water removal provides the best protection. Free water is removed through separation, and water dissolved in the gas is removed by drying with tri-ethylene glycol to obtain water contents less than 7 lbm/MMscf. Water removal processing is difficult and costly between the wellhead and the platform so other prevention schemes must be used. 2. Maintaining high temperatures keeps the system in the hydrate-free region (see Section II.G.4). High reservoir fluid temperature may be retained through insulation and pipe bundling, or additional heat may be input via hot fluids or electrical heating, although this is not economical in many cases. 3. The system may be decreased below hydrate formation pressure. This leads to the concept of designing system pressure drops at high temperature points (e.g. bottom-hole chokes). However, the resulting lower density will decrease pipeline efficiency. 4. Most frequently hydrate prevention means injecting an inhibitor such as methanol (MeOH) or mono-ethylene glycol (MEG), which decreases the hydrate formation temperature below the operating temperature.

5

Two kinetic means of hydrate inhibition have been added to the thermodynamic inhibitor list and are being brought into common practice: 5. Kinetic inhibitors are low molecular weight polymers and small molecules dissolved in a carrier solvent and injected into the water phase in pipelines. These inhibitors work by bonding to the hydrate surface and preventing crystal nucleation and growth for a period longer than the free water residence time in a pipeline. Water is then removed at a platform or onshore. 6. Anti-agglomerants are surfactants which cause the water phase to be suspended as small droplets in the oil or condensate. When the suspended water droplets convert to hydrates, the flow characteristics are maintained without blockage. Alternatively the surfactant may transport micro-crystals of hydrate into the condensed phase. The emulsion is broken and water is removed onshore or at a platform. The above methods are used individually or jointly for prevention. The prevention section of this handbook provides a method to use the six above methods to prevent hydrates in the design of an offshore system. Hydrates form in offshore systems in two fundamental ways: (a) slow cooling of a fluid as in a pipeline (see Example 2 below) or (b) rapid cooling caused by depressurization across valves as on a platform (see Example 3). Section II.A. provides typical offshore system examples of hydrate formation in a well, a flowline, and a platform. Offshore design for hydrate thermodynamic inhibition with slow cooling of a pipeline is the topic of Sections II.B, C, D, and E. Design practices are provided in Section II.F for hydrate prevention with rapid cooling across a restriction like a valve. Section II.G gives procedures for prevention of hydrates through inhibition and heat management. Section II.H. provides general design guidelines for hydrate prevention in an offshore system.

II.A. Where Do Hydrates Form in Offshore Systems? Figure 3 shows a simplified offshore process between the well inlet and the platform export discharge where virtually all hydrate problems occur. In the figure hydrate blockages are shown in susceptible portions of the system: (a) the well, (b) the pipeline, or (c) the platform, and this section provides a brief description of each in Examples 1, 2, and 3, respectively,. Prior to the well, high reservoir temperatures prevent hydrate formation, and after the platform export lines have dry gas and oil/condensate with insufficient water to form hydrates. In Figure 3, two unusual aspects of the system should be noted: (1) the water depth is shown as 6,000 ft. but it may range to 10,000 ft., and (2) the distance between the well and the platform may range to 60 miles. Such depths and distances provide

6

Figure 3 - Offshore Well, Transport Pipeline, and Platform DRY

COMP.

SEP.

Platform

Ocean

- Depth 6000 ft Well with X-Mas Tree

Transport Pipeline (2-60 miles in length)

Blockage in Riser

Blockage in Tree, Manifold, Well

Mudline

Downhole Safety Valve

Blockage in Flowline

Bulge from Expansion or Topography

Export Flowline

Riser

cooling for the pipeline fluids to low temperatures which are well within the hydrate stability region. The system temperature and pressure at the point of hydrate formation must be within the hydrate stability region, as determined by the methods of Sections II.B through II.D. The system temperature and pressure enters into the hydrate formation region, either through a normal cooling process (Example 2 and Figures 6 and 7) or through a Joule-Thomson process (Section II.F). A typical plot of the water temperature in the Gulf of Mexico is shown in Figure 4 as a function of water depth. The plot shows a high temperature of 70oF (or more) occurs for the first 250 ft. of depth. However, when the depth exceeds 3,000 ft. the bottom water temperature is very uniform at about 40oF, no matter how high the temperature is at the air-water surface. This remarkably uniform water temperature at depths greater than 3,000 ft. occurs in almost all of the earth’s oceans, (caused by the water density inversion) except in a few cases with cold subsea currents. The ocean acts as a heat sink for any gas or oil produced so that, without insulation or other heat control methods, any flowline fluid cools to within a few degrees of 40oF, no further than a few miles of the wellhead. The rate of cooling with length is a function of the initial reservoir temperature, the flow rate, the pipeline diameter, and other fluid flow and heat transfer factors. However, as shown in Section II.B, the ocean bottom temperature of 40oF is low enough to cause hydrates to form at any typical pipeline pressure. _____________________________________________________________________ Example 1. Hydrate Formation in a Well. Figure 5 shows a typical subsea well in which fluids are produced through the wing valve and choke to the pipeline. A pressure indication just beyond the choke is essential to determination of hydrate formation in the connecting flowline. About 300-500 ft. below the mudline is the Downhole Safety Valve, used as the initial emergency barrier between the reservoir and the production system. At the top of the well are Swab Valves, which provide an entry way for lubricating hydrate dissociation tools (inhibitor injection, heaters, coiled tubing, etc.) into the well to reach any hydrate blockage. Hydrate formation in wells is an abnormal occurrence, arising during drilling of the well or shut-in/start-up of the well. Normal well-testing procedures will not promote hydrate formation. Hydrates form only in unusual circumstances, such as pressurizing the well with water or with an aqueous acid solution. Addressing these blockages should be done using the techniques in the Remediation Section (III). Case Studies 11 (Section III.B.2.a) and 16 (Section III.C.3) provide two experiences with hydrate formation in a well. Davalath and Barker (1993) provide a comprehensive set of conditions for dealing with hydrates in deepwater production and testing, including two case studies

7

Figure 4 - Water Temperature vs. Depth (Gulf of Mexico) 10

Ocean Depth (feet)

100

1000

10000 20

30

40

50

60

Temperature (oF)

70

80

Figure 5 - Typical Subsea Well Swab Valve Christmas Tree Wing Valve Crossover Valve Master Valve Wellhead Mudline

30 inch

Downhole Completion

Downhole Safety Valve 20 inch

13 3/8 inch

9 5/8 inch

of problems (summarized in Appendix C Case Studies C.23 and C.24) and four case studies of successful hydrate management. Typically methanol injection capability is provided in the well at two places: (1) at the subsea tree, and (2) downhole several thousand feet below the seafloor. The injection location and amount of methanol injection are specified using the procedure indicated in Section II.G.1.a on methanol injection. In offshore well drilling, frequently a water-based drilling fluid is used that can form hydrates and plug blow-out preventors, kill lines, etc. when a gas bubble (or “kick”) comes into the drilling apparatus. This represents a potentially dangerous situation for well control. Hydrate formation on drilling is an area of active research with several joint industrial projects underway. While a brief overview is given here, the reader is referred to Sloan (1998, Section 8.3.2) for a detailed discussion. Barker indicated the following rules-of-thumb used by Exxon in considering hydrate formation with drilling fluids. • Drilling hydrate problems frequently occur, but have only been recognized in recent years. • When hydrates form solids, they remove water from the mud, leaving a solid barite plug. • One should not design a well to operate outside the hydrate region only if flow conditions are maintained. If the well will be in the hydrate formation region at static conditions, flow will stop at some period and the well operation will be jeopardized. • Several hours may be required for hydrate formation and blockage to occur. • As of October 1988 Exxon used salt at the saturation limit range of 150 to 170 g/l to prevent hydrate formation. • As general guidelines concerning hydrate formation at various water depths, the summary given below by Barker may be used:

Guidelines for Deepwater Hydrate Formation in Drilling Muds in Water-Based Muds Water Depth (ft.) <1000 ≤1500 ≤2000 ≥3000

Risk of Hydrate Formation Problems A hydrate problem will probably not occur Without inhibition a hydrate problem may occur Without inhibition a hydrate problem will occur Insufficient experience; salt alone will not suffice

By 1988 Shell had drilled 16 wells in the Gulf of Mexico at water depths between 2,000 and 7,500 feet, using muds with 20 wt% sodium chloride (NaCl) and partially hydrolyzed polyacrylamide (PHPA). In each well Shell experienced an

8

average of more than one gas kick per well, which signaled the possibility of hydrate formation. Only one instance in 2900 ft. of water involved the possibility of hydrate formation, when Shell experienced difficulty disconnecting the drill stack. Barker and Gomez (1989) documented two occurrences (see Case Studies C.21 and C.22 of Appendix C) of hydrate formation in relatively shallow waters off California and the Gulf of Mexico, where losses in drill times were 70 days and 50 days, respectively. Recently the number of hydrate problems have increased dramatically as drilling has moved to deeper water. In several cases where safety was an issue (plugged blow out preventers, stack connectors, etc.) the well was abandoned. Much remains to be done in this area. _____________________________________________________________________ Downstream of the well and choke, the fluid flows through a pipeline of considerable length before reaching the platform. Example 2 represents flow conditions in the pipeline. _____________________________________________________________________ Example 2: Hydrate formation in a Flowline. Texaco’s Notz, (1994) provided a hydrate pipeline case in Figure 6 for a Gulf of Mexico gas. To the right of the diagram hydrates will not form and the system will exist in the fluid (hydrocarbon and water) region. However, hydrates will form in the shaded region to the left of the diagram, and hydrate prevention measures should be taken. Pipeline pressure and temperature conditions were predicted using a pipe prediction program such as OLGA® or PIPEPHASE® and those conditions are shown superimposed on the hydrate conditions in Figure 6. At low pipeline distances (e.g. 7 miles) the flowing stream retains a high temperature from the hot reservoir gas at the pipeline entrance. The ocean cools the system, and at about 9 miles a unit mass of flowing gas and associated water enters the hydrate region (shaded region to the left of the line marked 0% MeOH), remaining in the uninhibited hydrate area until mile 45. Such a distance may represent several days of residence time for the water phase, so that hydrates would undoubtedly form, were not inhibition steps taken. In Figure 6, by mile 25 the temperature of the pipeline system is within a few degrees of the ocean floor temperature, so that approximately 23 wt% methanol is required in the free water phase to prevent hydrate formation and subsequent pipeline blockage. Methanol injection facilities are not available at the needed point along the pipeline. Instead methanol is injected into the pipeline at the subsea well-head. In the case of the pipeline shown in Figure 6 methanol is injected at the wellhead so that in excess of 23 wt% methanol will be present in the free water phase over the entire pipeline length. As vaporized methanol flows along the pipeline in Figure 6, it dissolves into any produced brine or water condensed from the gas. Hydrate inhibition occurs in the free water, usually at accumulations with some change in geometry (e.g., a bend or

9

Figure 6 - Offshore Pipeline Plotted on Hydrate Formation Curves (From Notz, 1994)

2500

30% MeOH

Pressure(psia)

2000

Hydrate Forming Region

1500

20% MeOH

10% MeOH

7 Miles

10

15

25

Hydrate Formation Curve

20

30

1000

35 500

50

Hydrate Free Region

40 45

0 30

40

50 Temperature(oF)

60

70

80

pipeline dip along an ocean floor depression) or some nucleation site (e.g., sand, weld slag, etc.). Hydrate inhibition occurs in the aqueous liquid, rather than in the vapor or condensate. While most of the methanol dissolves in the water phase, a significant amount of methanol either remains with the vapor or dissolves into any liquid hydrocarbon phase present as calculated using the methods shown later in this section. In Figure 6 Notz showed that the gas temperature increases from mile 30 to mile 45 with warmer (shallower) water conditions. From mile 45 to mile 50 however, a second cooling trend is observed due to a Joule-Thomson gas expansion effect. Methanol exiting the pipeline in the vapor, aqueous, and condensate phases is usually not recovered, due to the expense of regeneration. _____________________________________________________________________

Todd (1997) provided simulations with a different behavior from the pipeline in Figure 6. In Todd’s simulations, typical gas pipeline pressure drops are small relative to the overall pressure, resulting in an almost constant pressure cooling, providing a straight, horizontal line between the pipeline end points on a plot like Figure 7. Pipeline pressure drops are functions of several variables, and individual systems should be simulated for best results. _____________________________________________________________________ Example 3: Typical Offshore Platform Process. Manning and Thompson (1991, pp. 80-82, 344-355) detail a typical offshore platform process for a sweet crude oil with dissolved gas delivered to the platform at 1000 psig and 120oF. The process is shown in Figure 8 with process conditions given in Table 1 and selected stream compositions provided in Table 2. The process was sized for a product of 100,000 barrels per day (bpd) of oil to the pipeline at the LACT (lease automatic custody transfer) unit, with 49 MMscf/d gas produced at 1000 psig and an overall gas to oil ratio (GOR) of 491 scf/Bsto. The heavy ends of the crude are divided into five boiling-point cuts while mole fractions of individual gas components are given. There are three objectives of the platform process: 1. to separate the gas, water, and oil, providing an oil phase which has a very low vapor pressure, and providing water discharge to the ocean. 2. to dehydrate the gas to a water content below 7 lbm/MMscf before injection into the pipeline to shore, and 3. to compress the gas for transport to land.

10

Figure 7 - Typical Transport Pipeline Plotted on Hydrate Formation Curves (From Todd, 1997)

3000

Hydrate Formation Curve

10% MeOH

Pressure(psia)

2500 2000 1500 Pipeline

Separator

Wellhead

1000 500 0 30

35

40

45

50

55

Temperature(oF)

60

65

70

75

Figure

8

-

Typical (From

Offshore Manning

and

Pbtform

Thompson,

1991)

-u Main oil punp

Schematic

Table 1 - Platform Processing Conditions (From Manning and Thompson, 1991)

o

Location

Pressure(PSIA)

Temperature( F)

Mol/Hr

Mol Wt

1

1019.7

120

12297.76

105.9

0.1821

0

2

1019.7

120

2238.98

18.79

1

0

3

1019.7

120

10058.78

125.29

0

111807.9

4

314.7

115.86

10058.78

125.29

0.2026

0

5

314.7

115.86

2038.13

20.39

1

0

6

314.7

115.86

8020.65

151.94

0

104667.3

7

69.7

111.45

8020.65

151.94

0.1084

0

8

69.7

111.45

869.66

27.44

1

0

9

69.7

111.45

7150.99

167.09

0

101141.7

10

16.7

106.22

7150.99

167.09

0.0664

0

11

16.7

106.22

474.67

43.13

1

0

12

16.7

106.22

6676.32

175.9

0

98533.16

13

74.7

236.54

474.67

74.7

1

0

14

69.7

100

474.67

69.7

0.9464

0

15

69.7

100

449.21

69.7

1

0

16

69.7

100

25.47

69.7

0

199.99

17

69.7

106.27

1318.87

32.2

1

0

18

319.7

280.91

1318.87

32.2

1

0

19

314.7

100

1318.87

32.2

0.8655

0

20

314.7

100

1141.54

28.83

1

0

21

314.7

100

177.32

53.89

0

1172.6

22

314.7

107.94

3179.67

23.42

1

0

23

1024.7

285.05

3179.66

23.42

1

0

24

1019.7

100

3179.66

23.42

0.9926

0

25

1019.7

100

3156.23

23.27

1

0

26

1019.7

100

23.43

43.18

0

144.6

27

1019.7

104.9

5395.21

21.41

1

0

28

314.7

95.43

200.75

52.64

0.0504

0

29

314.7

97.93

226.22

54.96

0.0275

0

30

314.7

104.75

6902.53

171.93

0

100000.1

Frac. Vap BPD @60F

Table 2 - Gas and Liquid Compositions on Platform (From Manning and Thomson,1991) #1

Inlet Fluid

#2

#3

#5

#6

#8

#9

#11

#12

#14

#15

Gas Out

Liq. Out

Gas Out

Liq. Out

Gas Out

Liq. Out

Gas Out

Liq. Out

5th Sep.

Gas Out

1st Sep.

1st Sep.

2nd Sep.

2nd Sep.

3rd Sep.

3rd Sep.

3rd Sep.

4th Sep.

Inlet

6th Sep.

Comp.(Mol Frac.)

Nitrogen

0.0078

0.0287

0.0031

0.0137

0.0005

0.0040

0.0000

0.0004

0.0000

0.0004

0.0005

CO2

0.0005

0.0009

0.0004

0.0012

0.0002

0.0015

0.0001

0.0009

0.0000

0.0009

0.0009

Methane

0.3386

0.8705

0.2202

0.8074

0.0710

0.5605

0.0115

0.1615

0.0008

0.1615

0.1704

Ethane

0.0563

0.0607

0.0553

0.1060

0.0424

0.2118

0.0219

0.2399

0.0063

0.2399

0.2517

Propane

0.0440

0.0213

0.0491

0.0416

0.0510

0.1232

0.0422

0.2789

0.0253

0.2789

0.2880

i-butane

0.0121

0.0033

0.0140

0.0062

0.0160

0.0203

0.0155

0.0597

0.0124

0.0597

0.0598

n-butane

0.0342

0.0073

0.0402

0.0133

0.0470

0.0444

0.0474

0.1393

0.0408

0.1393

0.1371

i-pentane

0.0185

0.0022

0.0221

0.0036

0.0269

0.0118

0.0287

0.0407

0.0278

0.0407

0.0368

n-pentane

0.0244

0.0023

0.0293

0.0036

0.0359

0.0120

0.0388

0.0418

0.0385

0.0418

0.0360

Hexane

0.0429

0.0018

0.0520

0.0024

0.0647

0.0075

0.0716

0.0267

0.0748

0.0267

0.0169

o

248 F

0.0996

0.0009

0.1216

0.0010

0.1522

0.0027

0.1704

0.0092

0.1819

0.0092

0.0018

340oF

0.0714

0.0001

0.0873

0.0001

0.1094

0.0003

0.1227

0.0008

0.1313

0.0008

0.0000

413oF

0.0611

0.0000

0.0747

0.0000

0.0937

0.0000

0.1051

0.0001

0.1125

0.0001

0.0000

0.0544

0.0000

0.0665

0.0000

0.0834

0.0000

0.0935

0.0000

0.1002

0.0000

0.0000

o

472 F 657oF Total Mol/Hr

Comp.(Mol Frac.)

0.1342

0.0000

0.1641

0.0000

0.2058

0.0000

0.2308

0.0000

0.2472

0.0000

0.0000

12297.75

2238.98

10058.78

2038.13

8020.67

869.66

7150.98

474.66

6676.31

474.66

449.2

#16

#17

#20

#21

#23

#25

#26

#27

#28

#29

#30

Liq. Out

6th Sep.

Gas Out

Liq. Out

7th Sep.

Gas Out

Liq. Out

Sales

Liquid

Liquid

Sales

6th Sep.

Inlet

6th Sep.

6th Sep.

Inlet

7th Sep.

7th Sep.

Gas

Line

Line

Oil

Nitrogen

0.0000

0.002783 0.000467 0.000169 0.009932

CO2

0.0000

0.001304 0.000935 0.000395

Methane

0.0043

0.42762 0.170392 0.061975

Ethane

0.0318

0.225381 0.251714 0.125021 0.154435 0.154317 0.170367 0.115474 0.130298 0.119176 0.010048

Propane

0.1190

0.179342 0.288001 0.248351

0.00999 0.002135 0.017764 0.000398 0.000354

0.00128 0.001283 0.000854

1.3E-05

0.00111 0.000448 0.000398 2.32E-05

0.69145 0.694509 0.279249 0.767528 0.087314 0.077977 0.003338

0.08717 0.086334 0.199829 0.059332 0.242716

0.22876 0.032016

i-butane

0.0562

0.033794

n-butane

0.1783

0.075951 0.137066 0.218463 0.027843 0.027092

0.12895 0.018863 0.207999 0.204668 0.046189

i-pentane

0.1108

0.020328 0.036754 0.086336 0.005897 0.005605

0.04526 0.004178 0.081536 0.084829 0.029695

0.05984 0.081205 0.013479 0.013199 0.051238 0.009112 0.077701 0.075325 0.014435

n-pentane

0.1438

0.020161

Hexane

0.1995

0.010736 0.016941 0.065133 0.002365 0.002091 0.039283

0.1398

0.002404 0.001848 0.017143 0.000654 0.000456 0.027327 0.000649 0.018329 0.032004 0.176941

o

248 F o

0.03602 0.094344 0.005419 0.005098 0.048676 0.003929 0.089057 0.095217 0.040401 0.00197 0.062111 0.077535 0.074892

340 F

0.0145

0.000174 2.23E-05 0.001297

413oF

0.0020

2.27E-05

0

0

0.001281

472oF

0.0000

0

0

0

0

0

0

657oF

0.0000

0

0

0

0

0

0

0

0

0

0.239094

Total Mol/Hr

25.46

1318.88

449.2

177.33

3179.65

3156.23

23.42

5395.22

200.77

226.22

6902.57

6.6E-05 2.53E-05 0.005551 7.41E-05 0.001793 0.003227

0.000169 9.44E-06

1.3E-05

0.12715

0.000249 0.000442 0.108848

3.71E-06 4.98E-05 8.84E-05 0.096918

Note that water separation and gas dehydration are vital for hydrate prevention, so that even if the system cools into the hydrate pressure-temperature region shown in Figure 7, hydrate formation is prevented due to insufficient water. The export pipeline gas water content is below its water dew point (9 lbm/MMscf) at the lowest temperature (39oF) so free water will not condense from the gas phase. The oil is stabilized by flow through a series of four separators, operating at 1000psig, 300 psig, 55 psig, and 2 psig before the export oil pipeline, so an oil pipeline pressure greater than 15 psia will prevent a gas phase. Hydrate formation is not a significant problem in the oil export pipeline because relatively few hydrate formers (nitrogen, methane, ethane, propane, butanes and CO2) are present and the water content is low. The gas from each separator is compressed, cooled, and separated from liquid again before re-combining the gas with the previous separator’s gas for injection into the export gas line. The additional oil obtained after cooling the compressed gas amounts to about 1.5% of the total oil production. In the process shown, 4310 bhp compressors represent the largest cost on the platform, with capital cost on the order of $800-$1500 (1990 dollars) per installed horsepower. These compressors are powered by fuel gas which operates at a low pressure (about 200 psig), usually fed from the inlet gas passing through a control valve with a substantial pressure reduction. Pressure reductions after the fuel gas takeoff cause cooling, so that point is very susceptible to hydrate formation, particularly in winter months. Also instrument gas lines require similar pressure reductions from a header. Texaco’s Todd et al. (1996. pp. 35-42) observe that when fuel and/or instrument gas lines are blocked due to hydrates, the process frequently shuts down, resulting in pipeline cooling and significant hydrate blockages in the production line at restart. Hydrate limits to pressure reductions through restrictions such as valves and orifices is shown in Section II.F. _____________________________________________________________________ II.B. A One Minute Estimate of Hydrate Formation Conditions (Accurate to ± 50%) Assuming the pipeline pressure drop to be relatively small, the engineer may do a rough estimation to determine whether the pipeline will operate in the hydrate region. As a first approximation, the engineer should first calculate the pressure at which hydrates form at the lowest deep ocean temperature (38-40oF), so that if the pipeline pressure is greater, then inhibition might be considered in the pipeline design

11

and operation. Such an approximation may indicate the need for more accurate calculations to determine the amount of inhibition required. Rules-of-Thumb. In this handbook, Rules-of-Thumb will frequently be stated in bold type. These Rules-of-Thumb are based upon experience, and they are intended as guides for the engineer for further action. For example, using a Rule-of-Thumb the engineer might determine that a more accurate calculation was needed for inhibitor injection amounts, or that further consideration of hydrates was unnecessary. Rulesof-Thumb are not intended to be “Absolute Truths”, and exceptions can always be found. Where possible the accuracy of each Rule-of-Thumb is provided. The first Rule-of-Thumb is given below for hydrate formation at ocean bottom temperatures. Rule of Thumb 1: At 39oF, hydrates will form in a natural gas system if free water is available and the pressure is greater than 166 psig. Hydrate formation data were averaged for 20 natural gases (from Sloan, 1998, Chapter 6) with an average formation pressure of 181 psia. Of the 20 gases, the lowest formation pressure was 100 psig for a gas with 7 mole % C3H8, while the highest value was 300 psig for a gas with 1.8 mole % C3H8. Rule-of-Thumb 1 indicates that most offshore pipeline pressures greatly exceed the hydrate formation condition, indicating: • • •

gas drying and/or inhibition is needed for ocean pipelines with temperatures approaching 39oF, a more accurate estimation procedure should normally be considered, and hydrate formation pressures are dependent upon the gas composition, and are particularly sensitive to the amount of propane present.

It should be reiterated here that hydrates can form at temperatures in excess of 39oF when the pressure is elevated, as in the case of warmer temperatures in shallower water. More accurate estimations of hydrate formation conditions over a broad temperature range are made by the method in the following section. II.C. A Ten-Minute Estimation of Hydrate Formation/Inhibition (Accurate to ± 25%). As a second approximation of hydrate formation the design/facilities engineer should perform two calculations: 1. A pipeline pressure-temperature flow simulation should be done to determine the conditions between the wellhead and the platform separators, (or between the platform and the onshore separators), and

12

2. Hydrate formation conditions such as those shown in Figure 6 should be calculated, determining pressures and temperatures of vapor and aqueous liquid inhibited by various amounts (including 0 wt%) of methanol (MeOH) or monoethylene glycol (MEG). The intersection of the above two lines determines the pressure and temperature at which hydrates will form in a pipeline. As we have seen in Example 2 of Section II.A, it is very likely that a long offshore pipeline will have hydrate formation conditions with free water present. The engineer then needs to specify the amount of inhibitor needed to keep the entire pipeline in the fluid region, without hydrate formation. Step 1 in this calculation, the flow simulation of the pipeline, is beyond the scope of this handbook and should be considered as a separate, pre-requisite problem, perhaps done by the engineering staff at the home office. As an alternative if a pipe flow simulation is not readily available, the engineer may wish to assume that contents of a long offshore pipeline will eventually come to the ocean bottom temperature at the pipeline pressure. Step 2, enabling estimations of hydrate formation pressures and temperatures, is one of the principal goals of this handbook, as discussed in this and in the following section. The below methods (Sections II.C and II.D) may then be used directly to determine the amount of MeOH (methanol) or MEG (monoethylene glycol) needed to prevent hydrate formation at those conditions.

II.C.1. Hydrate Formation Conditions by the Gas Gravity Method. The simplest method to determine the hydrate formation temperature and pressure is via gas gravity, defined as the molecular weight of the gas divided by that of air. In order to use this chart shown in Figure 9, the gas gravity is calculated and the temperature of a point in the pipeline is specified. The pressure at which hydrates will form is read directly from the chart at the gas gravity and temperature of the line. To the left of every line hydrates will form from a gas of that gravity, while for pressures and temperatures to the right of the line, the system will be hydrate-free The following example from the original work by Katz (1945) illustrates chart use. _____________________________________________________________________ Example 4: Calculating Hydrate Formation Conditions Using the Gas Gravity Chart Find the pressure at which a gas composed of 92.67 mol% methane, 5.29% ethane, 1.38% propane, 0.182% i-butane, 0.338% n-butane, and 0.14% pentane form hydrates with free water at a temperature of 50oF.

13

a Fi ur

- H

rat

Formati

(From Katz 19591

43-

2-

3-

4 J,

30.00

I

I

45.00 35.00 40.00 50.00

55.00

I

I

I 6o)oo

Temperature (F)

65.00

70.00

75.00

80.00

Solution: The gas gravity is calculated as 0.603 by the procedure below: Component Mol Fraction Mol Wt Avg Mol Wt in Mix yi MW yi•MW Methane Ethane Propane i-Butane n-Butane Pentane

0.9267 0.0529 0.0138 0.00182 0.00338 0.0014 1.000 Gas Gravity =

16.043 30.070 44.097 58.124 58.124 72.151

14.867 1.591 0.609 0.106 0.196 0.101 17.470

Mol Wt of Gas 17.470 = = 0.603 Mol Wt of Air 28.966

At 50oF , the hydrate pressure is read as 450 psia _____________________________________________________________________

The user is cautioned that this method is only approximate for several reasons. Figure 9 was generated for gases containing only hydrocarbons, and so should be used with caution for those gases with substantial amounts of CO2, H2S, or N2. In addition, the estimated inaccuracies (Sloan, 1985) for the hydrate equilibrium temperature (Teq) and pressure (Peq) are maximized for 0.6 gravity gas as ±7oF or ±500 psig. In the fifty years since the generation of this chart, more hydrate data and prediction methods have caused the gravity method to be used as a first estimate, whose principle asset is ease of calculation. Section II.D provides one of the most accurate methods for calculation of hydrate conditions, but it requires some additional time as well as a computer.

II.C.2. Estimating the Hydrate Inhibitor Needed in the Free Water Phase The above gas gravity chart may be combined with the Hammerschmidt equation to estimate the hydrate depression temperature for several inhibitors in the aqueous liquid: ∆T =

CW M(100 - W)

where: ∆T = C = W = M =

hydrate depression, (Teq - Toper) oF, constant for a particular inhibitor (2,335 for MeOH; 2,000 for MEG) weight per cent of the inhibitor in the liquid, and molecular weight of MeOH (32) or MEG (62).

14

(1)

The Hammerschmidt equation was generated in 1934 and has been used to determine the amount of inhibitor needed to prevent hydrate formation, as indicated in Example 5. The equation was based upon more than 100 natural gas hydrate measurements with inhibitor concentrations of 5 - 25 wt% in water. The accuracy of the Hammerschmidt equation is surprisingly good; tested against 75 data points, the average error in ∆T was 5%. For higher methanol concentrations ( up to 87 wt%) the temperature depression due to methanol can be calculated by a modification of Equation (1) by Nielsen and Bucklin (1983), where xMeOH is mole fraction methanol in aqueous phase ∆T = −129.6 ln(1 − x MeOH )

(1a)

_____________________________________________________________________ Example 5: Methanol Concentration Using the Hammerschmidt Equation. Estimate the methanol concentration needed to provide hydrate inhibition at 450 psia and an ocean floor temperature of 39oF for a gas composed of 92.67 mol% methane, 5.29% ethane, 1.38% propane, 0.182% i-butane, 0.338% n-butane, and 0.14% pentane. Solution: The gas is the same composition and pressure as that in Example 4, with the gas gravity previously determined to be 0.603 and uninhibited hydrate formation conditions of 50oF and 450 psia. Inhibition is required since the pipeline operates at 39oF and 450 psia, well within the hydrate formation region. The weight percent of inhibitor needed in water phase is determined via the Hammerschmidt Equation (1), with the values: ∆T = Temperature Depression (50oF - 39oF= 11oF), M = Molecular Weight for Methanol (= 32) C = Constant for Methanol (= 2335) W = Weight Percent Inhibitor Rearranging in Equation (1) W =

100 M ∆T 100 × 32 × 11 = = 131 . M ∆T + C 32 × 11 + 2335

The methanol in the water phase is predicted as 13.1 wt % to provide hydrate inhibition at 450 psia and 39oF for this gas. The engineer may wish to provide an operational safety factor by the addition of more methanol. _____________________________________________________________________

15

II.C.3. Amount of Inhibitor Injected Into Pipeline. While the Hammerschmidt equation enables estimation of the wt% MeOH (or MEG) needed in the free water phase, three other quantities are necessary to estimate the amount of inhibitor injected into the pipeline: 1. the amount of the free water phase, 2. the amount of inhibitor lost to the gas phase, and 3. the amount of inhibitor lost to the condensate phase. The amount of the free water phase is multiplied by the wt% inhibitor from the Hammerschmidt equation, just as the inhibitor concentrations in the gas and condensate are multiplied by the flows of the vapor and condensate. Because hydrate inhibition occurs in the water phase, inhibitor concentrations in the gas and condensate phases are usually counted as economic losses. Methanol recovery is done only rarely on platforms and is typically too expensive at onshore locations. II.C.3.a Amount of Water Phase The water phase has two sources: (a) produced water and (b) water condensed from the hydrocarbon phases. The amount of produced water can only be determined by data from the well, with an increasing amount of water production over the well’s lifetime. Water condensed from the hydrocarbon phases may be calculated. The water content of condensates is usually negligible, but water condensed from gases can be substantial. The amount of water condensed is the difference in the inlet and outlet gas water contents, multiplied by the gas flow rate. Rule-of-Thumb 2: For long pipelines approaching the ocean bottom o temperature of 39 F, the lowest water content of the outlet gas is given by the below table: Pipe Pressure, psia 500 1000 1500 2000 Water Content, lbm/MMscf 15.0 9.0 7.0 5.5

An inlet gas water content analysis is used, if available. Then the water content of the outlet gas (Rule-of-Thumb 2) may be subtracted from the inlet gas to determine the water condensed per MMscf of gas. When an inlet gas water content is not available a water content chart such as Figure 10 may be used to obtain the water content of both the inlet and outlet gas from the pipeline. In Figure 10 the temperature of the pipeline inlet or outlet is found on the xaxis and water content is read on the y-axis at the pipeline pressure, marked on each line in Figure 10. The engineer is cautioned not to use the water content chart at temperatures significantly below 38oF. At lower temperatures the actual water content deviates from the line due to hydrate formation. An illustration of condensed water calculation using Figure 8 is given in Example 6 (Section II.C.4).

16

Figure 10 - Water Formation Curve (From McKetta

and Wehe, 1958)

II.C.3.b Amount of Inhibitor Lost to the Gas Phase. The Hammerschmidt equation only provides the amount of methanol needed in the free water phase at the point of hydrate inhibition, while two other phases represent potential losses of methanol. The amount of MeOH or MEG loss into the gas phase should also be considered using the following Rules-of-Thumb. Rule-of-Thumb 3: At 39oF and pressures greater than 1000 psia, the maximum amount of methanol lost to the vapor phase is 1 lbm MeOH/MMscf for every weight % MeOH in the free water phase. Rule-of-Thumb 4: At 39oF and pressures greater than 1000 psia, the maximum amount of MEG lost to the gas is 0.002 lbm/MMscf. The methanol loss chart in Figure 11 shows that at typical offshore pipeline conditions, the amount of methanol in the vapor may be 0.1 mole% of that in the water phase. Rule-of-Thumb 3 is valid except for low water amounts, when the methanol vapor loss can be substantially higher and the method of Section II.D.3 should be used. Figure 12 validates Rule-of-Thumb 4 for MEG. Note that the data for Figures 11 and 9 were obtained in 1985 for the mole fraction ratio of inhibitor in the vapor over the aqueous phase; the water phase wt% inhibitor must be converted to mole % in order to use either chart. Example 6 in Section II.C.4 illustrates methanol loss to the gas phase. II.C.3.c Amount of Inhibitor Lost to the Liquid Phase. Two general Rules-ofThumb can be applied to inhibitor losses in the condensate. Rule-of-Thumb 5: Methanol concentration dissolved in condensate is 0.5 wt %. Rule-of-Thumb 6: The mole fraction of MEG in a liquid hydrocarbon at 39oF and pressures greater than 1000 psia is 0.03% of the water phase mole fraction of MEG. Even with low losses of MEG relative to MeOH in both the gas and the liquid, it is important to remember that methanol is a much more effective inhibitor than ethylene glycol on a weight basis. The predominance of methanol’s use is due to this effectiveness, together with the fact that methanol easily flows to the point of hydrate formation. II.C.4. Example Calculation of Amount Methanol Injection. The below sample calculation uses all of the concepts presented in Section II.C. _____________________________________________________________________ Example 6: Methanol Injection Rate. A sub-sea pipeline with the below gas composition has inlet pipeline conditions of 195oF and 1050 psia. The gas flowing

17

Figure 11 - Methanol Lost to Vapor (From Sloan, 1998)

Temperature,OF 20

30

I t I I I III

%

40 I,

I I,

50

60

I I I I I I,

70

1 III

I,,

80

1 I,

90 I,,

isobaric Vapor Phase Distribution for Methanol in Hydrate-Foxming Systems

1

5 Ls

,z

InK,, = a + b[l/T(R)]

-

-3, ,I,6s

0

III

Z.lOE-3

a

b

0 0

1000psia 8.41233

-7250.20

2000 psia

6.82227

-6432.23

0

3000 psia 5.70578

-5738.48

1111,,,,,,,,,,,,,,,,,,,,,,,,,,r ZOOE-3

1.9oE3 lfw)

l.mE-3

100 III,

Fimre 12 - Mono-Ethylene Glvcol Lost to Vapor (From Townsend and Reid, 1972)

xx)100

=

60 = 4020IO = 6= 42I

=‘

0.6 a4

= r

QOI ’

I

-40

/I

I 0

1

I

-20 20 40 EOlJlLlBRlUM TEMPERATURE,

I

1

60

Bo

OF

through the pipeline is cooled by the surrounding water to a temperature of 38oF. The gas also experiences a pressure drop to 950 psia. Gas exits the pipeline at a rate of 3.2 MMscf/d. The pipeline produces condensate at a rate of 25 bbl/day, with an average density of 300 lbm/bbl and an average molecular weight of 90 lbm/lbmole. Produced free water enters the pipeline at a rate of 0.25 bbl/day. Natural gas composition (mole %): methane = 71.60%, ethane = 4.73%, propane =1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen = 5.96%. Find the rate of methanol injection needed to prevent hydrates in the pipeline. Solution: Basis: The basis for these calculations was chosen as 1 MMscf/d. Step 1) Calculate Hydrate Formation Conditions using the Gas Gravity Chart Component

Mol Fraction yi

Mol Wt MW

Methane Ethane Propane n-Butane n-Pentane Nitrogen Carbon Dioxide

0.7160 0.0473 0.0194 0.0079 0.0079 0.0596 0.1419 1.000

16.04 30.07 44.09 58.12 72.15 28.01 44.01

Gas Gravity =

Avg Mol Wt in Mixture yi•MW 11.487 1.422 0.855 0.459 0.570 1.670 6.245 22.708

mol wt gas 22.708 = = 0.784 mol wt air 28.966

Reading the gas gravity chart (Figure 9), the hydrate temperature is 65oF at 1000 psia. Step 2) Calculate the Wt% MeOH Needed in the Free Water Phase The Hammerschmidt Equation is:

∆T =

CW 100M - MW

Where:∆T = Temperature Depression (65oF - 38oF= 27oF), M = Molecular Weight for Methanol (= 32.0) C = Constant for Methanol (= 2335) W = Weight Percent Inhibitor

18

Rearranging the Hammerschmidt equation W =

100 M ∆T 100 × 32 × 27 = = 27 M ∆T + C 32 × 27 + 2335

The weight percent of methanol needed in freewater phase is 27.0% to provide hydrate inhibition at 1000 psia and 38oF for this gas. Step 3) Calculate the Mass of Liquid H2O/MMscf of Natural Gas - Calculate Mass of Condensed H2O In the absence of a water analysis, use the water content chart (Figure 10), to calculate the water in the vapor/MMscf. The inlet gas (at 1050 psia and 195oF) water content is read as 600 lbm/MMscf. Rule of Thumb 2 states that exiting gas at 1000 psia and 39oF contains 9 lbm/MMscf of water in the gas. The mass of liquid water due to condensation is: 600 lbm _ 9 lbm = 591 lbm MMscf MMscf MMscf

- Calculate Mass of Produced H2O Flowing into the Line Convert the produced water of 0.25 bbl/day to a basis of lbm/MMscf:  0.25bblH 2 O  42 gal  8.34lbm    day   bbl  gal

 1day   3.2 MMscf

lb H O   = 27.4 m 2 MMscf 

- Total Mass of Water/MMscf Gas: Sum the condensed and produced water 591 lbm + 27.4 lbm = 618.4 lbm MMscf MMscf MMscf Step 4) Calculate the Rate of Methanol Injection Methanol will exist in three phases: water, gas, and condensate. The total mass of methanol injected into the gas is calculated as follows: -Calculate Mass of MeOH in the Water Phase 27.0 wt% methanol is required to inhibit the free water phase, and the mass of water/MMscf was calculated at 618.4 lbm. The mass of MeOH in the free water phase per MMscf is: 27wt% =

M lbm MeOH × 100% M lb m MeOH + 618.4lbm H 2 O

19

Solving M = 228.7 lbm MeOH in the water phase -Calculate Mass of MeOH Lost to the Gas Rule of Thumb 3 states that the maximum amount of methanol lost to the vapor phase is 1 lbm MeOH/MMscf for every wt% MeOH in the water phase. Since there is 27 wt% MeOH in the water, that maximum amount of MeOH lost to the gas is 27 lbm/MMscf.

-Calculate the Mass of MeOH Lost to the Condensate Rule of Thumb #5 states that the methanol concentration in the condensate will be 0.5wt%. Since a barrel of hydrocarbon weighs about 300 lbm, the amount of methanol in the condensate will be 0.005 × 300 lbm/bbl × 25bbl/d × 1d/3.2 MMscf = 11.7 lbm/MMscf

-Calculate the Total Amount of MeOH/MMscf MeOH in Water = 228.7 lbm/MMscf MeOH in Gas = 27 lbm/MMscf MeOH in Condensate = 11.7 lbm/MMscf Total MeOH Injection

= 267.4 lbm/MMscf (or 40.33 gal/MMscf at a MeOH density of 6.63 lbm/gal) _____________________________________________________________________ In the above example, the amount of methanol lost to the gas and condensate is approximately 11% of the total amount injected. However, with large amounts of condensate it is not uncommon to have as much as 90% of the injected methanol dissolved in the condensate (primarily) and gas phases. In such cases, the Rules-ofThumb should be replaced by a more accurate calculation, as shown in section II.D. The hand calculation example is provided for understanding of the second approximation. The method is made much more convenient for the engineer via the use of the below spreadsheet program.

II.C.5. Computer Program for Second Approximation. Shuler (1997) of Chevron provided a computerized version (HYDCALC) of the above calculation method, which is included with the disk in this handbook. Slightly different Rules-ofThumb have been used, but these differences are insignificant, as shown by a comparison in Section II.C.6 of results of the hand calculation (Example 6) with the computer method (Example 7).

20

HYDCALC is an IBM-PC compatible spreadsheet that provides an initial estimate of pipeline methanol injection for hydrate inhibition. To use HYDCALC, obtain access to a Microsoft Excel® - Version 7.0 spreadsheet program and copy HYDCALC into a hard drive directory. Start Excel® - Version 7.0 and open the file HYDCALC. Once the file is opened, the user will see text in three different colors on a color screen- black, red, and blue. The red text signifies required User Inputs, composed of the following eight pieces of information to start the program: 1) 2) 3) 4) 5) 6) 7) 8)

Pipeline Inlet Pressure - Starting high pressure Cold Pipeline Pressure - Pressure at the coldest part of the pipeline. Pipeline Inlet Temperature - Starting warm temperature. Cold Pipeline Temperature - Temperature at the coldest part of the pipeline. Gas Gravity - Gas gravity, calculated by the steps in Section II.C.1 and Example 4. Gas Flow Rate - Gas flow in the pipeline measured in MMscf/d. Condensate Rate - Condensate flow in the pipeline measured in bbl/d. Formation Water Rate - Produced water flowing into the pipeline (bbl/d).

Once the above values are input, HYDCALC displays calculations for both Intermediate Results (in black) and the amount of methanol or glycol to be injected (in blue on a color screen). In the below example, the User Input and Calculations are both listed in black, due to printing restrictions. A prescription for the use of this method is shown in Example 7.

_____________________________________________________________________ Example 7. Use of HYDCALC to Find Amount of Methanol and Glycol Injection This spreadsheet problem is the identical problem worked in Example 6 by hand. A sub-sea pipeline with the a gas gravity of 0.784 has inlet pipeline conditions of 195oF and 1050 psia. The gas flowing through the pipeline is cooled by the surrounding water to a temperature of 38oF. The gas also experiences a pressure drop to 950 psia. Gas exits the pipeline at a rate of 3.2 MMscf/d. The pipeline produces condensate at a rate of 25 bbl/d, with an average density of 300 lbm/bbl and an average molecular weight of 90 lbm/lbmole. Produced free water enters the pipeline at a rate of 0.25 bbl/d. Determine the rate of methanol and glycol injection needed to prevent hydrate formation in the pipeline. Solution: Figure 13 on the next page is a copy of HYDCALC, highlighting the data input that is needed to run the program. All required data are provided in the example, with

21

Figure 13 - Example #6 Calculated by HYDCALC a:\excel7\hydcalV7.xls

disk 2

P.J. Shuler CTN 694-7572, PJSH

HYDCALC Version 2

CPTC

5/27/97

for Excel 7.0

INHIBITOR REQUIREMENT CALCULATION

Inputs

FOR A WET GAS FLOWLINE USER INPUTS (in red) Bottom Hole Pressure Cold Line Pressure Bottom Hole Temperature Cold Temperature Gas gravity Gas Rate Condensate Rate

1050 950 195 38 0.784 3.2 25

psia psia F F

Formation Water Rate ?? Calculated Condensed Water Total Water to Treat

0.25 5.7 5.9

bbl/ H2O/day bbl/ H2O/day bbl/ H2O/day

MMSCFD bbl/day

CALCULATION WORKSHEET Water in hot gas Water in cold gas WATER CONDENSED

626.2 6.5 619.8

lb/MMSCF lb/MMSCF lb/MMSCF

Total Water CONDENSED in the line Total water (from above)

1983 5.7 5.9

lb/day bbl H2O/day bbl H2O/day

Hydrate temperature of gas

65.0

F

Freeze depression required

27.0

F

Wt. percent methanol needed in water phase

27.0

%

wt. percent MEG needed in water phase

45.6

%

Vapor to liquid composition ratio

0.9162 lb/MMSCFper % in water

Methanol in gas MEG in gas

24.77 0

lb/MMSCF lb/MMSCF

Methanol into condensate MEG into condensate

37.5 22.5

lb/day lb/day

Methanol to protect water phase MEG to protect water phase

767

lb/day

1735

lb/day

767

lb/day

79 37.5 884

lb/day lb/day lb/day

134.9

gal/day

42.2

gal/MMSCF

TOTALS Methanol to protect water phase Methanol going to gas Methanol into condensate TOTAL Methanol Rate Methanol Injection Rate (pure MeOH @ 77F) Methanol Rate/MMSCF

.===> starting high pressure .===> pressure where hydrates .===> starting high temperature .===> temperature where hydrates

SUMMARY OF RESULTS Methanol Injection Rate (pure MeOH @ 77F) Methanol Rate/MMSCF

134.9

gal/day

42.2

gal/MMSCF

MEG Injection Rate (pure MEG) MEG Rate/MMSCF

190.0

gal/day

59.4

gal/MMSCF

Summary of Results

MEG to protect water phase MEG in gas MEG into condensate TOTAL MEG Rate

1735

lb/day

0 22.5 1758

lb/MMSCF lb/day lb/day

MEG Injection Rate (pure MEG) MEG Rate/MMSCF

190.0

gal/day

59.4

gal/MMSCF

the exception of gas gravity. Gas gravity was calculated using the method described in Example 4 to be 0.784. Figure 13 on the next page displays all input data and results. The amount of methanol injected is 42.2 gal/MMscf and the amount of glycol injected is 59.4 gal/MMscf. _____________________________________________________________________ For ease of use, the engineer will turn to HYDCALC to perform the second approximation calculation. The following section provides accuracy and limitations of both HYDCALC and the hand calculation methods, which are vital to their use.

II.C.6. Accuracy, Limitations, and Extensions for Second Estimation Method A comparison of the previous results using the hand calculation method and the HYDCALC method is included in the below table. Calculated Quantity

Hand Method Result with Rules-of-Thumb

Water Condensed, lbm/MMscf MeOH in Water, lbm/MMscf MeOH in Gas, lbm/MMscf MeOH in Condensate, lbm/MMscf Total MeOH Injection, lbm/MMscf Total MeOH Injection, gal/MMscf

591 228.7 27 11.7 267.4 40.3

HYDCALC Result 619.8 239.7 24.7 11.7 276.25 42.2

While the hand calculation and the computer program provide only slightly different results, both include inaccuracies. For example, while it is possible to obtain more significant figures with HYDCALC than with the charts in the hand method, HYDCALC inaccuracies are those of the charts upon which HYDCALC is based. Using HYDCALC it was estimated that 27 wt% methanol was required in the water phase to inhibit the pipeline, while measurements by Robinson and Ng (1986) show that only 20 wt% methanol was required for inhibition at the same gas composition, temperature, and pressure of Examples 6 and 7. The major inaccuracies in the second estimation method are in the gas gravity hydrate formation conditions, which are only accurate to ±7oF or to ±500 psia. The Hammerschmidt equation, the inhibitor temperature depression ∆T is accurate to ± 5%. With such inaccuracies, the amount of methanol or glycol injection could be in error by 100% or more. The principal virtue of the second estimation method is ease of calculation rather than accuracy.

22

A second limitation is that the method was generated for gases without H2S, which represents the case for many gases in the Gulf of Mexico. A modification of the gas gravity method was proposed for sour gases by Baillie and Wichert (1987).

II.D. Most Accurate Calculation of Hydrate Formation and Inhibition. If the HYDCALC results indicate that hydrate formation will occur without inhibition, the engineer should elect to do further, more accurate calculations. The most accurate method for hydrate formation conditions, together with the amount of methanol needed in the water phase, is available as the final estimation technique in a computer program, HYDOFF. A User’s Manual (Appendix B) and an example are provided with this handbook. The method details are too lengthy to include here; the engineer interested in program details is referred to the hydrate text by Sloan (1998, Chapter 5). In Section II.D examples are provided for the most accurate methods for the following calculations: • • • •

calculation of hydrate formation and inhibition in water (Section II.D.1), conversion of MeOH to MEG concentration in water phase (Section II.D.2), calculation of solubility of MeOH and MEG in the gas (Section II.D.3), and calculation of solubility of MeOH and MEG in condensate (Section II.D.4).

II.D.1. Hydrate Formation and Inhibitor Amounts in Water Phase. HYDOFF is an IBM-compatible computer program provided on the disk with this handbook. The program enables the user to determine hydrate formation conditions and the amount of inhibitor needed in the free water phase. As a minimum of a 386-IBM computer with 2 megabytes of RAM is required. The program may be executed either from the Windows or from the DOS environment. To use the program, first load both HYDOFF.EXE and FEED.DAT from the accompanying 3.5 inch disk onto a hard drive. Appendix B is a User’s Manual with several examples of the use of HYDOFF. The simplest (and perhaps the most beneficial) use of HYDOFF is illustrated through Example 8.

_____________________________________________________________________ Example 8: Use of HYDOFF to Obtain Hydrate Formation and Prevention Conditions. Find (a) the hydrate formation pressure of the below natural gas at 38oF and (b) the amount of methanol in the water phase to inhibit hydrates at 38oF and 1000 psia. The

23

gas composition (mole %) is: methane = 71.60%, ethane = 4.73%, propane = 1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen = 5.96% Solution: The gas in this example has the same composition as the gas in Examples 6 and 7, so the results provide a comparison with hand and computer calculations of the gas gravity method (Section II.C.1) and the Hammerschmidt equation (Section II.C.2). For convenience with multiple calculations, the reader may wish to edit the program FEED.DAT to reflect the gas composition of the problem. Modification of the FEED.DAT program is done at the MSDOS prompt, by changing the composition of each component to that of the example gas, and saving the result using the standard MSDOS editing technique. However it is not necessary to use FEED.DAT; the gas composition may be input as part of the program HYDOFF. In the following solution, each input from the user is underlined: 1. From Windows or in the proper directory, click on, or type HYDOFF; press Enter. 2. After reading the title screen, press Enter 3. At the “Units” screen, press 1 (to choose oF and psia) then Enter 4. At the FEED.DAT question screen, press 2 and Enter if you wish to use the data in FEED.DAT, or 1 and Enter if you wish to enter the gas composition in HYDOFF by hand. The remainder of this example is written assuming that the user will enter the gas composition in HYDOFF rather than use FEED.DAT. The use of FEED.DAT is simpler and should be considered for multiple calculations with the same gas. 5. The next screen asks for the number of components present (excluding water). Input 7 and Enter. 6. The next screen requests a list of the gas components present, coded by numbers shown on the screen. Input 1, 2, 3, 5, 7, 8, and 9 (in that order, separating the entries by commas) and then Enter. 7. The next series of screens request the input of the mole fractions of each component Methane 0.7160 Enter. Ethane 0.0473 Enter. Propane 0.0194 Enter. n-Butane 0.0079 Enter. Nitrogen 0.0596 Enter. Carbon Dioxide 0.1419 Enter. n-Pentane 0.0079 Enter. 8. At the “Options” screen, input 1 then Enter. 9. At the screen asking for the required Temperature, input 38, and Enter. 10. Read the hydrate formation pressure of 229.7 psia, (meaning hydrates will form at any pressure above 230 psia at 38oF for this gas.) 11. When asked for another calculation input 1 for “No” then Enter. 12. At the “Options” screen input 2, then Enter.

24

13. At the screen asking for the required temperature, input 38, and Enter. 14. At the screen to enter the “WEIGHT PERCENT of Methanol,” input 22. 15. Read the resulting hydrate condition of 22 wt% MeOH, 38oF, and 1036 psia. It may require some trial and error with the use of the program before the correct amount of MeOH is input to inhibit the system at the temperature and pressure of the example. One starting place for the trial and error process would be the amount of MeOH predicted by the Hammerschmidt equation (27 wt%) in Example 6. Ng and Robinson (1983) measured 20 wt% of methanol in the water required to inhibit hydrates at 38oF and 1000 psia. A comparison of the measured value with the calculated value (22 wt%) in this example and through the Hammerschmidt equation provides an indication of both the absolute and relative calculation accuracy. HYDOFF can also be used to predict the uninhibited hydrate formation temperature at 1000 psia at 58.5oF, through a similar trial and error process, as compared with 65oF determined by the gas gravity method. No measurements are available for the uninhibited formation conditions of the gas in this example. In using HYDOFF, if components heavier than n-decane (C10H22) are present, they should be lumped with n-decane, since they are all non-hydrate formers. _____________________________________________________________________

II.D.2 Conversion of MeOH to MEG Concentration in Water Phase. The concentration of inhibiting monoethylene glycol (MEG) in the water phase can be determined from methanol (MeOH) concentration using a simple correlation of inhibitors: wt% MEG = -1.209+ 2.34 (wt% MeOH)- 0.052(wt% MeOH) 2+ 0.0008(wt% MeOH) 3

(2)

In order to use Equation (2), first determine the amount of methanol required using HYDOFF, as in Example 8. Insert the amount of methanol in Equation (2) to determine the amount of mono-ethylene glycol needed in water to inhibit hydrates. Equation (2) should be used for the free water phase only. Example 9 (Section II.D.5) provides a summary calculation of all the procedures in Section II.D.

II.D.3. Solubility of MeOH and MEG in the Gas. Figure 11 is a fit of recent measurements by Ng and Chen (1995) for KvMeOH defined as the methanol mole fraction in gas relative to water (≡ yMeOH/xMeOH in H2O). Once the mole fraction of methanol in water is determined, it may be multiplied by KvMeOH to obtain the mole fraction of methanol in the gas. As can be determined by Figure 11, the solubility in the water is only slightly affected by pressure over the range from 1000-3000 psia at offshore temperatures. For a conservative estimate the 3000 psia line is recommended:

25

KvMeOH = exp (5.706 - 5738×(1/T(oR))

(3)

Figure 12 provides an estimation of monoethylene glycol dissolved in gas at 1000 psig, from the data of Polderman (1958). As indicated in the figure the amount of MEG in the vapor is very small; Ng and Chen (1995) measure a negligible MEG concentration in the vapor as a comparison. Example 9 (Section II.D.5) provides a summary calculation of all the procedures in Section II.D.

II.D.4. Solubility of MeOH and MEG in the Condensate. Figure 14 is a fit of measurements by Ng and Chen (1995) for KLMeOH defined as the methanol mole fraction in condensate relative to water (≡ xMeOH in HC/xMeOH in H2O). Once the mole fraction of methanol in water is determined, it may be multiplied by KLMeOH to obtain the mole fraction of methanol in the condensate. In Figure 14 all lines are pressure independent and the toluene line should not apply, due to the absence of such compounds in typical condensates. The fit for the solubility of methanol in condensates of methane, propane, and n-heptane is recommended: KLMeOH = exp (5.90 - 5404.5×(1/T(oR))

(4)

Similar measurements by Ng and Chen (1995) are shown in Figure 15 to specify the solubility for monoethylene glycol (MEG) in the condensate, via KLMEG defined as the MEG mole fraction in condensate relative to water (≡ xMEG in HC/xMEG in L L H2O). Note that the K MEG values are two orders of magnitude lower than K MeOH values. No pressure dependence is observed, and the line for MEG solubility in methane, propane, and n-heptane (or methylcyclohexane) is recommended, since toluene is not in condensate: KLMEG = exp (4.20 - 7266.4×(1/T(oR))

(5)

Example 9 (Section II.D.5) provides a summary calculation of all the procedures in Section II.D.

II.D.5. Best Calculation Technique for MeOH or MEG Injection. The following example is identical that of Examples 6 and 7, with the exception that both MeOH and MEG injection are calculated for comparison of each inhibitor as well as with the less accurate method of Section II.C.

_____________________________________________________________________ Example 9: Most Accurate Inhibitor Injection Calculation. A sub-sea pipeline with the below gas composition has inlet pipeline conditions of 195oF and 1050 psia. The

26

Figure 14 - Methanol Lost to Condensate (From Sloan, 1998)

Temperature (OF) 20

30

40

50

60

70

80

90

100

1o-~_I’1’~““““““““‘~“““““~“““‘~

115

0

s-l 7-

h

zi

g

634-

5

‘-

‘-

i

3 10‘2u

‘,-

5 :_ ti ‘I-

.-

blK mc= a + b[l/T(R)]

3-

a 3-

2.1E-3

- b

0

Methane+ Propane+ n-Hcptane

5.90062 -5404.45

[7

Metime + Propane+ htiylcyclohexane

5.91795 -5389.73

0

Methane+ Propane+ Tolueoe

3.55142 -3242.43

2.OE-3

1.9E-3

l/T(R)

1.8E-3

130

Figure 15 - Mono-Ethvlene Glvcol Lost to Condensate (Fmm Sloan, 1998)

Temperature, OF 40

50

60

70

80

90

112

100

J!“““““,~“““““”

a + b[l/T(Fi)]

InK,=

I ” z.ooE-3

Mdlmw+Pmpm+ll-~

f3

I’btbw+~+~~e

4A9818

-726638

0

-+Rupm+Tol\rar

2.65872

-5211.86

I ” 1.9SE-3

“I””

I “‘I

MOE-3 l/T(R)

Las-3

-

b

0

”

-

a

I ” 1.SOE-3

” 1.7s3

gas flowing through the pipeline is cooled by the surrounding water to a temperature of 38oF. The gas also experiences a pressure drop to 950 psia. Gas exits the pipeline at a rate of 3.2 MMscf/d. The pipeline produces condensate at a rate of 25 bbl/d, with an average density of 300 lbm/bbl and an average molecular weight of 90 lbm/lbmole. Produced salt-free water enters the pipeline at a rate of 0.25 bbl/d. Natural gas composition (mole%): methane = 71.60%, ethane = 4.73%, propane = 1.94%, n-butane = 0.79%, n-pentane = 0.79%, carbon dioxide = 14.19%, nitrogen = 5.96% Find the rate of both methanol and monoethylene glycol injection needed to prevent hydrate formation in the pipeline.

Solution: Basis: the basis for solution is 1 MMscf/d. Step 1) Calculate the Concentration of MeOH and MEG in the Water Phase. In Example 8 the methanol concentration was calculated to be 22 wt% of the free water phase at 38oF and 1000 psia. Using Equation (2) the MEG concentration was calculated at 33.6 wt% in the water phase. Step 2) Calculate the Mass of Liquid H2O/MMscf of Natural Gas - Calculate Mass of Condensed H2O Use the water content chart (Figure 10), to calculate the water in the vapor/MMscf. The inlet gas (at 1050 psia and 195oF) water content is read as 600 lbm/MMscf. The outlet gas (at 950 psia and 38oF) water content is read as 9 lbm/MMscf. The mass of liquid water due to condensation is: 600 lbm _ 9 lbm = 591 lbm MMscf MMscf MMscf - Calculate Mass of Produced H2O Flowing into the Line Convert the produced water of 0.25 bbl/d to the basis of lbm/MMscf:  0.25bblH 2 O  42 gal  8.34lbm    day   bbl  gal

 1day   3.2MMscf

 lb H O  = 27.4 m 2 MMscf 

- Total Mass of Water/MMscf Gas: Sum the condensed and produced water 591 lbm + 27.4 lbm = 618.4 lbm MMscf MMscf MMscf 27

Step 4) Calculate the Rate of Methanol and MEG Injection MeOH and MEG can exist in three phases: water, gas, and condensate. The total masses of MeOH and MEG injected per MMscf are calculated as follows: -Calculate Amount of (a) MeOH and (b) MEG in the Water Phase (a) 22.0 wt% methanol is required to inhibit the free water phase, and the mass of water/MMscf was calculated at 618.4 lbm. The mass of MeOH in the free water phase per MMscf is: 22wt% =

M lb m MeOH × 100% M lb m MeOH + 618.4lb m H 2 O

Solving M = 174.4 lbm MeOH/MMscf in the water phase (b) In Step 1 33.6.0 wt% MEG is required to inhibit the free water phase, and the mass of water/MMscf was calculated at 618.4 lbm in Step 3. The mass of MEG in the free water phase per MMscf is: 33.6wt% =

N lb m MEG ×100% N lb m MEG + 618.4lb m H 2 O

Solving N = 313.1 lbm MEG/MMscf in the water phase -Calculate Amount of (a) MeOH and (b) MEG Lost to the Gas (a) MeOH Lost to Gas. The mole fraction MeOH in the free water phase is: mole fraction MeOH =

174.4 lb m MeOH / (32lb m / lbmol MeOH) 174.4 / 32 + 618.4lb m H 2 O / (18lb m / lbmolH 2 O)

The mole fraction MeOH in the water phase is xMeOH in H2O = 0.137. The distribution constant of MeOH in the gas is calculated at 38oF (497.7oR) by Equation (3), relative to the methanol in the water KvMeOH = exp (5.706 - 5738×(1/497.7oR) = 0.00296 (3) o o where R = F + 459.69 The mole fraction of MeOH in the vapor is yMeOH = KvMeOH•xMeOH in H2O or yMeOH = 0.00296 × 0.137 = 0.0004055 The daily gas rate is 8432 lbmol (= 3.2 × 106 scf / (379.5 scf/lbmol), where an scf is at 14.7 psia and 60oF), so that the MeOH lost to the gas is 3.42 lbmol (=

28

0.0004055 × 8432) or 109.4 lbm/day. Since the calculation basis is 1 MMscf/d, the amount of MeOH lost is 34.2 lbm/MMscf (= 109.4 lbm / 3.2 MMscf). (b) MEG Lost to Gas. In Figure 12 use the 50 wt% MEG line to determine the MEG lost to the gas is 0.006 lbm/MMscf at 38oF and 1000 psig; such an amount is negligible. Ng and Chen (1995) measured a negligible concentration of MEG in the gas phase at conditions similar to those of this problem.

-Calculate Amount of (a) MeOH and (b) MEG Lost to the Condensate (a) MeOH lost to the condensate. The distribution of MeOH in the condensate is calculated via equation (4) KLMeOH = exp (5.90 - 5404.5×(1/497.7oR)) = 0.00702

(4)

where oR = oF + 459.69. The mole fraction MeOH in condensate is xMeOH in HC = KLMeOH×xMeOH in H2O or xMeOH in HC = 0.00702 × 0.137 = 0.0009617 The condensate rate is 26.0 lbmoles/MMscf (= 25bbl/d×300 lbm/bbl×1 lbmol/90 lbm×1d/3.2 MMscf) so that the amount of MeOH in condensate is 0.025 lbmol/MMscf (= 0.0009617 × 26 / ( 1 - 0.009617)) or 0.8 lbm/MMscf) (b) MEG Lost to Condensate. The mole fraction MEG in the water phase is calculated as mole fraction MEG =

313.1 lb m MEG / (62lb m / lbmol MEG) 313.1/ 62 + 618.4lb m H 2 O / (18lb m / lbmolH 2 O)

The mole fraction MEG in the water phase is xMEG in H2O = 0.128. The distribution of MEG between the aqueous liquid and condensate is given by KLMEG = exp (4.20 - 7266.4×(1/497.7 oR)) = 3.04 × 10-5

(5)

The mole fraction MEG in condensate is xMEG in HC = KLMEG×xMEG in H2O calculated as 3.8 × 10-6.(= 3.04 × 10-5 × 0.128). The condensate rate is 26.0 lbmoles/MMscf (= 25bbl/d×300 lbm/bbl×1 lbmol/90 lbm×1d/3.2 MMscf) so that the amount of MEG in condensate is 9.9×10-5 lbmol/MMscf (= 0.0000038 × 26 / ( 1 - 0.0000038)) or 0.0061 lbm/MMscf) -Calculate the Total Amount of MeOH/MMscf and MEG/MMscf

29

In Water, lbm/MMscf In Gas, lbm/MMscf In Condensate, lbm/MMscf Total, lbm/MMscf Total, gal/MMscf

MeOH

MEG

174.4 34.2 0.8 209.4 31.5

313.1 0.006 0.0061 313.11 33.3

The example illustrates that for this gas condition, the injection amounts of MeOH and MEG are comparable. The more precise calculation shown here however, represents a considerable savings in the amount of MeOH injected (31.5 gal/MMscf versus 42.2 gal/MMscf in the second estimation method.) _____________________________________________________________________

II.E. Case Study 6: Prevention of Hydrates in Dog Lake Field Pipeline As a summary of the thermodynamic hydrate prevention methods, consider the steps taken to prohibit hydrates in the Dog Lake Field export pipeline in Louisiana, by Todd et al., (1996) of Texaco. During the winter months hydrates formed in the line. While this pipeline passes through shallow water (a marsh) many of the principles illustrate applications to offshore pipeline design. Hydrate formation conditions, shown in Figure 16, are calculated via an earlier version of HYDOFF with 0 wt%, 10%, and 20% methanol in the water phase. The Dog Lake gas composition is: 92.1 mole% methane, 3.68% ethane, 1.732% propane, 0.452% i-butane, 0.452% n-butane, 0.177% i-pentane, 0.114% n-pentane, 0.112% hexane, 0.051% heptane, 0.029% octane, 0.517% nitrogen, 0.574% carbon dioxide. The pipeline pressure and temperature, calculated using PIPEPHASE , were superimposed on the hydrate formation curve shown in Figure 17. Gas leaves the wellhead at 1000 psia and 85oF, far from hydrate forming conditions. As the gas moves down the pipeline, it begins to cool towards ambient temperatures. Once the temperature reaches approximately 63oF hydrates will form, so methanol must be added. The figure shows pipeline conditions and the hydrate formation curves for various concentrations of methanol, indicating that 25% wt% methanol in water is needed to inhibit hydrates. Despite large quantities of methanol injection for hydrate prevention, 110 hydrate incidents occurred in the line during winter of 1995-1996 at a cost of $323,732. Combinations of four alternative hydrate prevention methods were considered: (1) burying the pipeline, (2) heating the gas at the wellhead, (3) insulating the pipeline, and (4) methanol addition. The details of each prevention measure are considered below.

30

Figure 16 - Dog Lake Field - Hydrate Curves (From Todd, 1997) 4000

10 wt% MeOH

20 wt% MeOH

3500

Pressure(psia)

3000 2500

Hydrate Formation Region 0 wt% MeOH

2000 1500 1000 500

Hydrate Free Region

0 30

35

40

45

50 Temperature(oF)

55

60

65

70

Figure 17 - Dog Lake Field - Original Conditions (From Todd, 1997)

2000

25 wt% MeOH

1800

10 wt% MeOH

20 wt% MeOH

0 wt% MeOH

1600

Pressure(psia)

1400 1200 1000

Wellhead

Pipeline

Separator

800 600 400 200 0 30

40

50

60 Temperature(oF)

70

80

90

1. Burying the Pipeline. Some of the Dog Lake pipeline was built over a stretch of marsh. The exposure to winter ambient temperatures caused rapid reductions in the gas temperature. Burying the pipeline would protect it from low environmental temperatures due to the higher earth temperatures. Figure 18 displays the temperature increase in the pipeline after exposed areas were buried relative to the exposed pipeline in Figure 17. With pipeline burial, the need for methanol in the water phase was reduced from 26 wt% to less than 19 wt%. 2. Wellhead Heat Addition. Catalytic in-line heaters could be installed at the wellhead to increase the gas temperature to 125oF. Figure 19 shows the pipeline temperature increase caused by the combined prevention methods of burial and wellhead heating. Use of these two methods permitted the methanol concentration to be reduced to approximately 14 wt% to prevent hydrate formation in the line. It should be noted that heating may increase the amount of corrosion in the line. 3. Insulation. Insulation of exposed areas near the wellhead and battery would maintain higher pipeline temperatures, thereby reducing the amount of methanol needed for hydrate inhibition. Figure 20 displays the temperature increase in the buried and heated pipeline when exposed pipes were insulated. The pipeline is now outside the hydrate formation region, and methanol addition is no longer needed. 4. Methanol Addition. Continued methanol injection could be done at an cost of approximately $1.50 -$2.00 per gallon. The cost of methanol to an offshore platform cost $2.00 per gallon during the 1996-7 winter. Since methanol recovery may not be economical, methanol is normally considered an operating cost. This case study illustrates how combinations of pipeline burial, insulation, heating, and methanol injection can be used to prevent hydrates. The selection of the hydrate prevention scheme(s) is then a matter of economics, as considered in Section IV of this handbook. _____________________________________________________________________

II.F. Hydrate Limits to Expansion through Valves or Restrictions. When water wet gas expands rapidly through a valve, orifice or other restriction, hydrates form due to rapid gas cooling through Joule-Thomson expansion. Hydrate formation with rapid expansion from a wet line commonly occurs in fuel gas or instrument gas lines, as indicated in the platform Example 12 in Section II.F.3. Hydrate formation with high pressure drops can occur in well testing, start-up, and gas lift operations, even when the initial temperature is high, if the pressure drop is very large. This section provides methods to determine when hydrates will form upon rapid expansion. A rough estimation method (Section II.F.1) is followed by a more accurate

31

Figure 18 - Dog Lake Field with Burial (From Todd, 1997)

2000 20 wt% MeOH

1800

0 wt% MeOH

10 wt% MeOH

1600

Pressure(psia)

1400 1200 Separator

Wellhead

Pipeline

1000 800 600 400 200 0 30

40

50

60 Temperature(oF)

70

80

90

Figure 19 - Dog Lake Field with Burial and Heating (From Todd, 1997)

2000 20 wt% MeOH

1800

10 wt% MeOH

0 wt% MeOH

1600

Pressure(psia)

1400 1200 Pipeline

Sep.

Wellhead

1000 800 600 400 200 0 30

40

50

60

70

80

90

Temperature(oF)

100

110

120

130

Figure 20 - Dog Lake Field with Burial, Heating, and Insulation (From Todd, 1997)

2000 20 wt% MeOH

1800

10 wt% 0 wt% MeOH MeOH

1600

Pressure(psia)

1400 1200 Separator

1000

Wellhead

Pipeline

800 600 400 200 0 30

40

50

60

70 80 90 Temperature(oF)

100

110

120

130

but resource intensive method (Section II.F.2), concluding with prevention techniques in Section II.F.3. Figure 7 is a schematic of the pressure and temperature of a pipeline production stream during normal flow with entry into the hydrate formation region. If the gas expands rapidly, the normal pipeline cooling curve of Figure 7 will take on a much steeper slope, but the hydrate formation line remains the same. Two rapid expansion curves for a 0.6 gravity gas are shown in Figure 21. Intersections of the gas expansion curves with the hydrate formation line gives the limiting expansion discharge pressures from two different high initial pressure/temperature conditions. In Figure 21, the curves specify the pressure at which hydrate blockages will form at the restriction discharge for an upstream pressure and temperature. Gas A expands from 2000 psia and 110oF until it strikes the hydrate formation curve at 780 psia (and 57oF) so that 780 psia represents the limit to hydrate-free expansion. Gas B expands from 1800 psia (120oF) to intersect the hydrate formation curve at a limiting pressure of 290 psia (42oF). In expansion processes while the upstream temperature and pressure are known, the discharge temperature is almost never known, but the discharge pressure is normally set by a downstream vessel or pressure drop. Cooling curves such as the two in Figure 21 were determined for constant enthalpy (or Joule-Thomson) expansions, obtained from the First Law of Thermodynamics for a system flowing at steady-state, neglecting kinetic and potential energy changes: ∆H = Q - Ws

(6)

where ∆H is the enthalpy difference across the restriction (downstream - upstream), while Q represents the heat added, and Ws is shaft work obtained at the restriction. Offshore restrictions have no shaft work, and because the system operates adiabatically, both Ws and Q are zero, resulting in constant enthalpy (∆H =0) operation on expansion. Due to the constant enthalpy requirement, rapid gas expansion results in cooling, except at very high pressures, where heating occurs on expansion due to a compressibility decrease with temperature. The upstream pressure at which the system changes from heating to cooling upon expansion is called the Joule-Thomson inversion pressure. Rule-of-Thumb 7. Natural gases cool upon expansion from pressures below 6000 psia; above 6000 psia the temperature will increase upon expansion. Virtually all offshore gas processes cool upon expansion, since only a few reservoirs and no current pipelines or process conditions are above 6000 psia.

32

Figure 21 Hydrate

-

Gas Expmsion into Forrmtioo Region

(From

Katz,

1944)

2000 1500 1000 d .:: ;I L Z E k

800 600 500 400 300

30

40

50

60

70

80

90

Temperature(F)

100

1

Rule-of-Thumb 7 was determined by G.G. Brown at the University o Michigan (1945) who constructed the first natural gas enthalpy - entropy charts. II.F.1. Rapid Calculation of Hydrate-Free Expansion Limits. Katz (1945) generated charts to determine the hydrate-free limit to gas expansion, by the gas gravity chart (Figure 9) to obtain the hydrate formation line in Figure 21, with gas enthalpy-entropy charts by Brown (1945) to obtain the cooling line. Cautioning that the charts applied to gases of limited compositions, Katz provided expansion charts for gases of 0.6, 0.7, and 0.8 gravities, shown in Figures 22, 23, and 24 respectively. The abscissa (or x axis) in each figure represents the lowest downstream pressure without hydrate formation, given the upstream pressure on the ordinate (y axis) and the upstream temperature (a parameter on each line). It should be noted that the maxima in Figures 22, 23, and 24 occur at an inlet pressure of 6000 psia, the Joule-Thomson inversion pressure. This provides a further validation of Rule-of-Thumb 7 above. The following three examples for chart use are from Katz’ original work. _____________________________________________________________________ Example 10a Maximum Pressure of Gas Expansion. To what pressure may a 0.6 gravity gas at 2000 psia and 100oF be expanded without danger of hydrate formation? Solution: From Figure 22, read 1050 psia.

Example 10b. Unlimited Gas Expansion. How far may a 0.6 gravity gas at 2000 psig and 140oF be expanded without hydrate formation? Solution: In Figure 22 it is seen that there is no intersection with the 140oF isotherm. Hydrates will not form upon expansion to atmospheric pressure..

Example 10c. Minimum Initial Temperature Before Expansion. A 0.6 gravity gas is to be expanded from 1500 psia to 500 psia. What is the minimum initial temperature that will permit the expansion without danger of hydrates? Solution: From Figure 22 the answer is read as 99oF or above. _____________________________________________________________________

Figures 22, 23, and 24 for gas expansion incorporate the inaccuracies of gas gravity charts from which they were derived. As indicated in Section II.C the 0.6 gravity chart (used for both hydrate formation and gas expansion) may have inaccuracies of ± 500 psia. Accuracy limits to these expansion curves have been tested

33

Figure 22 - ffas Emansion of 0.6 6as Gravitv W6 (From Katz.1959) 10000 8

_

-I _

6

4

2

1000

! _

_

_

6 6

_ _

4 i

_

Initial

1

_

2

_

-

100 100

2

4

2

6 6

1000

Pressure (psia)

Fimure 23 - Gas

Exsansion

of 0.7 ffas Gram

NG

(FromKatz,1959) 10000 _

6

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I~

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I

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F,inal Pwssuya fpsia\

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6 610000

10()OOT

- - -~

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(From Katz, 1959) -

---

r

--

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a 1000

Final Pressure (psia)

2

-

I

by Loh et al. (1983) who found for example, that the allowable 0.6 gravity gas expansion from 150oF and 3500 psia should be 410 psia rather than the value of 700psia, given by Figure 22.

II.F.2. More Accurate Calculation of Hydrate-Free Limits to Gas Expansion. A more accurate computer method is available, using the same principles indicated in Figure 21. Just as before, for an initial temperature, pressure and gas composition, the intersection of an isenthalpic (∆H=0) cooling curve with the hydrate three-phase locus may be determined. In the new method, the isenthalpic line is determined via a modern equation-of-state, and the program HYDOFF replaces the gas gravity chart to predict hydrate formation conditions. While this method requires more resources (namely time and an IBM-compatible computer) than the Joule-Thomson charts, it results in higher accuracy and provides an estimation of the amount of methanol inhibitor required. In order to use the more accurate method, the first step is to generate the hydrate stability pressure-temperature line as in Figure 21, using HYDOFF as indicated in Section II.D.1. Later the amount of methanol injected to displace the hydrate formation curve to the left can be calculated, as illustrated in Example 12 in Section II.F.3 at the close of this Section. The computer program XPAND is included with this handbook for calculation of the second, Joule-Thomson expansion line, which intersects the hydrate formation line. The expansion line is calculated with an equation-of-state, using the method detailed by Sloan (1998, Appendix A). Given an inlet temperature, pressure, and gas composition, the program calculates the enthalpy change (∆H) for a specified outlet pressure and a temperature guess. The user changes the outlet temperature guess until a value of ∆H = 0 is obtained. The resulting discharge temperature and pressure is plotted to obtain the expansion curve. For one inlet temperature and pressure, a series of such discharge points provides a curve which intersects the hydrate formation curve at the limiting temperature and pressure of expansion. The result may be compared with the Joule-Thomson result in Figures 22, 23, and 24.

_____________________________________________________________________ Example 11: Hydrate Formation on Expansion of a Natural Gas A simple natural gas consists of 90 mol% CH4 , 7% C2H6 , and 3% C3H8 with free water in a pipeline. Two initial inlet process conditions are considered for expansion across a valve: (a) 68oF and 2180 psia, or (b) 77oF and 2180 psia. For either condition, is hydrate formation a possibility? Are there process limitations on the expansion from either initial condition to 1450 psia?

34

Solution: Before doing any hydrate calculations, one should confirm that this gas is not close to the hydrocarbon dew point, to eliminate the possibility of encountering both vapor and liquid hydrocarbon phases. The expansion program was written for a gas phase. A vapor-liquid equilibria flash calculation indicates that the highest temperature at which a hydrocarbon liquid can occur (the cricondentherm) for this mixture is -44oF, so the process will not form hydrocarbon liquid. Figure 25 shows the expansion conditions of both inlet conditions for the gas. The remainder of this example concerns the generation of Figure 25 and the processing implications. First, the pressures and temperatures of hydrate formation are calculated using the program HYDOFF as in Section II.D as: T(oF) P(psia)

32 119

35 149

40 213

45 303

50 368

55 551

60 718

65 1117

68 1624

71 2509

77 4046

A semi-logarithmic interpolation of the above values gives the hydrate formation point at 70oF when the pressure is 2180 psia. Therefore the initial condition of 68oF and 2180 psia is within the hydrate formation region, but the initial conditions of 77oF and 2180 psia remains in the fluid (vapor-liquid water) region. If the system at 68oF and 2180 psia has formed hydrates, consider two means of depressurization. If the system pressure is lowered to 1450 psia slowly and isothermally (with substantial heat input) hydrates will dissociate at 1537 psia. A second, isenthalpic (∆H=0) depressurization without heating from the surroundings, results in much colder gas at 1450 psia. Using XPAND on the disk accompanying this handbook (see the User’s Manual prescription in Appendix B) the following isenthalpic line is obtained: P (psia) T (oF) for ∆H=0

2100 68.0

2000 1800 1600 1450 62.4 55.2 46.9 39.8

As shown in Figure 25, the isenthalpic expansion system extends further into the hydrate region. Only with subsequent heating at a constant pressure of 1450 psia, will the system become hydrate-free at 66.6oF. A similar calculation for the system initially in the fluid region at 77oF and 2180 psia shows the problem with isenthalpic expansion. The result, plotted as line ABC in Figure 25 shows an isenthalpic intersection with the hydrate formation boundary at approximately 70.5oF, 1990 psia. To prevent expansion into the hydrate region four options may be considered, as illustrated in Example 12:

1. limit the final expansion pressure to a higher value than 1990 psia, 2. add inhibitor at the restriction inlet, 3. dehydrate the gas before expansion, or

35

Figure - 25 Joule-Thomson Cooling Through Gas Expansion (From Sloan, 1998)

3000 Isenthalpic Expansion From 77oF, 2180 psia

Isenthalpic Expansion From 68oF, 2180 psia

2500

Pressure(psia)

C

B

∆H = 0

2000

1500

A

Isothermic Expansion From 68oF, 2180 psia

∆H = 0

∆T = 0

1000

500

Hydrate Formation Curve

0 30

35

40

45

50

55

60

Temperature(oF)

65

70

75

80

4. heat the gas to a higher inlet temperature.

Pipeline hydrate plugs are frequently porous, so that depressurization from one (downstream) side can result in Joule-Thomson cooling as gas flows through the plug. Expansion across a hydrate plug yields identical results to expansion across a valve. In the initial part of the above example, it was seen that expansion from a condition which has a hydrate plug (e.g. 68oF and 2180 psia) will only cause the downstream portion of the plug to progress further into the hydrate region. Heat must be put into the system from the surroundings to dissociate hydrates. The field tests which confirm the above discussion are given in Case Studies C.15 and C.17 in Appendix C. There are several limitations to XPAND. First, it is limited to the vapor phase and will not account for expansion of a fluid containing any liquid amount. If there is a question whether the system might contain a liquid either at the inlet or discharge, the engineer should calculate the hydrocarbon dew point, and an isenthalpic flash should be performed to obtain the cooling curve, using a process simulator package like HYSIM , ASPEN , or PROCESS . Secondly, XPAND was generated only for the first five common paraffins (methane, ethane, propane, normal butane, iso-butane, and normal pentane) so XPAND cannot be used with nitrogen, acid gases (H2S or CO2), or with significant amount of heavy components. With the above restrictions, the engineer may group components larger than pentanes into the “pentane plus” fraction of the gas.

II.F.3. Methods to Prevent Hydrate Formation on Expansion. Frequently gas expansion causes hydrate formation in fuel gas lines and in instrument gas lines on a platform, which may result in other, larger hydrate problems. In some cases, hydrate formation in a platform instrument gas line has caused system shutdown; subsequent cooling of the non-flowing pipeline into the hydrate formation region resulted in a pipeline blockage upon resumption of flow. The following example provides a Section II.F summary of hydrate prevention during gas expansion, with four methods for hydrate prevention in a fuel gas line, which is used to supply power to platform compressors. _____________________________________________________________________ Example 12: Hydrate During Gas Expansion An offshore platform design required fuel gas at 300 psia and a rate of 0.02 MMscf/d from a high pressure flowline at 1500 psia and 100oF. The inlet flowline was offgas from the first stage separator (see Figure 8, Example 3) so the gas was saturated with water. A control valve was placed on fuel gas line from the inlet flowline to provide the required pressure and flow of fuel gas. The mole fraction

36

composition of the components were: 0.927 methane, 0.053 ethane, 0.014 propane, 0.0018 i-butane, 0.0034 n-butane, and 0.0014 i-pentane. Is there a chance that hydrate formation might occur in the fuel gas line? If so, which of the following ways could be used to prevent hydrates? 1. 2. 3. 4.

two stage expansion with intermediate heat addition, methanol injection upstream of expansion, parallel expansions, and drying the inlet gas.

Solution: The example solution is provided with the following steps: Ex12.A1. Hydrate-Free Expansion Limits Using the Joule-Thomson Diagrams Ex12.A2. Hydrate-Free Expansion Limits Using HYDOFF and XPAND Ex12.B1. Prevention via Heat Addition to Two-Stage Expansion Ex12.B2. Prevention via Methanol Injection Upstream of Expansion Ex12.B3. Parallel Expansions Ex12.B4. Drying the Inlet Gas Ex12.A1. Hydrate Prediction Through Joule-Thomson Diagrams. Using the Katz Joule - Thomson expansion diagrams (Figures 22, 23 and 24), the minimum initial temperature required for hydrate-free operation can be estimated. This gas is identical with that in Example 4, whose gravity is calculated as 0.603. Figure 22 provides an estimate that a 0.6 gravity natural gas must have an initial temperature of 104oF to prevent hydrate formation during gas expansion from 1500 psia to 300 psia. Under the current design the initial temperature of 100oF will cause hydrates to form just downstream of the fuel gas control valve. Ex12.A2. Hydrate Prediction Using XPAND and HYDOFF. XPAND was used to calculate the discharge temperature of the natural gas upon expansion, using inputs of the upstream valve pressure, temperature and gas composition to calculate the downstream gas temperature at a given discharge pressure. Appendix B gives a step-by-step XPAND User’s Manual for the calculation in this example. Once the expansion P-T values are obtained, they are plotted to determine the intersection with hydrate formation curves (including inhibited curves) generated by HYDOFF, as done in Section II.D. Figure 25 shows such intersections. In Figure 26 note that the expansion line is curved, requiring calculation of several temperatures and pressures along the expansion line. The expansion enters the uninhibited formation region at 53oF and final temperature after expansion is calculated to be 33oF. For a comparison with 105oF inlet temperature requirement by the Katz

37

Figure 26 - Hydrate Formation Curve for Single Valve Expansion 1600

Hydrate Formation Curves

1400

20 Wt% MeOH

10 Wt% MeOH 0 Wt% MeOH

Inlet

Pressure(psia)

1200 1000

Hydrates

800 600 Gas Expansion Curve 400

Outlet

No Hydrates 200 0 30

40

50

60

70 80 o Temperature( F)

90

100

110

Joule-Thomson charts, the inlet temperature using XPAND should be 108oF for hydrate-free expansion from 1500 psia to 300 psia.

Ex12.B. Hydrate Prevention After establishing that hydrates will form upon gas expansion, the platform design had to be modified to inhibit hydrate formation. Four hydrate prevention methods were considered: 1) Heat addition to two stage expansion, 2) methanol addition, 3) parallel expansion, and 4) drying the gas. Details of each prevention method are provided below. Ex12.B.1. Heat Addition with Two-Stage Expansion. In-line heaters could be installed to raise the temperature of the gas outside the hydrate formation region. In the case considered here, two control valves are used with an in-line heater between them. Figure 27 is a schematic of the two control valves and in-line heater design for the fuel gas line. The cooler gas present after the first pressure drop facilitates heat transfer before the second valve. The following calculations provide the pressure and temperature conditions in the system shown in Figure 24. In our example, the pressure ratio (Pin/Pout) will be arbitrarily set at a value approximately equal across each control valve, providing 675 psia as the intermediate pressures after the first control valve. Using XPAND the temperature of the gas at 675 psia is predicted to be 58oF at the first valve discharge. Figure 28 shows the gas expansion conditions and the HYDOFF hydrate formation curves, demonstrating that the gas is outside the hydrate formation region after the first pressure drop (line 1). In Figure 28, heat is added to the system (line 2) to raise the temperature to prevent hydrates upon gas expansion across the second control valve (line 3). The heat duty in the exchanger was defined by the temperature increase (T3-T2). XPAND was used to estimate a value of T3 at the second valve inlet which provided a discharge value T4 outside the hydrate formation region. For this example, a T3 of 68oF is required to maintain the final temperature at 44oF, just above the hydrate formation region at the required pressure of 300 psia. Figure 28 suggests that heating before expansion through a single control valve may provide a more economical method to prevent hydrates on expansion. A single control valve and heater would save the capital cost of one control valve and may be a better alternative to prevent hydrates on expansion.

Ex12.B.2. Methanol Addition. Methanol can be injected into the fuel supply line upstream of the control valve to prevent hydrate formation downstream of the valve. Figure 26 shows that more than 10 wt% methanol is needed in the free water phase to prevent hydrate formation. A better estimate of 12 wt% methanol in the

38

Figure 27 - Two Stage Gas Expansion with Heating 1st Control Valve

In-Line Heater

2nd Control Valve

P1 = 1500 psia

P2= 675 psia

P3= 670 psia

P4= 300 psia

T1= 100oF

T2= 58oF

T3= 68oF

T4= 44oF

Estimated Using HYDXPAND

Figure 28 - Two Stage Gas Expansion with Heat Addition 20 Wt% MeOH

1600

Inlet 1st Valve(T1)

10 Wt% MeOH 0 Wt% MeOH

1400

Hydrates Heating Line #2

Pressure(psia)

1200

Line #1

1000 Outlet 1st Valve (T2)

800

Inlet 2nd Valve(T3)

600

Gas Expansion Curve

Line #3

400

No Hydrates Outlet 2nd Valve(T4)

200 0 30

40

50

60

70 Temperature(oF)

80

90

100

110

water phase was obtained through interpolation using XPAND and HYDOFF. The total amount of methanol required for upstream gas injection is calculated through methods of Section II.D.

Ex12.B.2.a.Water condensation with expansion. Gas flows into the fuel line at a rate of 0.02 MMscf/d. Since the gas is saturated with water, one can calculate the mass of free water in the pipeline due to dewpoint condensation from Figure 10 (45 lbm H2O/MMscf in the vapor at 1500 psia and 100oF and 16 lbm H2O/MMscf in the vapor at 350 psia and 33oF). The amount of free water that forms from the vapor is 45 lbm/MMscf- 16 lbm/MMscf = 29 lbm/MMscf. Consequently, the total amount of water (W) condensed per day is: 29lbm H2 O 0.02 MMscf 0.58lbm H2 O × = MMscf day day

Ex12.B.2.b. Mass of MeOH Required in the Water Phase. The mass of MeOH can be found by using the definition of weight percent wt % =

M (lbm MeOH ) X 100% M ( lbm MeOH ) + W ( lbm H2 O)

Solving for 12 wt%, the amount of methanol, M = 0.079 lbm MeOH/day Ex12.B.2.c. Mass of MeOH Lost to Condensate and Vapor. The mole fraction of MeOH in the water is found by the equation: mole fraction MeOH =

0.079 lb m MeOH / (32 lb m / lbmol MeOH) 0.079 / 32 + 0.58 lb m H 2 O / (18lb m / lbmolH 2 O)

The mole fraction MeOH in the water phase is xMeOH in H2O = 0.071. The distribution coefficient of MeOH in the gas is calculated at 33.03 oF (492.7oR) by Equation (3), relative to the methanol in the water KvMeOH = exp (5.706 - 5738×(1/492.7oR) = 0.00263

(3)

The mole fraction of MeOH in the vapor is yMeOH = KvMeOH•xMeOH in H2O or yMeOH = 0.00263 × 0.071 = 0.000187

39

The daily gas rate is 52.7 lbmol (= 2.0 × 104 scf / (379.5 scf/lbmol)), so that the MeOH lost to the gas is 0.0098 lbmol (= 0.000187 × 52.7) or 0.314 lbm/day. No condensate is formed in the pipeline, consequently there is no MeOH lost to the liquid hydrocarbon phase. Ex12.B.2.d. Total Mass of MeOH Needed. The total amount of MeOH injected is the sum that in the vapor (0.314 lbm) condensate (0), and water (0.079 lbm) = 0.393 lbm MeOH/day (0.06 gal/day) injection required to inhibit the fuel gas line, with injection before the control valve as shown in Figure 29. Ex12.B.3. Parallel Gas Expansion. Operating personnel sometimes suggest that fuel gas lines be placed in parallel to provide more than one gas expansion as shown in Figure 30. If one control valve becomes plugged with hydrates and shut down, the second gas line is then opened while the first line is depressurized for hydrate dissociation. In this manner, it is hoped that flow can be maintained in one fuel gas line without the need for hydrate inhibition. Conditions of hydrate formation on parallel gas expansion are exactly the same as shown in Figure 26. The capital cost is doubled however, and there is the risk that the parallel valve may become hydrated before the plug is removed from the initial line. This solution technique addresses the effect of hydrate formation rather than its cause, and should be considered less than optimal operating practice.

Ex12.B.4. Drying the Inlet Gas. If the gas inlet is dry, hydrate formation cannot form due to insufficient water. It is good design practice to place both fuel gas and instrument gas lines downstream of a TEG drying unit or a molecular sieve adsorption tower. The design of a drying unit is outside of the scope of this handbook, but it is readily available in standard texts on gas processing (e.g. Manning and Thompson, 1991). _____________________________________________________________________ Of the above four design methods to prevent hydrates in fuel gas lines, the most satisfactory from the standpoint of expense and operating practice is to provide dry inlet gas with a fuel gas line downstream of the TEG dryer. As Deaton and Frost (1946, p. 41) stated in their classic study of hydrate formation and prevention: “The only method found to be completely satisfactory in preventing the formation of hydrates in gas transmission lines is to dehydrate the gas entering the line to a dew point low enough to preclude formation of hydrates at any point in the system.”

40

Figure 29 - Single Valve Gas Expansion with Methanol Injection Control Valve Gas Inlet of 0.02 MMSCF per day 0.393 lbm MEOH/day .

P1=1500 psia

P2=300 psia

T1=100oF

T2=33oF

Figure 30 - Parallel Gas Expansion

P1=1500 psia

P2=300 psia

T1=100oF

Flowline #1 T2=33oF

High Pressure Flowline P2=300 psia T1=100oF P1=1500 psia

Flowline #2 T2=33oF

The study of gas expansion without hydrate formation suggests two additional Rules-of-Thumb, stated below. Rule-of-Thumb 8. It is always better to expand a dry gas than a wet gas, in order to prevent hydrate formation in unusual circumstances, e.g. changes in upstream pressure due to throughput changes. Rule-of-Thumb 8 is illustrated by the previous example, which typifies instrument or fuel gas applications. To use this Rule-of-Thumb it is necessary to be able to dry the gas, using either a glycol dehydrator or a molecular sieve adsorption process. Rule-of-Thumb 9. Where drying is not a possibility, it is always better to take a large pressure drop at a process condition where the inlet temperature is high. One application of Rule-of-Thumb 9 is the bottom hole choke, provided in Texaco’s Reliability Engineering: Gas Freezing & Hydrate Study, a handbook for field personnel by Todd et al. (1996). A bottom hole choke is a device with a restricted opening, placed in the lower end of the tubing string to cause a large pressure drop to be taken deep in the wellbore. The warm downhole reservoir heats the gas before it expands, thus preventing hydrates from forming across the expansion. The majority of bottom hole chokes are installed in high pressure gas wells that producer a low amount of liquids.

II.G. Hydrate Control Through Chemical Inhibition and Heat Management There are four classical approaches to hydrate inhibition, discussed at the beginning of Section II: 1. remove water from the system, 2. increase the temperature, 3. decrease the pressure, or 4. insert a component to attract water molecules, such as an alcohol or glycol. Two additional, new inhibition techniques have been commercialized and are gaining industrial acceptance: 5. the kinetic inhibition method of preventing sizable crystal growth for a period exceeding the free water residence time in a pipeline, and 6. the anti-agglomerant method which uses a surfactant to stabilize the water/hydrate phase as small emulsified droplets within a liquid hydrocarbon. Thermodynamic inhibition (methods 1 through 4) prohibit hydrate formation altogether, while with the newer methods (5 and 6) the system is allowed to exist within the hydrate stability zone, so that small crystals are stabilized for some time

41

period without growing to larger masses. While thermodynamic inhibitors are the standard practice offshore, there are successful commercial instances of kinetic control. The incentive for newer kinetic control methods is a substantial capital cost reduction by the elimination of the need for offshore platform equipment, a small operating cost reduction, and elimination of some environmental concerns. In the future innovative methods of heat management through heating and insulation may provide thermodynamic protection against hydrates. Section II.G.1 discusses design and operation with thermodynamic inhibition chemicals (methanol and monoethylene glycol). Section II.G.2 discusses design and operation with kinetic inhibitors. Section II.G.3 summarizes the chemical inhibitor use guidelines. Section II.G.4 shows the methods of heat management to retain a high inlet temperature in the fluid region.

II.G.1 Inhibition with Methanol or Monoethylene Glycol II.G.1.a Methanol. Of all hydrate inhibitors, methanol is the most widely used. Methanol is also the best and most cost effective of the alcohols. Hydrate inhibition abilities are less for larger alcohols (i.e. methanol > ethanol > isopropanol.) Typically methanol is vaporized into the gas stream of a pipeline, then dissolves in any free water accumulation(s) to prevent hydrate formation. For methanol injection into wells, a commercial program such as WELLTEMP can be used to predict the flowing temperature and pressure (in an identical manner to that used with PIPEPHASE or OLGA in Example 2 of Section II.A). The downhole methanol injection point is placed at the well depth for which the well temperature and pressure are predicted to cross into the hydrate formation region, for both well production and well testing conditions. Usually the flowing well conditions are warm enough to prevent hydrate formation. The methanol amount needed in free water of either wells or flowlines may be determined using Hammerschmidt’s equation or HYDOFF, as illustrated in Sections II.C. and II.D. Typically the free water concentration of methanol in onshore pipelines is about 20 wt%, while offshore methanol concentrations can exceed 50 wt% if the pressure is high. A recent finding is that under-inhibition with MeOH is worse than no inhibition for two reasons, as measured by Yousif et al, (1996): (1) under-inhibited systems form hydrates faster than systems without inhibitors, and (2) hydrates stick to the pipe walls more aggressively when insufficient methanol is injected. While hydrate inhibition occurs in the water phase, significant amounts of methanol are also dissolved in the vapor and oil/condensate phases. Proportions of methanol dissolved in the vapor or oil/condensate phases are calculated via the

42

methods of Sections II.C and II.D, and are usually taken as operating expense losses. Methanol loss costs can be substantial when the total fraction of either the vapor or the oil/condensate phase is very large relative to the water phase. Sample economics for methanol are provided in Section IV and in the following Case Study 7. Makogon (1981, p. 133) noted that in 1972 the Soviet gas industry used 0.3 kg of methanol for every 1000 cubic meters of gas extracted. Norsk Hydro workers (Stange et al. 1989) indicated that North Sea methanol usage may surpass the ratio given by Makogon by an order of magnitude. The use of methanol in the North Sea has become so expensive that alternatives to methanol injection are considered.

_____________________________________________________________________ Case Study 7. Methanol Recovery from the Water Phase Paragon Engineering (1994) performed a study for DeepStar (DSII CTR 2211) of the impact of methanol recovery on offshore systems. As an evaluation scenario, a conventional, shallow water platform was designed solely for methanol recovery in 100-150 feet of water, with methanol return lines 40-60 miles to deepwater subsea wells. Figure 31 shows a block flow diagram for methanol recovery and injection. Costs were determined for methanol recovery on the platform for eight cases of methanol in the produced water. Table 3 shows results for four cases: 20wt% and 30wt% methanol in the free water phase, for (a) high water production in late field life, and (b) low water production in early field life.

Table 3. Methanol 1994 Costs with Offshore Platform Recovery Case Amount of MeOH in H2O, wt% Oil Production, bpd Produced Water, bpd Gas, MMscf/d Injected MeOH, bpd MeOH Loss to Gas, lbm/d MeOH Loss to Gas, % MeOH Loss to Oil, lbm/d MeOH Loss to Oil, % Installed Cost on Platform, $MM Total Cost with Platform, $MM Operating Cost, $MM/yr.

High Water (Late Life) 30 20 13,188 14,593 15 7,797 6,412 0.29 2,176 0.10

13,191 14,498 15 4,537 4,430 0.35 1,456 0.11

Low Water (Early Life) 30 20 48,813 3,196 57 1,668 23,443 4.72 7,914 1.59

48,802 3,188 57 960 15,977 5.53 5,224 1.81

Capital and Operating Cost Calculations 16.7 13.3 5.03 4.20 20.8 17.4 9.14 8.31 5.78 4.39 4.25 2.99

43

Figure 31 - Methanol Recovery and Injection (From Manning and Thompson, 1991)

Shallow Water Platform (150 ft. w.d)

Max. MeOH Min. MeOH Rec. Facil. Rec. Fac. Gas Flow (MMSCFD) 15.3 56.4 Oil Flow (BPD) 13,200 48,800 Water Flow (BPD) 14,600 3,380 MeOH Inj. (BPD) 7,800 200 MeOH Rec. (%) 99.5 91

Gas Treating Dehydration Compression & Metering

Oil/Gas/Water Separation

Water

Oil/Gas to Sales Pipeline

Oil

Oil Treating Pumping Metering

Water Treating

50 miles to Platform 12” Production Pipeline 4” Methanol Re-injection

Deepwater (4000 ft. w.d) Subsea Well & Template

Methanol Storage

Methanol Recovery Facilities Water Overboard

In all cases methanol was recovered as the overhead product from a 40 tray distillation column. The bottoms methanol concentration was less than 1000 ppm so that water could be dumped overboard. Paragon Engineering also reported methanol losses which were greater than anticipated in North Sea recovery systems from three Conoco facilities (4-5 gal MeOH lost/MMscf), a Norsk Hydro recovery unit (29% MeOH losses), and an Amoco Netherlands recovery unit (12% MeOH losses). _____________________________________________________________________ Methanol recovery is possible from the vapor phase, using a cryogenic recovery process, but this is seldom done due to the expense involved. Methanol can be recovered from the condensate via a water-wash and subsequent distillation, but this is also seldom done. Environmental concerns have a major impact on recovery.

II.G.1.b Monoethylene Glycol. Of the glycols, mono-ethylene glycol (MEG) dominates pipeline injection over di-ethylene glycol (DEG) and tri-ethylene glycol (TEG) because MEG has a lower viscosity and is more effective per pound. MEG also has a higher molecular weight and a lower volatility than methanol, so MEG may be recovered and recycled more easily on platforms. In addition MEG losses to the vapor and oil/condensate phases are very small relative to methanol. Consequently, MEG is most applicable for small water fractions when gas and oil/condensate fractions are very high. The MEG injection amount may be calculated using methods in Sections II.C and II.D. Rule-of-Thumb 10. Monoethylene glycol injection is used when the required methanol injection rate exceeds 30 gal/hr. Rule-of-thumb 10 was obtained from Manning and Thompson (1991, p. 86). Unlike methanol, MEG’s low vapor pressure requires that it be atomized into a pipeline. After injection, MEG is retained with the water phase and provides no hydrate protection above the water level. Due to it’s high viscosity and density, MEG is seldom used to dissociate a hydrate plug unless the injection point is vertically above a hydrate plug (as in a riser or a well); methanol is normally used for flowline plugs.. Figure 32 shows a MEG recovery unit that appears very similar to the methanol recovery block diagram in Figure 31. However in the methanol column the overhead may be almost pure methanol, while in the glycol regenerator MEG is recovered with water (typically at 60-80 wt%) at the bottom. Salt also concentrates in MEG regenerator bottoms (due to low salt vapor pressure) when salt water is produced in the well stream inhibited by MEG. The salt solubility limit in MEG is frequently exceeded, resulting in salt precipitation and fouling of column trays, exchangers, and other equipment.

44

Figure 32 - MEG Recovery and Regeneration (From Manning and Thompson, 1991)

Wellstream

Free Water Knockout

Gas

Glycol Inj. Nozzle

Bypass Valve HXER

Water

Low Temp Separator

Choke Residue Gas

Water Vapor

Lean Glycol Filter Glycol Pump Glycol-Oil Separator Oil to Stabilizer

Fuel Gas

Glycol Regenerator

Glycol-Glycol HXER

Rich Glycol

II.G.1.c Comparison of Methanol and Glycol Injection. In a comprehensive set of experimental studies, Ng et al. (1987) determined that methanol inhibited hydrate formation more than an equivalent mass of glycol in the aqueous liquid. Methanol usage (principally in flowlines and topside on platforms) predominates in the Norwegian sector of the North Sea; MEG is principally used for hydrates in wells and risers. In contrast, MEG dominates BP’s inhibition use in the North Sea. Major problems with use of MEG are high viscosity in long lines and salt precipitation upon regeneration. Methanol use is much more prevalent than MEG in the United States. While there is no robust strategy to discriminate between the use of methanol and MEG, the choice seems to depend upon (a) plug location, (b) fluid effects, and (c) properties of the plug in question. The table below provides a summary.

Table 4. Methanol and Monoethylene Glycol Attributes Comparison Hydrate Inhibitor

Methanol (MeOH)

Monoethylene Glycol (MEG)

Advantages

-easily vaporized into gas -for flowline & topside plugs -no salt problems

-easy to recover -for plugs in wells and risers -low gas &condensate solubility

Disadvantages

-costly to recover -high gas & condensate losses -too little is worse than none -costly in condensate product (See Table 13 Section IV.B.1.a)

-high viscosity inhibits flow -salt precipitation and fouling -remains in aqueous phase

A step-wise list of considerations before injection of methanol and monoethylene glycol are provided in Table 5 at the end of Section II.G.3.

II.G.2. Kinetic Control by Anti-Agglomerants and Kinetic Inhibitors The reader is referred to the text by Sloan (1998, Section 3.3) for the theory of hydrate prevention using the two new techniques of anti-agglomeration and kinetic inhibition. At the time of this writing, the kinetic inhibition area is changing rapidly with substantial research and development, and only a few good examples of commercial application exist. With some inhibitors, substantial advantages are claimed for combinations of anti-agglomerants and kinetic inhibition. 45

II.G.2.a Anti-Agglomerants. Figure 33 shows a schematic of the method for anti-agglomeration. In the upper diagram hydrates form large black masses and can grow to a size to plug the pipeline. In the lower portion of Figure 33, a surfactant emulsifier has been added to the gas condensate system to cause the water to be suspended as small droplets in the condensate. With this inhibition mechanism, hydrate droplets form, and both gas and water are consumed, but hydrates are prevented from agglomerating to larger hydrate masses capable of plugging pipelines. Even though hydrates are formed, their suspension may provide acceptable flow properties such as low pressure drops. Antiagglomerant inhibitors are particularly effective in preventing hydrate pluggage or flow stoppages such as shut-ins, with subsequent cooling and restarting. As surfactant molecules, anti-agglomerants have one water-attractive end, while the other end attracts oil, causing a lower surface tension between oil and water. With excess oil, a surfactant causes the water phase to be suspended as emulsified droplets. However with excess water, the emulsion may be reversed and water will be the external phase. Surfactant chemistry is complex and a different surfactant may be required to emulsify water with each oil (or condensate). Lingelem, et al. (1994) present Norsk-Hydro data in Figure 34 as an example of anti-agglomerant behavior in a multiphase pipeline that did not exhibit plugging when the initial water-to-oil ratio (WOR) was below 60% (volume), even with hydrate formation. In contrast, plugging was observed above 60% WOR with less than 10 wt% methanol in the free water. Other multiphase oil pipelines (not shown in Figure 34) commonly plug with minimal WOR. The Norsk-Hydro authors suggest that behavior such as in Figure 34 illustrates a “natural” anti-agglomerant mechanism because, “the difference in plugging behavior is attributed to the type and amount of natural surfactants present in the oil or condensate. In general oils with little tendency to form stable emulsions have been observed to form hydrate plugs more easily than oils more prone to form stable emulsions.” Rule-of-Thumb 11. Use of anti-agglomerants requires a substantial oil/condensate phase. The maximum water to oil ratio (volume basis) for the use of an anti-agglomerant is 40:60 on a volume basis. The above rule-of-thumb is founded on two bases: 1. At higher WOR than 40:60, the water-in-oil emulsion may invert to an oil-in-water emulsion. If the water phase is external, hydrates will grow beyond small droplets. 2. Coal slurry transport technology provides a maximum ratio of coal : liquid vehicle of 40:60. Higher ratios increase the risk of having a non-transportable hydrate phase, similar to a non-transportable coal slurry.

46

Figure 33 - Anti-Agglomorants in Pipeline (From Sloan, 1998)

Without Anti-Agglomerantes

Condensate

Hydrate Plug

Condensate

With Anti-Agglomerantes

Condensate

Hydrates in Suspension

Figure 34 - Anti-Agglomerantes Effectiveness in Various Amounts of Water (From Lingelam et al, 1994)

100 Not Tested 90

No Hydrate Hydrate, No Plugs

80

Plugs

70

T = 0-4 oC

60 Watercut %

P = 70 bar

50

40

30

20

10

0 0

5

10

Wt% MeOH

15

At the French Petroleum Institute, Behar et al. (1994) provided three performance examples of an anti-agglomerant inhibitor in a two inch pilot loop, for a recombined crude, a gas saturated oil, and a gas saturated condensate with WOR ratios of 0.3, 0.3, and 0.1 ft3/ft3 respectively. The last case is shown with and without anti-agglomerant inhibition in the Figures 35 and 36, respectively. The gas consumption increases in both cases, indicating hydrate formation even with anti-agglomerant inhibition. However the loop pressure drop (an indicator of hydrate formation in a closed system) remains at a low value with inhibition (Figure 36), while it increases rapidly without inhibitor in Figure 35. A low pressure drop indicates that the effective viscosity is small and that the fluid components flow readily. Small amounts of surfactant are required relative to traditional inhibitors like methanol. Behar et al. (1994) indicate that 1 wt% of an emulsifier is equivalent to 25 wt% methanol. Economics should include such factors as surfactant cost, emulsion breaking, and recovery, and environmental considerations. Specific surfactants must be formulated and tested as emulsifying agents for each composition of condensate. Many surfactants have been shown to promote hydrate formation. Significant technology was transferred from earlier studies of enhanced oil recovery. Undocumented reports from Shell report an inhibition chemical which provides inhibition at an order of magnitude lower concentration than the IFP chemical, without being condensate specific. Reportedly, this additive allows the hydrates to form before taking them into the condensate phase; some environmental concerns persist. There is not a published commercial example of the use of an anti-agglomerant in an offshore hydrates application. Yet the method holds great promise, especially for deep, highly subcooled systems and shutdown with cold restart situations. Weaknesses of the method include toxicity concerns, the need to break emulsions, and the need to recover the expensive dispersant additive. Anti-agglomerant chemicals are proprietary and chemical structures, properties, and performance are not in the open literature. The next decade will undoubtedly see major advances in these chemicals.

II.G.2.b Kinetic Inhibition. Kinetic inhibition of hydrate growth has a different mechanism than that of anti-agglomerants. While there is evidence that the presence of a liquid hydrocarbon phase aids inhibition, kinetic inhibitors prevent hydrate crystal nucleation and growth without emulsifying in a hydrocarbon phase. Prevention of nucleation prevents hydrate crystals from growing to a critical radius. Growth inhibition maintains hydrates as small crystals, inhibiting progress to larger crystals. Figure 37 shows the most common measure of kinetic inhibitor performance. The line marked Lw-H-V represents the hydrate formation line, as predicted by the gas

47

Figure 35 - Hydrate Formation with Plugging (From Behar et al, 1994)

4

70 WOR = 0.1 Ft3/Ft3

3.5

60 50

3

Temperature 2.5

Pressure Drop

40

2 30 1.5 20

Plugging

1

10

0.5

0

0 0

10

20

30

40 Time (min)

50

60

70

80

Pressure Drop (Psia)

Temperature (oF); Gas Consumption (mMol)

Gas Consumption

Figure 36 - Anti-Agglomerants Preventing Plugging (From Behar et al, 1994)

70

4 Gas Consumption

60

3.5

Pressure Drop

50

3 2.5

40 WOR = 0.1 Ft3/Ft3

2

30 1.5 20

No Plugging

1

10

0.5

0 0

50

100 Time (min)

150

0 200

Pressure Drop (Psia)

Temperature (oF); Gas Consumption (mMol)

Temperature

Figure 37 - Subcooling as a Measure of Kinetic Inhibitor Performance (From Shuler, 1994)

Pressure (psia)

10000

∆T

1000

(Tsubcooling)

100

E

il qu

ib

m riu

L

(l we in

V H-

Cooling

Teq

Hydrate Onset (Tonset)

)

Start Experiment

10 20

40

60

Temperature (oF)

80

100

gravity curve (Section II.C) or by HYDOFF (Section II.D), with hydrate formation to the left and non-hydrate conditions to the right of the line. The horizontal line in Figure 37 represents a cooling curve for hydrate forming mixtures, such as may occur in a pipeline (Figure 7). The object of kinetic inhibition is to maintain the operating condition of a pipeline as far as possible to the left of the Lw-H-V line without formation of hydrate plugs during the residence time of the fluids in the flow line. In Figure 37, subcooling (∆T) is the measure of the lowest temperature that the system can be operated relative to the hydrate formation temperature at a given pressure. The maximum value of ∆T is determined by a laboratory and/or pilot plant experiment, and the pipeline is operated at a smaller value of ∆T. The value of ∆T appears to be pressure independent; however ∆T does depend upon the polymer, molecular weight, and the amount of salt, glycol, and alcohol present. Recent results suggest that water residence time can be as long as 30 days without hydrate formation, when the lowest temperature of the pipeline is at least 3oF less than the maximum subcooling (∆Tmax) with a good kinetic inhibitor. Kinetic inhibitors are commonly polymers with several chemical formulas shown in Figure 38. Each of the chemicals has a polyethylene backbone, connected to pendant groups typically containing an amide (-N-C=O) linkage, frequently within a five- or seven-member ring. As the inhibitor adsorbs on the hydrate crystal, the pendant group penetrates specific sites (cages) of a hydrate crystal surface while the polymer backbone extends along the surface. In order to continue growing, the crystal must grow around the polymer; otherwise crystal growth is blocked. Figure 39 is a schematic of one type of kinetic inhibition. Adsorption of three kinetic inhibitor polymer strands are shown on a hydrate crystal surface. The “filled stars” on each polymer strand represent the pendant groups which dock at the “empty star” sites on the hydrate crystal surface. As indicated on the figure, the subcooling ∆T is directly proportional to the liquid-crystal surface tension (σ), but inversely proportional to the length (L) between polymer strands. If the amount of polymer adsorption increases, the distance L between the strands decreases, resulting in an increased subcooling ∆T performance. Conversely, if the amount of inhibitor adsorption decreases (due to depletion by multiple small hydrate crystals) the distance L between polymer strands increases, resulting in a smaller subcooling ∆T. One of the first kinetic inhibitors developed was polyvinylpyrrolidone (PVP), a polymer whose structure is shown in Figure 38. Several companies have adopted the use of PVP in onshore fields with a small subcooling (∆T) and short residence time. Initial field tests of kinetic inhibitors were reported by ARCO (Bloys et al., 1995) and Texaco (Notz et al., 1995). Bloys reported the effectiveness of 0.3-0.4 wt% VC-713 in a 17 day test in a North Sea pipeline. The pipeline (8 in. diameter, 9.4 48

Fkure 38 - Formulas of Some Kinetic Inhibitors (From Sloan, 1998)

PVCap

H3C

vc-713

‘N’CH3

Figure 39 - Polymer Adsorption in Hydrate Crystal (From Larsen, 1994)

tal ys

L

Cr

L

Po

lym

er

Su

rfa

Ch

ce

ain

4σ ∆T ≤ C⋅L

km long) had a flow rate of 20 MMscf/d, 0.5 bbl/MMscf condensate and 0.2 bbl/MMscf condensed water at a subcooling between 1oC and 9oC. Bloys suggested that economics were very favorable for new developments, but marginal for retrofits of systems with traditional inhibitors such as monoethylene glycol. Texaco’s Notz et al. (1995) indicated successful use of polyvinylpyrrolidone (PVP) in several wells and flow lines in Texas and in Wyoming, concluding that PVP was in routine use in some Texaco fields. Notz further reported that PVP (at less than 1 wt%) was effective in replacing methanol (at concentrations from 10 to 60 wt% in free water) resulting in savings of as much as 50%. See Texaco Case Studies C.13 and C.14 in Appendix C. Rule-of-Thumb 12. PVP may be used to inhibit pipelines with subcooling less than 10oF for flow lines with short gas residence times (less than 20 minutes). Rule-of-Thumb 12 comes from Texaco’s Reliability Engineering: Gas Freezing & Hydrate Study, a handbook for field personnel by Todd et al. (1996) which reflects Texaco operating kinetic inhibitor practice with approximately 30 flow lines from their Brookeland field. Kinetic inhibitors more effective (but more expensive per pound) than PVP (illustrated by the other chemical formulas in Figure 38) have a seven-member ring pendant group in place of the five-member PVP pendant ring. The better kinetic inhibitors provide additional subcooling with long water residence times. Rule-of-Thumb 13: VC-713, PVCap, and co-polymers of PVCap can be used to inhibit flow lines at subcooling less than 18oF, with water phase residence times up to 30 days. Rule-of-Thumb 13 comes from commercial use of kinetic inhibitors, as indicated in the below case study. _____________________________________________________________________ Case Study 7: North Sea Use of New Inhibitors On July 22, 1996 British Petroleum (BP) initiated continuous commercial use of kinetic inhibitors (called threshold hydrate inhibitors, THI) in flowlines in the West Sole gas export lines (Argo et al, 1997). This followed from an extensive set of field trials carried out in the Ravenspurn to Cleeton wet gas line (Corrigan et al., 1996). BP began THI use in a 16 inch I.D., 13 mile long pipeline from three Ravenspurn platforms to Cleeton. At the time of the trial the maximum flow rate was 195MMscf/d. For the purpose of the trial the flow rate was cut back to 90mmscf/d to put the line as far into the hydrate region as possible (16oF of subcooling). Three trials were carried out, all of which were successful. The trials included extensive periods of

49

shut-in, up to 7 days with successful restart. A typical water production rate was 1.6 bbl/MMscf with a line pressure of 1088 psia and a low temperature of 48oF. The THI dose rate was 3000-5000 ppm based on the free water phase. See Corrigan et al. (1996) for further details. Currently two lines (24 inch and 16 inch I.D., 35 miles long) from West Sole A,B, and C and Hyde are being inhibited with THI. Water residence times can be as long as 2-3 weeks, and the lines are 11oF inside the hydrate region at operational conditions. The gas is very lean producing very little condensate. Water content is low and free water comes mainly from condensation. Due to the low amounts of water and condensate, this is an atypical case, but nonetheless represents a severe test for kinetic inhibitors. Water production from all four West Sole platforms is 150-200 bbl/d, or about 0.3 bbl/MMscf with 250 MM scf/d total produced from the 3 West Sole platforms and the remainder from the Hyde platform. The condensate rate is also 0.3 bbl/MMscf. The THI pumping rate per platform is 2-3 liters/hr of solution which contains about 15wt% active ingredient. The target injection rate is 3000 ppm based on the free water phase. _____________________________________________________________________

II.G.3. Guidelines for Use of Chemical Inhibitors Table 5 is a stepwise protocol to determine whether the use of inhibitors might be suitable, modified from the original suggestions by Edwards of BP (1997) and T R Oil Services (Grainger, 1997). It should be emphasized that, before field application, experimental data should be obtained, particularly if kinetic inhibition is being considered. The below protocol provides preliminary steps for such experiments.

_____________________________________________________________________

Table 5. Guidelines for Use of Kinetic or Thermodynamic Inhibitors 1. If the field is mature, record the current hydrate prevention strategy. Record the existing or planned procedures for dealing with an unplanned shutdown. Provide a generic description of the chemistry of the scale and corrosion inhibitors used. 2. Obtain an accurate gas, condensate, and water analyses during a field drill test. Estimate how these compositions will change over the life of the field. Estimate the production rates of gas, oil, and water phases over the life of the field. 3. Generate the hydrate pressure-temperature equilibrium line with several prediction methods. If the operating conditions are close to the hydrate line, confirm the prediction with experiment(s).

50

4. Determine the water production profile over field life (see Table 6 example). 5. Consider the pipeline topography along the ocean floor to determine where water accumulations will occur at dips, resulting in points of hydrate formation. 6. Simulate the pipeline pressure-temperature profile using a simulator such as OLGA or Pipesim to perform hydraulic and heat transfer calculations in the well, flow lines, and separator over the life of the field. 7. Determine the water residence times in all parts of the system, especially in low points of the pipeline. 8. Estimate the subcooling ∆T (at the lowest temperature and highest pressure) relative to the equilibrium line over all parts of the system, including fluid separators and water handling facilities. List the parts of the system which require protection. 9. If ∆T < 14oF, consider the use of kinetic inhibitors. If ∆T > 14oF, consider the use of standard thermodynamic inhibitors or anti-agglomerants (no one has used antiagglomerants commercially as of January 1, 1998). 10. Perform economic calculations (capital and operating expenses) for four options (a) drying, (b) methanol, (c) monoethylene glycol, and (d) kinetic inhibitors. 11. Determine if inhibitor recovery is economical. 12. Design the system hardware to measure: (a) temperature and pressure at pipe inlet and outlet (b) water monitor for rates at receiving facility, and (c) the below chemical check list a) Has the inhibitor been tested with systems at the pipeline temperature and pressure? b) Consider the environmental, safety, and health impact of the chemical. c) Determine physical properties such as flash point (should be < 135oF), viscosity ( should be <200 cp at lowest T), density, and pour point ( should be >15oF). d) Determine the minimum, maximum, and average dosage of inhibitor. e) Determine the storage and injection deployment methods. f) Determine the material compatibility with gaskets, seals, etc. g) Determine compatibility with other production chemicals. h) Determine the compatibility with the process downstream including cloud point, foaming, and emulsification tendencies.

51

At an early stage in the inhibitor design process it will be worthwhile to consider obtaining laboratory data and involving a service company to provide field support of process hydrate inhibition. _____________________________________________________________________ Hydrate inhibition occurs in the water phase and is dependent on the amount of water production and the salt concentration. Because the amount and concentration of pipeline water depends heavily upon produced water, reservoir engineers should provide the best estimate of produced water and salt concentrations over the life of the field. The second source of water, condensed water, can be estimated from gas water content as illustrated in Section II.C.3.a and in Figure 10. Edwards also provided one possible scenario for water production over a field life, given in Table 6. The below scenario for a North Sea pipeline indicates a nonintuitive situation. The pipeline initially operates with a low inhibition need, in mid-life the pipeline requires inhibition, in the final stages of life, the pipeline does not require hydrate inhibition.

_____________________________________________________________________

Table 6. One Scenario for Pipeline Water Over Field Life 1. At the beginning of field life, water production may be low, so that only a small amount of condensed water can be responsible for hydrate problems. The field may be operating with a large subcooling ∆T, but low dosages of chemicals are required by low amount of water production. However, there are counter examples of fields which begin producing water early in their life. Only fluid measurements can assess this difference. 2. At field mid-life, water produced down the line (if there is no upstream separation facilities) will increase. Both produced water and condensed water may be substantial. Total water may double or triple, but the condensed water amount may be sufficient to dilute the solution to low salt concentrations, so that maximum inhibitor injection rates may be required. Over a field lifetime, typical salt concentration from produced water may vary from 0% to the reservoir concentration. 3. At the end of field life there may be 10 times as much water, but it is mostly saline production, Both the increase in water salinity and the pressure decline of the field may take the production fluids outside the hydrate P-T region. 4. As an example, one BP field is forecast to dip into and out of the hydrate formation region over its life. _____________________________________________________________________

52

II.G.4. Heat Management The discussion in this section has been excerpted from DeepStar reports CTR A601-a,b,c,d, CTR 223-1, from Aarseth (1997), and from discussions with Statoil researchers. The retention of reservoir heat is one of the most efficient means of hydrate prevention. Because all reservoirs contain water and because water acts as a heat sink due to a high heat of vaporization, fluids at the wellhead are typically at temperatures from 175oF to 212oF. When the reservoir fluid flows through a deep ocean pipeline with an outer temperature at 40oF, the temperature can quickly cool into the hydrate region as determined by the heat transfer coefficient (U) between pipe and ocean.

_____________________________________________________________________ Case Study 8. Pipeline Temperature with Heat Loss Figure 40 (from DeepStar Report CTR 223) shows an offshore pipeline temperature as a function of length, at various values of U, between the pipeline inlet temperature (140oF) and a separator 50 miles away. The pipeline in the figure was assumed to be 50% buried and had a water flow of 1,527 bbl/d, a gas flow of 30.76 MMscf/d, and an oil flow of 22,723 bbl/d. In Figure 40 the lowest, dashed line shows the temperature of the ocean with length. The upper lines represent the pipeline temperature with no heat loss through the pipe wall, with the temperature drop being due to expansion. However, with heat loss through the pipewall, the temperature drops dramatically. With overall heat transfer coefficients of U = 0.17 and U = 3.3 BTU/hr-ft2-oF, the separator temperature is 70oF or 50 oF, respectively. Hydrates can easily form at these temperatures, particularly at the higher pressures (densities) necessary to make pipeline transport economical. It is concluded that a lower heat transfer coefficient is needed to prevent hydrate formation. _____________________________________________________________________ The temperature profiles in the above case study are for a flowing pipeline. If the pipeline were shut-in, the system would rapidly cool to the ambient conditions represented by the dashed line at the bottom of Figure 40. At the low ambient temperatures, hydrate problems are particularly severe and blockages may occur, particularly when the system is re-started. If hydrates form in an insulated pipeline, the pipeline may be depressurized to achieve a hydrate equilibrium temperature just above 32oF, so that heat will flow into the hydrates from the ocean, which has a temperature around 40oF. In such cases, the insulation is a hindrance or barrier which prevents heat flow from the ocean, making

53

Figure 40 - Pipeline Temperature vs. Change in Heat Conductivity of Pipeline (From Deepstar CTR 223, 1995)

160 Little Heat Loss Through Pipewall

Pipeline Temperature (oF)

140 120

U=0.17 Btu/(hr ft2 oF)

100 Heat Loss Through Pipewall

80 60

Ambient Conditions 40

U=3.3 Btu/(hr ft2 oF)

20 0 0

50000

100000

150000 Pipeline Length (ft)

200000

250000

300000

hydrate dissociation much more difficult. As a consequence it is good operating practice to inject large quantities of MeOH or MEG into the pipeline before a planned shut-in. Hydrates can be prevented in pipelines by three types of heat control: 1. burying the pipeline to provide heating and insulation by the ocean floor, 2. insulating the pipeline, using non-jacketed insulation, pipe-in-pipe systems, and bundling systems, or 3. heating the pipeline. Pipeline burial is a good means of providing pipeline insulation and protection. The degree of insulation depends upon the thermal gradient in the earth along the pipeline route, the pipeline depth, and the water temperature. Expenses for providing a trench and burial system for pipelines may be very high, particularly at great depths. On the other hand, heat control systems through pipeline insulation or heating may be laid with the pipeline from a barge. Pipeline insulation and heating methods are given consideration in design, but insulation alone offer no protection for long-term shut-ins.

II.G.3.a Insulation Methods. Figure 41 shows the three categories of insulated pipelines: (a) non-jacketed, (b) pipe-in-pipe, and (c) bundled flowlines. The nonjacketed system (Figure 41a) consists of an insulated pipe with a coating. The minimum overall coefficient achievable with a non-jacketed system is 0.3 BTU/hr-ft2o F (CTR A601-a) and costs are typically $50-$300/ft. for pipes with diameters between 8 inches and 12 inches. The pipe-in-pipe (PIP) system (Figure 41b) is the most thoroughly tested of the three types. In this system the flow pipe is within an outer pipe, with either insulation or vacuum between the two pipes, sometimes aided by a reflecting screen in the annulus. With a 3-4 inch insulation layer, the PIP system can provide an overall heat transfer coefficient (U) of 0.14 - 0.6 BTU/hr-ft2-oF. Figure 41c, shows a bundled line with two or more flowlines and a start-up water line with an insulator, all in an outer casing. Bundles are fabricated on shore in lengths up to 10 miles and towed to their offshore position, currently at water depths of up to 5,000 ft. Overall heat transfer coefficients as low as 0.1 BTU/hr-ft2-oF can be achieved. Figure 42 (from DeepStar Report II CTR 223) shows the increase in temperature at the platform riser as a function of insulation thickness, with two pipelines flowing together compared to an individual flow, when each line has a water flow of 1,527 bbl/d, a gas flow of 30.76 MM scf/d, and an oil flow of 22,723 bbl/d. The addition of a second flowline can reduce the insulation thickness required to

54

Fipure 41 - PiFeline Insulation Methods (From Deenstar CTR A601-a, 1995)

Insulation

Insulation (Max. 3 in.)

Steel Flowline

A) Non-Jacketed Insulation System

B) Pipe-in-Pipe Insulation Svstem

Figure 42 - Riser Temperature vs. Thickness (From Deepstar CTR 223, 1995)

110 Flow to Each Pipeline 22,723 Bbl/day oil & condensate, 30.76 MMSCF/D gas, and 1,527 Bbl/D water

105

Temperature (oF)

100 95 Two Pipeline Flows

90 85 80

One Pipeline Flow

75 70 0.4

0.6

0.8

1

1.2

1.4

Insulation Thickness (inches)

1.6

1.8

2

obtain a given riser temperature, or the second flowline will provide a higher riser temperature for a given insulation. Figures 43 and 44 (from DeepStar Report CTR A601-a) compare the cost of the three above types of insulation for water depths of 6000 ft. over 60 miles at oil production rates of 25,000 and 50,000 bbl/d, respectively. If an average U = 0.3 BTU/hr-ft2-oF is required with a flowline pressure of 4000 psia, bundled flow lines are more cost effective. II.G.3.b Pipeline Heating Methods. DeepStar Report CTR A601-b concludes that, “where pipeline depth precludes depressurization below the hydrate formation pressure, heating may be the only option to clear a hydrate plug.” Yet as noted in Section I, heating a hydrate plug can be very dangerous. DeepStar Report CTR A601-c concludes that pipeline heating will be very expensive, “at least 1MW of power is required for a 20oC (36oF) increase of a 10 inch pipeline 15 miles long.” In the future Statoil will use heating more extensively in order to reduce the amount of methanol or other chemicals used. Bundles will be used in 1998, and direct heat thereafter. The Chevron/Conoco Britannia project will start in the North Sea in 1998 using a bundled line to heat fluids. The three common means of heat management are (a) bundling hot water lines (for 10 km and return) in production lines to prevent hydrate formation (b) Combipipe (shown in Figure 45) for induction heating, with current flowing through 3 cables outside of pipe but within insulation, with corrosion protection,), (c) direct electrical heating for 50-60 km long lines (shown in Figure 46) in which the pipeline is the primary conductor with a current return line at 1m in parallel to the pipeline. It should be noted however, that such heating tools are in the planning stage and commercial use has yet to be documented.

II.H. Design Guidelines for Offshore Hydrate Prevention The below hydrate prevention paradigm is a collection of Rules-of-Thumb which provide general guidelines for offshore design. These design Rules-of-Thumb are for hydrate prevention in the three parts of the system where hydrates most often occur (shown in Figure 47): the well, the pipeline, and the platform. Many of these guidelines result from Section III on Hydrate Remediation. 1. Before embarking on a hydrate prevention design, it is imperative to have a reliable hydrate equilibrium curve (Sections II.C and II.D) which represents the gas, oil/condensate, and water compositions over the life of the field. If possible the hydrate formation curve should be verified via an independent prediction or hydrate formation experiment. 2. Simulate the pressure-temperature profile in the well, flow lines and platform at the worst case (usually during winter months) over the life of the field. Estimate the

55

Figure 43 - Cost vs. Overall Heat Transfer Coefficent (Depth - 6000ft. Prod. Rate - 25,000 BOPD) (From Deepstar CTR A601-a, 1995)

900 14" Non-Jacketed 2x10" Non-Jacketed 14" PIP 3x8" PIP 3x8" Bundled 3x8" Vacuum Tube 3x8" Non-Jacketed 2x10" PIP 2x10" Bundled

800 700

Cost($/ft)

600 500 400 300 200 100 0 0

0.1

0.2

0.3 U-Value (Btu/hr-sqft-oF)

0.4

0.5

0.6

Figure 44 - Cost vs. Overall Heat Transfer Coefficent (Depth - 6000ft. Prod. Rate - 50,000 BOPD) From Deepstar CTR A601-a, 1995)

1200 18" Non-Jacketed 2x12" Non-Jacketed 18" PIP 3x10" PIP 3x10" Bundled 3x10" Non-Jacketed 2x12" PIP 2x12" Bundled

1000

Cost($/ft)

800

600

400

200

0 0

0.1

0.2

0.3 U-Value (Btu/hr-sqft-oF)

0.4

0.5

0.6

Figure 45 - Heating Through Bundling and Combi-Piping A) Bundled Pipeline

Hot Water Input Line

B) Combi- Pipe

Thermal Insulation

Insulation

Pipeline Pipeline

Flowline

Insulation Cold Water Return

Heating Cables

Pipewall with Corrosion Protection

Figure 46 - Direct Electric Heating

Electric Current

Pipeline 1 meter Current Return Wire

Electric Current

Figure 47 - Offshore Well, Transport Pipeline, and Platform DRY

COMP.

SEP.

Platform

Ocean

- Depth 6000 ft Well with X-Mas Tree

Transport Pipeline (2-60 miles in length)

Mudline

Downhole Safety Valve

Bulge from Expansion or Topography

Export Flowline

Riser

water residence times at all points in the system. Account for both normal cooling (e.g. in pipelines as in Example 2 of Section II.A) and Joule-Thomson expansions across restrictions (e.g. in wells, chokes, and control valves as in Section II.F). 3. Estimate the subcooling ∆T (at the lowest temperature and highest pressure) at each point in the process relative to the hydrate equilibrium curve. Hydrates may form in systems with subcooling ∆T’s less than 2-4oF. 4. Where subcooling is unavoidable, determine the type of hydrate inhibition, such as chemical inhibitor injection (Sections II.G.1, II.G.2, II.G.3, particularly Table 5), or heat management (Section II.G.4). Choose the inhibition method with regard to both prediction ability and operating experiences. Consider providing a heater prior to the platform choke and separator. 5. Eliminate subcooling points of likely hydrate formation. Design pipelines to minimize buckling and protrusions from mudlines which might promote cooling. 6. Design large pressure drops with either dry gas or expansions at high temperature points in the process. Where large expansions of wet gas are unavoidable, (e.g. at choke valves) provide methanol injection capability upstream of the restriction. 7. Eliminate points of water accumulation, such as upslopes in pipelines or “S” configurations in risers. Where pipeline topography ensures water accumulations (e.g. upslopes in lines, etc.) provide for frequent pigging and consider placing methanol injection prior to the accumulation points. 8. Eliminate points of hydrate accumulation from a mechanical perspective. Hydrate crystals in a line may be considered to accumulate (and plug) wherever light sand particles might accumulate, such as at blind flanges at turns, elbows, screens and filters, upstream of restrictions etc. Avoid unnecessary bends. Bend radii less than 5 times the pipe diameter should be avoided to facilitate coiled tubing entry. A riser tube radius should be from 20-80 ft. 9. With a high probability hydrates will form over the system lifetime. Provide hydrate remediation methods (see Section III for justification) in the design. a) For pipelines, safe remediation often implies depressurization from both ends of a hydrate plug. Optimally, multiple access points in a pipeline (see b) are invaluable in locating and remediating hydrate and paraffin plugs. Alternatively dual production lines should be used to provide for depressurization of wellheads from the upstream side of a pipeline plug. As a second best method, provide for depressurization through a wellhead service line (for corrosion, paraffin, or hydrate inhibitor injection) with bypass capability for checkvalve(s) at the point of injection. As a minimum

56

a spare flange and valve should be provided at the wellhead or manifold, so that depressurization can be done via connection to offshore production vessel (see ARCO Case Study 14 in Section III.C.1.b) Technology is not yet available for location of the end of plugs or the safe heating of plugs in ocean pipelines. b) Subsea access points should be considered at the well manifold and at 4 mile intervals along the pipeline, as shown in Figure 48. Such access points will facilitate (a) the location of a hydrate (b) venting of excessive fluid head from plugs in deepsea lines, (c) injection of hydrate inhibitors, (d) coiled tubing entry, and (e) pig launching. c) In wells, hydrate remediation occurs by approaching one end of a plug via chemical injection, depressurization, heating, or coiled tubing. Case Study 16 in Section III.C.3 indicates that normal well lubricators can be used at the swab valve with careful balancing of pressure. d) On the platform hydrate plugs may be located using tools such as a thermocamera (see Figure 54 of Section III.B.1.b). With the accurate location of the plug ends, remediation may be done through chemical injection, heating, or depressurization.

57

Fiqure

48

Yorkover

-

Pre-Installed

(From

Deepstar

Access

A-208-1,

Ports

on

1995)

PipeLine

Vessels \

access Port Coiled

Functions

Tubing

Entry

-Surface -suLxeo.

Inject

Vent

Fluid

Fluids

Into

From

Pipeline - Hydrate Renoval

Pipeline

I

III. Hydrate Plug Remediation Perhaps the best way to remove a hydrate blockage in a flow channel is to use the experience of those who have removed similar blockages. In addition to those case studies in the body of the handbook, Appendix C details 27 case histories of hydrate removal in flow lines. Table 7 provides an overview of Appendix C case histories. Rule-of-Thumb 14: Hydrate blockages occur due to abnormal operating conditions such as well tests with water, loss of inhibitor injection, dehydrator malfunction, start-up, shut-in, etc. In all recorded instances1 pipeline plugs due solely to hydrates were successfully removed and the system returned to service. No pipelines were abandoned or replaced due to a hydrate plug, as is sometimes the case for paraffin plugs. However since every hydrate plug is unique, individual case studies are anecdotal in nature. A very large number of anecdotal studies is required before detailed remediation Rules-of-Thumb can be stated with confidence. Fortunately three systematic studies of hydrate plugs provide substantial guidelines for remediation. In 1994 Statoil purposely formed/removed over 20 hydrate plugs in a 6 inch gas/condensate line over a 9 week period (Case Studies C.15,16,17 in Appendix C). During 1995-6 uninhibited plug formations were studied as baselines for new inhibitors. DeepStar IIA Report A208-1 Methods to Clear Blocked Flowlines (December 1995) was compiled by Mentor Subsea to document 16 hydrate blockage cases and 39 paraffin blockage cases. In -February 1997 SwRI (Hatton et al., 1997) formed and dissociated hydrates in a Kerr-McGee field line, resulting in three significant tests (Case Studies C.25,26,27) with extensive instrumentation at five pipeline points. Much of the information in Section III on hydrate remediation was excerpted from the above three systematic studies, supplemented by the literature and personal interviews relating to hydrate blockages. The section is organized to provide answers to the following questions: III.A. How do Hydrate Blockages Occur? III.B. How Can Hydrates be Detected? III.C. How Can Hydrate Plugs be Removed? III.D. What Remediation Questions Remain to be Answered?

1

An exception was the LASMO Staffa subsea field in the North Sea, which was abandoned in 1995 due to low production problems with combined waxes and hydrates. See Case Study C.6. for further history on this field, which included a 1 mile flowline replacement.

58

Table 7 Summary of Hydrate Blockage Experiences in Appendix C

Case/Operator

Field/ Region

Line Size

Line Type

WD (ft)

1. Placid

GC 29

16"

Gas Cond.

200 ft

Time

Extent of Control Method Operations Restriction before Plug before Plug

1989 Complete

None

Flowing

Removed?

Current Prev. Method

Depressurize

Gas Dehydration MeOH Inj.

2. Chevron

Wyoming

4"

Gas Cond.

0

Winter Complete Heating Tape &

Flowing

Insulation 3. Chevron

GOM

Gas Lift

0

Winter Complete

None

Depressurize Heat MeOH

Flowing

Inj. MeOH

Inj. Lines 4. Chevron

Oklahoma

4"

Gas Sales

MeOH Inj.

Inj. MeOH Vary Flow Rate

0

1995

Partial

None

Depressurize

Remove Restriction

Inj. MeOH

@ Flow Meter

Heat Gas

MeOH during Winter

5. Chevron

Canada

6"

Gas cond.

0

Winter Complete

None

Export

Shut in for

Depressurize

Depressurize after

Several Days

Heat w/

24 Hours S/I

Welding Rig 6. Lasmos

North Sea

8"

Multiphase

?

1994 Complete

MeOH

Flowing

Replaced 2km

Same as before

blocked section Planning to abandon 7. Texaco

8. Texaco

9. Texaco

GB 189

GC 6

2-3/4"

3/4"

North Sea 1/4"

Gas

Gas

Instrament Valve

725 ft

600 ft

-

1995 Complete

1992

Partial

Complete

None

None

None

Flowing

Flowing

Flowing

Depressurize

Inj. MeOH

Inj. MeOH

Gas Dehydration

Depressurize

Inj. MeOH

Inj. MeOH

Gas Dehydration

Inj. MeOH

Occasionally Inj. MeOH

Case/Operator

Field/ Region

10. Elf Norge N.E. Frigg

Line Size

Line Type

WD (ft)

Time

16"

Gas Cond.

-

1990

Extent of Control Method Operations Restriction before Plug before Plug Partial

MeOH

Flowing

Removed?

Current Prev. Method

Depressurize

MeOH Injection

Inject MeOH 11. Marathon

EB 873

-

Gas Export 800 ft

1995

partial

Inadequate

Flowing

MeOH 12. Philips

Maintain

MeOH

MeOH Inj.

Depressurize

MeOH Inj.

MeOH Inj.

Dehydrate Cond.

Depressurize

Comb. of KI

Cod N. Sea 16" Gas & Cond. Export

-

1978 Complete

MeOH

Pig Stuck

Pigging 13. Texaco

Inject more

Wyoming

-

Gas

0

1995 Complete

MeOH

Field Test

and MeOH 14. Texaco

East Texas 4"-6"

Gas

0

1995 Complete

MeOH

Field Test

Depressurize

Comb. of KI and MeOH

15. Statoil

Tommeliten

6"

Gas Cond.

-

1994 Complete

MeOH Inj.

(Experimental) North Sea

Flowing/

Depressurize

Continue

Shut-in/

Inj. MeOH

MeOH Inj.

Re-start 16. Statoil

Tommeliten

6"

Gas

11.5 km 1994 Complete

MeOH

Field Study

Condensate 17. Statoil

Tommeliten

6"

Gas

Depressurize Inj. MeOH

11.5 km 1994 Complete

None

Field Study

Depressurize

MeOH

Flowing

Depressurize

Ensure Proper

MeOH Inj.

MeOH Inj.

Condensate 18. Oxy

North Sea

-

Gas Condensate

-

-

Complete

Field/ Region

Line Size

Line Type

WD (ft)

Time

Case/Operator 19. Amoco

North Sea

-

Gas Export

NA

-

20. Petrobras

Brazil

-

Manifold

NA

-

Extent of Control Method Operations Restriction before Plug before Plug Complete

Complete

None(Dry)

Ethanol

Flowing

Start-up

Removed?

Current Prev. Method

Depressurize

Ensure

MeOH Inj.

Dehydration

Depressurize

Drain Manifold of

Ethanol Inj.

Water before Start-up

21. Exxon

California

-

Well

NA

1989 Complete

None

Drilling

-

-

22. Exxon

Gulf of Mex

-

Well

NA

1989 Complete

None

Drilling

-

-

23. Exxon

S. America

-

Well

NA

1993 Complete

None

Testing

Coiled Tubing

-

Hot Glycol 24.Exxon

Gulf of Mex

-

Well

NA

1993 Complete

Methanol

Shut-in

Abandoned

25. Kerr-McGee Wyoming

4"

Gas/Condns Land

1997 Complete

Methanol

Shut-in

Depressurize

26. Kerr-McGee Wyoming

4"

Gas/Condns Land

1997 Complete

Methanol

Shut-in

Depressurize

27. Kerr-McGee Wyoming

4"

Gas/Condns Land

1997 Complete

Methanol

Shut-in

Depressurize

III.A. How Do Hydrate Blockages Occur? Figures 3 and 47 in Section II each show a simplified offshore process between the well inlet and the platform export discharge. Section II.A illustrates hydrate prevention design where virtually all hydrates occur - namely in (a) the well, (b) the pipeline, or (c) the platform. Before the well, high reservoir temperatures prevent hydrates; platform export lines are dry, with insufficient water to form hydrates. The system temperature and pressure at the point of hydrate formation must be within the hydrate stability region, as determined by the methods of Sections II.C. and II.D. In order for hydrates to form, the system temperature and pressure must first enter into the hydrate formation region, either through a normal cooling process (Example 2 and Figure 6 and 7) or through a Joule-Thomson process (Section II.F). The rate of hydrate formation region is a function of the degree of subcooling (∆T see Figure 37 in Section II.G.2.b) relative to the hydrate formation line. Hydrates can form with subcooling ∆T’s less than 2-4oF, particularly in industrial systems with contaminants like sand, weld slag, etc. present to serve as nucleation centers. However, hydrates with such a low degree of subcooling will form more slowly than in systems which have a subcooling of 10oF or more.

III.A.1 Concept of Hydrate Particle and Blockage Formation. All natural gas hydrates are approximately 85 mole% water and 15% natural gas. Hydrate formation always occurs at the hydrocarbon-water interface, because this 85:15 ratio is far in excess of the solubility of gas in the bulk water (< 0.06 mole %) or water in the bulk gas (< 4%). This exceptionally low mutual solubility is the result of water hydrogen-bonding (see Sloan, 1998, Chapter 3). When hydrate particles occur in a static system, a solid hydrate shell forms an impenetrable barrier at the hydrocarbon-water interface which prevents further contact of the hydrocarbon and water phases. Diffusion through the solid is extremely slow and hydrate fissures or cracks provide the only means for further contact of the water and hydrocarbon. Due to the hydrate formation barrier at the interface, natural gas hydrate particles have water as an occluded phase. Infrequently, when gas is bubbled through water, gas is the occluded phase within a hydrate shell. In an turbulent system such as a pipeline, high agitation rates provide for surface renewal, which can form hydrate particles and agglomerations to build up and obstruct pipe flow. Such a build-up is one major concern of this section. Rule-of-Thumb 15: In gas-water systems hydrates can form on the pipe wall. In gas/condensate or gas/oil systems, hydrates frequently form as particles which agglomerate and bridge as larger masses in the bulk streams.

59

Rule-of-Thumb 15 was obtained through multiple studies on flow loops/wheels at Statoil’s Research Center in Trondheim, Norway. In gas systems, water may splash or adsorb on the pipe wall where hydrate nucleation and growth may occur. In an oil/condensate system, the light hydrocarbon liquid above the water prevents splashing and causes hydrate particle formation and agglomeration at the liquid-liquid interface. In a black oil system, often only a small amount (less than 5 volume %) of water forms hydrates, but all the water and condensate are trapped in the open, porous system and can form a blockage (Urdahl, 1997). In Statoil’s Tommeliten Field blockages formed from a hydrate slurry with < 1 volume % of the water present. Such results are fluid dependent; while some oil/water systems convert to hydrates almost immediately with fairly low water conversion, other oil systems are more difficult to convert, but practically all water might be transformed to hydrates. Rule-of-Thumb 16: Agglomeration of individual hydrate particles causes an open hydrate mass which has a high porosity (typically >50%) and is permeable to gas flow (permeability to length ratio of 8.7 - 11 × 10-15 m). Such an open hydrate mass has the unusual property of transmitting pressure while being a substantial liquid flow impediment. Hydrate particles anneal to lower permeability at longer times. Rule-of-Thumb 16 was obtained through both field and laboratory studies at Statoil’s Tommeliten Gamma field and SINTEF’s research center (Berge et al., 1996). Plug porosity is determined by forming conditions and fluid effects; some plugs can have porosities considerably higher than 50% while other plug porosities can be considerably lower. Because liquid surface tension is much higher than that of gas by about a factor of 1000, hydrate plugs are much less permeable to liquid than to gas. Figure 49a from Lingelem et al. (1994) of Norsk Hydro is a schematic of the case of hydrate formation along the wall periphery in a gas system. This slow buildup of hydrates along the wall may be characterized by the gradual increase in line ∆P witnessed in 2 of 3 DeepStar field tests in a Wyoming gas-condensate line (Hatton et al., 1997). Figure 49b shows the case of hydrate formation as agglomerating or bridging particles in a condensate or oil system, providing the open, porous structure. The Statoil experience suggests that Figure 49b represents the more common case in hydrate formation. However, there are two schools of thought about hydrate formation; (1) the gradual buildup of hydrate formation on the walls, resulting in the less porous plugs seen in a few, thoroughly instrumented DeepStar field tests (See Case Studies C.25, C.26, and C.27) and the multitude of Statoil studies which suggests a high porosity, bridging hydrate structure may be the norm (See Case Studies C.15, C.16, and C.17).

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Figure 49a - Hydrate Accumulation in Gas Pipeline (From Lingelem et al, 1994)

Gas Pipeline Flow

Hydrate

Water

Figure 49b - Hydrate Accumulation in Condensate Pipeline (From Lingelem et al, 1994)

Initial

1 Hour

3 Hours

5 Hours

Partial Plug

Complete Plug

Condensate Pipeline

Hydrate Plug

The state-of-the-art of hydrate studies in field pipelines is too small to determine the causes and frequency of either type of hydrate buildup. It is apparent from the small number of studies however, that a wide range of hydrate porosities may be attained. The porosity/permeability of hydrate plugs largely determines their remediation. For example, if a hydrate plug is depressurized from only one end, flow through the plug will cause Joule-Thomson cooling just as in Example 11, so that the downstream side of the plug may be in the hydrate formation region at the lower temperature. This effect has been observed at the Tommeliten field (Berge et al., 1996) and provides both technical and safety reasons for depressuring a plug from both sides. However, Case Studies C.25, C.26, and C.27 detail safe techniques for depressuring one side of a hydrate plug in DeepStar Wyoming field studies by SwRI (Hatton et al., 1997). Figure 50 shows two types of pressure drop (∆P) increases which occur with hydrate blockage of lines. At the left, Figure 50a shows the gradual increase in ∆P which would occur if hydrates formed an ever-decreasing annulus as shown in Figure 49a. Figure 50b shows the more typical case of multiple spikes in ∆P before the final plug forms; these spikes indicated that particles are forming blockages and releasing, as depicted in the agglomeration of particles in Figure 49b.

III.A.2 Process Points of Hydrate Blockage. The above conceptual picture of hydrate formation reinforces field experiences regarding points in the process shown in Figure 48 where hydrate formation occurs. For example, subcooling will occur with pipeline protrusions from mudlines so dips in pipelines should be minimized. Large pressure (e.g. at orifices/valves) should be avoided. Points of water accumulation, such as “S” configurations in pipelines or risers, should also be minimized. Where pipeline topography ensures water accumulations (e.g. upslopes in lines, etc.) one may consider providing pigging inhibitor injection points to accommodate the accumulation. Hydrate particles in a line may be considered to accumulate (and plug) wherever light sand particles might accumulate, such as at blind flanges at elbows, short radius bends, screens and filters, upstream of restrictions etc. It is often unavoidable to design and to operate hydrate-free systems. In such cases it is important to identify likely points of hydrate formation, so that hydrate prevention (or dissociation) can be addressed in the original design or in system operation through dehydration, heating, inhibitor injection, depressurization or mechanical removal.

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Figure 50 - Pipeline Pressure Drops Due to Hydrates Atypical

50b)

Typical

Pipeline Pressure Drop

Pipeline Pressure Drop

50a)

Time

Time

III.B. Techniques to Detect Hydrates. When partial or complete blockages are observed in flowlines, questions always arise about the plug composition. Is the blockage composed of hydrates, paraffin, scale, sand, or some combination of these? Such questions are more easily answered with line access, as on a platform where a number of detection devices (e.g. thermocamera, gamma ray densitometers, or acoustic sensors) can be used as indicated in Section III.B.1. Indications of the blockage composition are obtained through combinations of (1) separator contents and pig (sphere or ball) returns as direct indicators and (2) line pressure drop as an indirect indication. Separator contents and pig returns provide the best indication of pipeline contents and should be regularly inspected, even when blockages are not a problem. Separator discharges and the pig trap provide valuable information about line solids such as hydrates, wax, scale, sand, etc. and may be used as an early warning of future problems. A less direct flow indicator is line pressure drop buildup, which differs for hydrates and for paraffins. Pressure drop increases are usually more noticeable than flow rates changes. With the exception of hydrate formation from gases without oil/condensate (with a typical pressure drop schematic in Figure 50a), hydrates usually cause a series of sharp spikes (Figure 50b) in pressure as hydrate masses form, agglomerate, and break, prior to final blockage. With paraffins the pressure buildup is more gradual, as deposition on the periphery of the pipe wall causes a gradual increase in line pressure drop. Pressure changes immediately before the blockage should be studied in addition to such things as fluid slugging, gas/oil ratio, water cut, reservoir pressure, and choke setting, all of which can affect the flow and pressure drop. When blockages occur in wells it may be difficult to distinguish the cause. Frequently only heating or mechanical means are available to detect the plug source. In flowlines and in wells, solid blockages of scale, rust, sand, etc. are less readily detected and removed than hydrates or paraffins, so treatment for the more solid plugs should be considered as when hydrate and wax treatments fail. In this section on detection of hydrate blockages, Section III.B.1 considers early warning signs of hydrates, and Section III.B.2 considers methods to determine the center and length of the plug. A significant amount of material in this section was obtained from DeepStar IIA Report A212-1, Paraffin and Hydrate Detection Systems, by Paragon Engineering and Southwest Research Institute (SwRI) (April 1996). Another major resource was the Statoil Hydrate Research/Remediation group, who contributed through in-depth interviews (July 13-15, 1997); this group has more field experience in hydrate remediation than any other at present, perhaps by an order of magnitude.

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III.B.1. Early Warning Signs for Hydrates. Unfortunately no indicator gives a single best warning of hydrate formation. Frequently the pressure drop in a line, commonly thought to provide the best warning, is wholly inadequate for reasons given in Section III.B.1.a. Instead a suite of indicators should be used to provide the best early warning before blockages occur. Of the three portions of the offshore process where hydrates form blockages, early indicators of well formation are least developed. Hydrates in a well are most often announced by abrupt flow blockages, accompanied by a high pressure drop. In normal operation however, the well temperature is high enough to prevent hydrate formation. It is only during abnormal operations such as start-up, shut-in, testing, beginning gas lift, etc. that hydrate formation becomes a problem. When hydrates form without warning in a well, the engineer turns to Section III.C, “Techniques to Remove Hydrate Blockages.” Early warning methods in the subsea pipeline (Section III.B.1.a) and platform (Section III.B.1.b) are discussed independently below. However, even with the methods listed in this section, there is a significant need for better hydrate detection. III.B.1.a Early Warnings in Subsea Pipelines. There are four methods for warnings of hydrate formation in a subsea pipeline: (1) pigging returns, (2) changes in fluid rates and compositions at the platform separator, (3) pressure drop increases, and (4) acoustic detection. Each method is discussed in the following paragraphs. (1) Pigging Returns. Periodically a flexible plastic ball or cylinder called a “pig” is pressure driven through pipelines to clear them of condensed matter. The pig’s trip is initiated via a “pig launcher” and ended by a “pig catcher or receiver”, with the debris swept from the pipeline into a “pig trap”. A detailed DeepStar II CTR 6401, Pipeline/Flowline Pigging Strategies, by H.O. Mohr Research and Engineering, Inc. (August 1994) provides a tutorial of this technology. Frequently hydrate particles are found in pig traps before hydrate blockages occur in pipelines, providing notice of the need for corrective action, e.g. increased methanol injection. For example hydrate particles may occur when they have been suspended in an oil or condensate with a natural surfactant, such as the Norsk Hydro oil shown in Figure 34 and accompanying discussion in Section II.G.2.a. Statoil’s Gullfaks subsea installation may have undergone several start-ups with hydrate present, but without problems (Urdahl, 1997) before a blockage in January 1996. Rule-of-Thumb 17. A lack of hydrate blockages does not indicate a lack of hydrates. Frequently hydrates form but flow (e.g. in an oil with a natural surfactant present) and can be detected in pigging returns.

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Pigging returns should be carefully examined for evidence of hydrate particles. Hydrate masses are stable even at atmospheric pressure in a pig receiver or catcher discharge. The endothermic process of hydrate dissociation causes released water to form an ice shell, which provides a protective coating to inhibit rapid dissociation (Gudmundsson and Borrehaug, 1996). However, it may be very expensive to provide pigging, either via a mobile pigging vessel over the well or from the well head without round-trip pigging capability. Such costs make examinations of pigging returns an infrequent luxury. (2) Changes in Fluid Rates or Composition at Platform Separator. When the water production rate is small it may be possible to monitor the rate of water production as an indication of hydrate formation. If the water arrival decreases appreciably at the separator, hydrates may be forming in the line. _____________________________________________________________________ Case Study 9. Separator Water Rate as an Indicator of Hydrate Production. In a controlled experiment, British Petroleum formed hydrates in a 14.5 inch I.D., 13.7 mile long gas line in the southern North Sea. Corrigan et al. (1996) reported that prior to the trial water arrived at the separator in the amount of 1.3 bbl/MMscf. The test was started at the time marked “Day 1” in Figure 51. After methanol injection was stopped, the separator water arrival stopped completely after about 30 hours (no increase in water volume), while gas flow rates remained steady and pressure drop did not change. The first significant increase in line pressure drop (to 2.4 bar in Figure 52) was observed 46 hours after the start of the test. A further rise in ∆P to 3.3 bar was noted after 3 days. Seventy-four hours after the start of the trial, large fluctuations in the gas flow rate were observed that were concurrent with further increases in ∆P. A large slug of liquid, presumed hydrates, arrived at the slug catcher at the trial conclusion. BP estimated 50 metric tons of hydrate were formed before methanol injection was resumed. _____________________________________________________________________ The above case study is evidence that separator water rate provides an early indication of hydrate formation in a gas line with almost no oil/condensate and little water production. When water production is substantially higher, it may be difficult to monitor changes in separator water arrival for an early warning (Todd, 1997; Austvik, 1997). Statoil’s Gjertsen (1997) suggested that changes in gas composition provide an early indication of hydrate formation. In a rich gas field in the Norwegian sector of the North Sea, chromatograms showed a removal of hydrogen sulfide (H2S) from sour gases as hydrates form. Hydrates particularly denude H2S from natural gases, due to

64

Figure 51 - Water Production for Wet Gas Line (From Corrigan et al, 1996)

Volume (barrels) in slugcatcher vessel

300 Water arriving as slugs - water simultaneously being processed from slug catcher

250 Sphere Arrived

200

Water processed from slug catcher

High DP MeOH Injected

150

100

Hydrate slug entering slug catcher

Water arrival @ 0.6bbls/mmscf

50

Water processed Start of Trial

0 0

1

2

3

4 Time (days)

5

6

7

8

Figure 52 - Differential Pressure Due to Hydrate Blockage (From Corrigan et al, 1996)

70

60 Differential Pressure (psi)

High DP maintained while hydrate melts, slug flow.

High DP due to hydrates. MeOH Injected.

50

40 Normal line DP at a flow rate of 9 mmscf/d

30

20

10 0

1

2

3

4 Time (days)

5

6

7

8

the near-optimal fit of H2S in the small hydrate cavities (see Sloan, 1998, Chapter 5). The same statement is not true about the other acid gas, carbon dioxide. (3) Pressure Drop Increases. Pressure drop (∆P) will increase and flow rate will decrease if the pipe diameter is decreased by hydrate formation at the wall in a gas line. Since ∆P in pipes is proportion to the square of turbulent flow rates, the change in ∆P is more sensitive than the change in flow. With hydrates however, a large restriction may be necessary over a long length before a substantial pressure drop occurs. For example, if a hydrate decreased the effective pipe diameter from 12 to 10 inches over a 1000 foot section, the ∆P would only increase 0.05 psi with 10 MM scf/d of gas operating at 1000 psia and 39oF. In addition, the ∆P trace usually contains substantial noise, making it difficult to observe trends. Statoil’s Austvik (1997) suggested that, while a gradual pressure increase in hydrate formation will occur for gas systems, a gradual pressure increase is not typical for a gas and oil/condensate system. In gas and oil/condensate systems, Statoil’s experience is that, without advance warning the line pressure drop will show sharp spikes just before blockages occur. Figure 52 shows the BP field experiment (Corrigan et al., 1996) with methanol stoppage in a North Sea gas pipeline with little condensate or free water; in that figure step changes and spikes in ∆P are more prevalent than a gradual increase. In contrast, recent DeepStar Wyoming trials (Hatton et al., 1997) show both gradual and spiked pressure drops, in a gas-condensate field. In Case Studies C.25, 26, and 27 the pressure built gradually upstream of a plug, while pressure spikes downstream indicated hydrate sloughing from the wall, with agglomeration and bridging downstream. However, the DeepStar tests had five pressure sensors spaced at intervals of a few thousand feet. As indicated in the calculation two paragraphs earlier, with only two pressure sensors at either end of a line, severe hydrate wall buildup must occur in order to sense a significant pressure drop, due to the dampening effect of the gas. Most pipelines are likely to experience hydrates as sudden, extreme pressure drops. (4) Acoustic Sensing Along Subsea Pipeline. DeepStar IIA Report A212-1, Paraffin and Hydrate Detection Systems, by Paragon Engineering and SwRI indicates: “The only hydrate crystal detection instrumentation suitable for subsea use identified by this survey is sand monitoring instrumentation...In a limited number of laboratory tests, the Fluenta acoustic sand monitor has detected hydrates. However, a detailed study using the Fluenta monitor has not been conducted.” A typical acoustic sensor from Fluenta is shown in Figure 53. Over 280 units have been installed to detect sand impingement on pipe by clamping the unit onto the flow line downstream of a 90o elbow or 45o bend. At flow rates as low as 3 ft/sec the

65

Figure 53 - SAM

400s Pwtide

Detector

(From Deepstar IIA A212-1,1995)

Underwater Electronic

Mateable

Stainless

Connection

Cable

Length

-

TBO

Steel

Pad

unit can detect 50 micron sand particles. Such units are rated for water depths of 4000 ft. and may be diver-assisted or ROV installed with an underwater cable. Acoustic sensors quantify the “hail on a tin roof” sound typical of hydrate particles impinging on a wall at a pipeline bend. However, this unit has yet to be field tested in a subsea application. The initial background note of the Paragon Engineering and SwRI (April 1996) study presets a caution which still exists: “This survey did not identify any proven hydrate or paraffin deposition measurement instrumentation for subsea multiphase flow lines or any other type of fluid transmission lines. For gas transmission lines, ultrasonic instrumentation has worked in specific applications and for single-phase liquid or gas lines, an acoustical/pigging system has been proposed.”

III.B.1.b Early Warnings Topside on Platforms. In addition to the above four types of subsea early warning systems, two methods are suitable for detection of hydrates on a platform, where piping and equipment are more available: (5) thermocamera, and (6) gamma-ray densitometer with temperature sensing. (5) Thermocamera. A thermocamera is a hand-held device which measures the infrared spectral transmission as an indicator of system temperature. Since water absorbs infrared transmission, the thermocamera is typically used topsides on a platform with air between the detector and the suspected hydrate plug. Statoil’s hydrate group provided a thermocamera picture of a hydrate plug, just beyond a short radius bend in a topside riser, as shown in Figure 54. The original color picture provided better temperature discrimination than the black and white reproduction presented here. While this blockage is obviously not an “early warning,” the picture is indicative of the instrument’s ability. As hydrate deposits build and as restrictions cause gas expansion, the low temperatures enable portable thermometers to be used in detecting plugs and potential plug points topside. A thermocamera enables determination of temperature variations in the system, particularly at points where hydrates might form but a thermocouple is typically not provided, such as downstream of a valve. The thermocamera is very sensitive to pipe coating, variations in wall thickness, pipe roughness, etc. After location of low temperatures the engineer can determine whether the system is in the hydrate formation region, to consider corrective actions such as insulation, heat tracing, inhibitor injection etc. (6) Gamma-ray Densitometer with Temperature Sensing. A gamma-ray densitometer uses an emitter and sensor on opposite, external pipe walls. The transmission of gamma-rays to the sensor is a function of the density of the pipe

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Figure 54 - Thermocamera Picture of Hydrates in Horizontal Portion of Riser Topside (From Austvik, Statoil)

contents. This technology is over 50 years old, and is commonly used in the chemical industry for level control in high pressure, non-visual systems. Because densities of hydrates and water are very similar gamma-ray densitometry alone cannot discriminate between the two; at best gamma-ray measurements indicate changes in conditions which could be hydrates. In combination with the temperature downstream of the densitometer (such as at the platform start-up heater as shown in Figure 55) hydrate formation can be discriminated. Hydrates are indicated by a low temperature in addition to an increase in density, whereas the water temperature is similar to that of gas. A high density and low temperature mass in the pipeline is likely to be hydrates, whereas a slug of high density but without a temperature drop is probably water. As shown in the blockage removal Section III.C, even small pressure reductions cause hydrate dissociation, which results in heat being removed from the condensed phases and lower temperatures. The temperature sensing requirement makes it difficult to use the densitometer subsea, due to high hydrate plug velocities damaging thermowells.

III.B.2. Detection of Hydrates Blockage Locations. The two objectives of locating the plug are: (1) to determine the distance from the platform from a safety perspective, and (2) to determine the plug length. In this section three DeepStar reports [(1) A208-1 Methods to Clear Blocked Flowlines, by Mentor Subsea (12/95), (2) A212-1 Paraffin and Hydrate Detection Systems, by Paragon Engineering and SwRI (4/96), and (3) Hydrate Plug Decomposition Test Program by SwRI (Hatton et al., 10/97)] were supplemented by Tommeliten field experiments by Statoil. Unfortunately there is no precise way to locate the blockage, so the methods involve both art and science. The efficiency of hydrate blockage location schemes is governed by the topology of the system and by the hydrate porosity shown in Figures 49a,b and Rule-of-Thumb 16, with accompanying discussion. The early warning methods of Section III.B.1 should be first considered to see if they apply. Additional methods to determine hydrate blockage locations are: a) Filling the line/well with an inhibitor or mechanical/optical device, b) Pressure location techniques: reductions, increases, fluctuations, and c) Measuring internal pressure through external sensors. A recommended composite blockage location method is given in III.B.2.d.

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Figure 55 - Platform Use of Gamma Densitometer

Thermocouple

Start-up Heater

Platform Choke

Gas

From

Pipe

line

Gamma Densitometer

1st Stage Separator

Platform

To Comp./Dehydration

III.B.2.a. Filling the Line/Well with an Inhibitor or Mechanical/Optical Device. When hydrates block a flowline, it is common to fill the line with an inhibitor, particularly when the blockage is close to the platform. The blockage and the line topology may prevent the inhibitor flow from reaching a blockage far from a platform. There is some disagreement about whether methanol or glycol should be lubricated into the line, and both are used. Since the density of methanol is low, the higher density glycol (and sometimes brine) is preferred. The inhibitor injection volume enables the determination of blockage location relative to the platform, given the line size and a knowledge of liquid retention within the pipeline. In each of the following case studies, the operator was fortunate to reach the hydrate plug with an inhibitor. In most cases this method is ineffective. ____________________________________________________________________ Case Study 10. Methanol Lubrication into an Export Line. Texaco reported a restriction in a 12.75 inch gas export line from a platform at Garden Banks Block 189 in 725 ft. of water. The export gas was insufficiently dehydrated and water condensed at a low point in the line, where hydrates rapidly formed. The hydrate blockage was removed by venting from the platform and injecting methanol down the riser. Hydrates completely melted after a total of twenty to thirty 55 gallon drums of methanol were used. _____________________________________________________________________ Rule-of-Thumb 18: Attempts to “blow the plug out of the line” by increasing the pressure differential will result in more hydrate formation and perhaps line rupture due to overpressure. When a hydrate blockage is experienced, for safety reasons, inhibitor is usually injected into the line from the platform in an attempt to determine the plug distance from the platform. Such a volumetric determination assumes the plug to be impermeable to the inhibitor and that the liquid hold-up in the line is known (or negligible). Both may be incorrect since hydrate accumulations push substantial liquids ahead of the plug. ____________________________________________________________________ Case Study 11. Monoethylene Glycol Lubrication into Well Tubing. An operator experienced a blockage in a multi-phase flow stream in the Gulf of Mexico, extending inside tubing inside a deepwater riser connection between the platform and the seafloor, from two hundred feet below, to several hundred feet above the seafloor. The well was being cleaned in preparation for production. The well contained 4-5wt% CaCl2 completion brine. After hydrocarbon flowed from the well for a few hours, the well had to be shut-in for two days due to bad weather, but methanol was not injected prior to shut-in. A gas hydrate plug formed which held a differential pressure of 1000 psi without movement.

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A coiled tubing (see Section III.C.4) was run down the tubing string and ethylene glycol was jetted to remove the blockage. Jetting operations took two days, and the entire remedial operation took one week to complete. ____________________________________________________________________ For hydrates in a well, Statoil has used a broach similar to that shown in Figure 56, lowered on a wireline to determine the blockage depth. A similar wireline heating tool has been used by Statoil for hydrate dissociation in wells; in this case, the hydrate blockage can be located and dissociated with the same tool. Heating a hydrate blockage is not recommended, unless the end is determined, for safety reasons shown in Figure 2b and accompanying discussion. However, when the hydrate end is discernable, heating from one side of the blockage may be a viable option. In a flowline a wireline, reach rod, coiled tubing, or fiber optics may be used to locate a plug. However, this detection method is currently limited to the first 10,000 ft. from the platform and requires mechanical intervention in the flowline.

III.B.2.b. Pressure Location Techniques: There are three pressure techniques to locate a hydrate blockage which are performed on the platform side of the plug: (1) pressure reduction, (2) back-pressurization, and (3) pressure fluctuations. Each technique has advantages and disadvantages. Pressure Reduction. This simple technique takes advantage of hydrate porosity by decreasing the downstream pressure and monitoring the rate of pressure recovery and the rate of pressure decrease of the upstream side of the plug. Figure 57 shows an flowline obstruction one-third the way between the platform and the well. If the pressure is suddenly decreased downstream, the rate of downstream pressure recovery should be one-half the rate of upstream pressure decrease. With low porosity plugs patience may be required, as illustrated in the following case study. ____________________________________________________________________ Case Study 12. Depressurizing the Blockage for Location. In January 1996 Statoil experienced a hydrate blockage in a black oil system in a 6 inch I.D., 1 mile-long line in the Gullfaks field. The normal oil rate was 18,000 ft3/d, the water rate was 16,242 ft3/d, and the GOR was 100-360 scf3/scf3. The normal line operating pressure was 2420 psia and the hydrate equilibrium pressure (at the low temperature) was 261 psia. With the well shut in, the downstream pressure at the platform was rapidly reduced to 1670 psia. Figure 58 shows blockage upstream and downstream pressure response (note expanded scale). Over a 25 hour period, the upstream pressure decreased about 73 psi while the downstream pressure increased the same amount. It was concluded that the plug was located mid-way in the pipe. See Case Study 15 (Section III.C.1.d.) for the removal of this Statoil plug.

69

Figure 56 - Wireline Broach to Dete ,rmine Hydrate Location in Well (From S tatoil)

Figure 57 - Hydrate Location In a Pipeline

Distance L Plug Upstream

Downstream

2/3 L

1/3 L

Figure 58 - Pressure Change Used to Estimate Plug Location (From Gjertsen et al, 1997)

2420

1760 1750 1740 1730

2380

1720 2360

1710 1700

2340

1690

2320

1680

Subsea Pressure

1670

Topside Pressure 2300

1660 0

5

10

15

Time (hours)

20

25

Topside Pressure (psig)

Subsea Pressure (psig)

2400

Two points should be emphasized about this case study: (1) safety and (2) rate. First, the small diagnostic pressure reduction was made from one side of the plug, well above the hydrate dissociation pressure, to prevent safety problems associated with a plug projectile (Section I) propelled by a high differential pressure. Second, pressure recovery was very slow, averaging about 3psig/hr. This slow rate may not be noticed if pressure is not carefully monitored by platform personnel, who may be inclined to discount a slow changes. The slow rate of pressure change was thought to be due to the fact that most of the line contained liquid, causing the apparent plug porosity to be about 1000 times smaller than that for gas flow. ____________________________________________________________________ Statoil, the company with the most methodical, documented experience in hydrate remediation, prefers the above method of plug location. The method locates the blockage center and the relative volumes upstream and downstream of the blockage(s). The disadvantage of the method is that it does not give any idea of the length of the blockage, how close the blockage is to the platform (due to the unknown plug porosity), or how multiple plugs may affect this location determination. Statoil locates the plug-platform proximity by inhibitor back-injection (see Rule-of-Thumb 18) or by back-pressurization, as shown in the following method. Pressure Increase. To locate a complete pipeline blockage one method is to measure the pressure increase as metered amounts of gas are injected at the platform. The rate of pressure increase is correlated to the rate of gas input to determine the length for a given diameter line between the platform injection point and the blockage. ____________________________________________________________________ Example 13. Back-Pressurization to Determine Plug Location. An offshore 16 inch ID gas pipeline is in full production when a hydrate plug occurs, blocking flow for a 0.6 gravity gas. The line is shut-in and the pipeline cools to the ambient temperature of 39.2oF. Before hydrate dissociation can begin to take place, the approximate location of the plug end should be obtained to determine the best remediation method and evaluate safety concerns. One standard location procedure is back-pressurization. This method consists of pumping a known amount of gas into the pipeline and measuring the change in pressure over time. From these pressure values, an estimate of volume can be obtained through PV=ZnRT. The following assumptions are made for the problem: 1. no porosity of the plug, 2. no liquid in the pipeline, 3. none of the injected gas condenses, 4. constant temperature throughout the pipeline,

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5. the heat of gas compression is dissipated rapidly, and 6. the pipeline is initially at atmospheric pressure. A reciprocating pump on the platform is used to inject gas at a rate of 4.89 lbmole/min into the pipeline, so that the pipeline pressure slowly increases. The heat of compression is assumed to be dissipated in the ocean and the entire temperature remains at 39.2oF. The time required for the pipeline to attain even increments of pressure (e.g. 400, 600, 850 psia, etc.) are measured and these data can be used to estimate the pipeline volume downstream of the plug via the equation: PV = ZnRT → V =

ZnRT P

where Z = gas compressibility as a function of P,T, and gas composition. Values obtained through an equation-of-state or from gas gravity compressibility charts (Figures 23-7,8,9 of the GPSA Engineering Handbook (1994)) n = value obtained from data (data table below) P = corresponding pressure for n (data table below) R = 10.73 (Universal Gas Constant in units of psia, oR, lbmol, ft3) T = 498.87oR (seafloor temperature) Five data points are averaged to estimate the volume of the pipeline between the hydrate plug and the platform. The first data point calculation is as follows: A line pressure of 400 psia is attained after 60.76 minutes when 297 lbmoles of gas have been pumped into the line. The gas compressibility is estimated at 0.915 from Figures 23-7,8,9 of the GPSA Engineering Handbook (1994). The pipeline volume is estimated as: ZnRT (.915)(297)(10.73)(498.9)=3637 ft 3 V= → P (400) The first estimate of the pipe volume down stream of the plug is 3637ft3. Estimated Pipeline Volumes Between Platform and Plug Data Point # Time (Minutes) Pressure Est Volume (psia) (ft3) 60.76 400 3637 1 96.58 600 3664 2 144.39 850 3667 3 198.61 1100 3662 4 300.01 1500 3663 5 Avg Volume (Platform to Plug

71

3658

This same calculation is summarized for four other data points, in the above table. The average approximation for the volume after the hydrate plug was 3658ft3. The cross-sectional area of the pipeline is calculated, in order to estimate the pipeline length between the plug and the platform. The pipeline cross-sectional area is A=

 1 ft 2  πD 2 π 16 2  =1.396 ft 2 = =201.06in 2  2  4 4  144in 

Since the pipeline volume = (length)(cross-sectional area), the estimated location of the plug is 2620 feet (= 3658ft3/1.396ft2) away from the platform. ____________________________________________________________________

Back-pressurization has been implemented many times in the field and is probably the method of choice of many operators. However, there are several disadvantages which cause significant inaccuracies, as follows: 1. Because hydrate plugs are frequently porous (>50%) and permeable, they transmit flow and act as a “leak” in a system considered to be a closed (i.e. no permeability) 2. The gas compressibility must be well-known in order to determine the pressure and volume rate increases. 3. The liquid hold-up in the line must be known. This is particularly a disadvantage when significant elevation changes result in unknown liquid holdup profiles, or when the hydrate plug has accumulated liquid in front of it. 4. The location of multiple plugs cannot be addressed by this method; only the plug located nearest the point of injection can be determined. Due to the above inaccuracies, the method of back-pressurization should be supplemented by other methods, as listed in the Section III.B.2.d. Pressure Variation. Pressure pulse travel time and pressure frequency response methods to locate a hydrate blockage are discussed in DeepStar IIA Reports A208-1 and A212-1. Both methods involve measurement of sound wave travel time or frequency changes from the platform to the blockage. However these analyses have not been successful to date due to two factors: 1. acoustic response is a function of the relative amounts of gas and liquid, which are usually unknown and may occupy portions of a pipeline. 2. reflected pulses are dampened by walls, valves, bends, and by a flexible plug.

III.B.2.c Measuring Internal Pressure through External Sensors. A technique recently developed is to measure hoop strain of the pipe as a function of line pressure to determine the location and type of blockage. An ROV places a metal caliper clamp on 25% of the pipe circumference using magnets, as shown in Figure 59a. The 72

Figure 59 - Hydrate Plug Detection through Strain Measurement (From Deepstar A208-1, 1995)

59a)

Hydrate detection device which measures the amount of strain a pipeline undergoes under high pressure. A graph of strain vs. pipeline length is shown below. Hydrates are present where very little strain occurs in the pipeline.

59b)

Strain vs. Pipeline Length 8

Strain/Pressure(bar)

7 6 5 4 3 2 1 0 1

1.5

2

2.5

3

3.5

4

Relative Distance (km)

Clear

ViscoHard Elastic

Visco - Elastic

Clear

4.5

platform end of the flowline is pressurized inducing a hoop strain, sensed by the pipeline caliper. The internal pressure causes a hoop strain that results in an outward movement of the caliper which varies with the wall deposits of the pipe. Lack of hoop strain across a section of pipe would indicate a blockage. The signal is transmitted to a work boat at the surface. This method was successfully used in the North Sea on an 8-inch, 15 km long flow line. Results of the strain gage are shown in Figure 59b for 20 points at various lengths along a line blocked with paraffin. Points 13, 14, and 15 are shown to be blocked with hard plugs, between visco-elastic plugs (points 15-18 and 3-13) at either end. The map in Figure 59b was in agreement with the contents of the flow line when it was replaced. Recovery and deployment of each measurement required 1-2 hours. Due to necessity for ROV deployment, this method yet to be used to locate a hydrate.

III.B.2.d. Recommended Procedure to Locate a Hydrate Plug. There is no one precise method to locate the hydrate plug, so a combination of the above methods are indicated below for best results. 1. Estimate the hydrate formation temperature and pressure of the blockage relative to the conditions of the pipeline. Use a simulation to determine at what length the contents of the pipeline enter the hydrate formation envelope during normal operations. Confirm the simulation with a linear interpolation between the wellhead and platform temperature and pressure. This will provide an approximation of the plug initiation point, but with flow blockage the entire pipeline will cool into the hydrate stability region. This calculation should be done during initial line design. 2. Depressurize the platform end of the plug to about 2/3 of the pressure between the normal operating pressure and the hydrate formation pressure. Do not decrease the pressure on one side of the plug below the hydrate formation pressure. Monitor the rate of pressure increase at the platform and the pressure decrease at the wellhead for the lesser of (a) either 24 hours or (b) until a significant pressure change (e.g. 75 psig) is obtained at each point. Use the rate of pressure change at wellhead and platform to determine the center point of plug(s), or relative volumes at each end of the plug(s). 3. Fill the riser with inhibitor to attempt to determine the distance between the platform and the plug. This may be inaccurate due to pipeline elevation changes, etc. 4. Back-pressure the pipeline and monitor the pressure increase for a measured volume of gas input. Estimate the distance from platform to plug by the rate of pressure change, relative to gas input, for a given compressibility and simulated liquid retention volume. Use this technique with method 2 to determine volume before the plug. 5. With available resources, use a mechanical device to determine plug location.

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III.C. Techniques to Remove a Hydrate Blockage. Four techniques to remove a hydrate blockage are listed in order of frequency: 1. 2. 3. 4.

hydraulic methods such as depressurization (Section III.C.1), chemical methods such as injection of methanol or glycol (Section III.C.2), thermal methods which involve direct heating (Section III.C.3), and mechanical methods with coiled tubing, drilling, etc. (Section III.C.4).

Applications of the above methods can be further divided into three cases: (a) partial blockage, (b) total blockage without substantial liquid head, and (c) total blockage with a liquid head. The following discussions concern only the final two cases. It is assumed that any indication of a partial blockage will be promptly treated with massive doses of methanol, the most effective inhibitor. Combinations of the above methods are simultaneously tried. Rule of Thumb 19. Regardless of the method(s) used to dissociate the hydrates, the time required for hydrate dissociation is usually days, weeks, or months. After a deliberate dissociation action is taken, both confidence and patience are required to observe the result over a long period of time. Often it is suggested that corrective actions be changed almost hourly when immediate results are not observed. Rapidly changing corrective actions, results in “thrashing” without significant effects on plug removal. The “waiting” aspect of plug removal is frequently the most difficult for platform operating and engineering personnel, who are accustomed to producing results on a continuous basis. Typical times of days or weeks are required for plug removal as indicated by Appendix C case studies. Measurements such as pressure drop across the plug are continuously monitored and changed deliberately, only after some time has passed to gain assurance of initial method failure. Rule of Thumb 20. When dissociating a hydrate plug, it should always be assumed that multiple plugs exist both from a safety and a technical standpoint. While one plug may cause the initial flow blockage, a shut-in will cause the entire line to rapidly cool into the hydrate region, and low lying points of water accumulation will rapidly convert to hydrate at the water-gas interfaces.

III.C.1. Depressurization of Hydrate Plugs. This section shows that, from both a safety and technical standpoint, the preferred method to dissociate hydrate plugs is to depressurize from both sides. Depressurization is particularly difficult when the deepwater liquid head on the hydrate

74

plug is greater than the dissociation pressure. Before that point is addressed, a conceptual picture of hydrate provides some key points in the dissociation process. III.C.1.a Conceptual Picture of Hydrate Depressurization. When a hydrate plug occurs in an ocean pipeline, the pressure-temperature conditions are illustrated in Figure 60. To the left of the three phase (LW-H-V or I-LW-V) lines hydrates or ice can form, while to the right only fluids can exist. Because the lowest ocean temperature (39oF) is well above the ice point of 32oF, ice formation (which could block flows) is not a normal operating concern. When hydrates form, flow is blocked so that the plug temperature rapidly decreases to the ocean floor temperature of 39oF at the pipeline pressure. Figure 60 shows the pressure-temperature conditions of a pipeline hydrate plug at point A in the two-phase (H-V) region, in which liquid water has converted to hydrate. Pressure reduction is accompanied by a temperature decrease at the hydrate interface. If the pipeline is rapidly depressured without heat transfer, Joule-Thomson (isenthalpic) cooling (line AB) at the hydrate may worsen the problem. If the pressure is reduced extremely slowly, isothermal depressurization (line AC) results. Usually an intermediate pressure reduction rate causes the hydrate interface temperature to be significantly less than 39oF, causing heat influx from the ocean to melt the hydrate at the pipe boundary. With rapid or extreme pressure reduction, the hydrate equilibrium temperature will decrease far below 32oF, for example to -110oF for a methane hydrate depressured to atmospheric pressure. In this case water from dissociated hydrate will rapidly convert to ice below the solid-liquid line (I-LW-H shown in Figure 60). If ice formation occurs with hydrate dissociation, then the question arises, “How will the ice plug dissociation rate compare to the hydrate dissociation rate in an ocean pipeline?” In 1994-1997 field studies, over 20 hydrate plugs were intentionally formed and removed from a 6 inch North Sea line in the Tommeliten Gamma field. In both laboratory and field studies these plugs were found to be very porous (>50%) and permeable. Porous, permeable hydrates easily transmit gas pressure while still acting to prevent free flow in the pipeline. When the pressure was decreased at both ends of a highly porous hydrate plug, the pressure decreased throughout the entire plug to an almost constant value. The dissociation temperature at the hydrate front is determined by the pipeline pressure. The depressurization results in a uniform hydrate dissociation temperature which is in equilibrium with the LW-H-V line pressure in Figure 60, predicted by the methods of Section II.C and II.D. Pipeline depressurization reduces the hydrate temperature below the temperature of the ocean floor (39oF for depths greater than 3000 ft.). Heat flows radially into the pipe, causing dissociation first at the pipe wall as shown in Figure 61. Radial hydrate dissociation controls plug removal, because the pipe diameter (less than

75

Figure 60 - Isethalpic and Isothermal Plug Dissociation

A

B HYDRATES V I-H-

HLw

V

∆T = 0 C I-Lw-V

Pressure

∆H = 0

I-Lw-H

(From Kelkar et al, 1997)

ICE

Temperature

NO HYDRATES

Figure 61 - Radial Dissociation of Hydrate Plug A) Pipeline Cross Section

Heat

B) Pipeline Longitudinal View

Water

Heat

Heat

2 ft.) is typically at least an order of magnitude less than the length of a hydrate plug (frequently more than 50 ft.) in a pipeline. The radial dissociation concept presents a contrast to previous longitudinal dissociation concepts of non-porous hydrates, in which depressurization from both ends was supposed to result in dissociation progressing from the plug ends toward the middle (Yousif, et al., 1990; DeepStar Report CTR IIA A208-1, 1995). As diagrammed in Figure 62 when the temperature of the hydrate is lower than that of the ocean floor, heat flows radially into the system, causing dissociation along the entire length. Of course some plug dissociation occurs at the ends, but due to much smaller dimensions the radial dissociation (which occurs simultaneously along the plug length) controls blockage removal. Figure 62 shows a cross section of a pipeline hydrate plug that has been depressured to provide an equilibrium temperature just above 32oF. Such a pressure corresponds to about 450 psia for a pure methane gas, but much lower for a natural gas, as predicted by the methods of Sections II.C. and II.D. Figure 62a shows an inner hydrate core enclosed in a water layer, which results from hydrate melting. The water layer is adjacent to the pipe wall. Figure 62b shows the temperature profile from the ocean temperature of 39oF at the pipe wall, to the hydrate dissociation temperature (set by the line pressure to a point just above the ice point) where it remains uniform throughout the hydrate layer. As a result, the radial disappearance of the two-phase water+hydrate boundary (X1) determines the disappearance of the final solid and eliminate the flow obstruction. Because hydrate plug detachment occurs first at the pipe wall, a partiallydissociated plug will move down the pipeline when the line is re-started, only to result in a later plug at a pipeline bend, depression, or other obstruction. The second blockage by the plug can be more compact than the first, for example if there is substantial momentum on impact at the bend. This phenomena relates to Rule-ofThumb 19, indicating that one of the most important aspects of plug removal is patience to allow time for total dissociation. In the above conceptual picture, it is assumed that the pipeline is exposed to turbulent, deep ocean water so that the pipe wall temperature is constant at 39oF. If a line is insulated, hydrate dissociation becomes much more difficult because the insulation which prevented heat loss from the pipe in normal operation will prevent heat influx to the pipe for hydrate dissociation. Alternatively, if the pipe is buried in the ocean floor, the pipe wall temperature will be greater than 39oF, but only by an average of about 1oF per 100 ft. of buried depth. The cross section in Figure 63a shows a hydrate plug dissociation when the pressure is too low. An inner hydrate core is surrounded by an ice layer, that is enclosed in a water layer adjacent to the pipe wall. Figure 63b shows the temperature profile from 39oF at the pipe wall, to 32oF at the water-ice interface, to a lower hydrate

76

Figure 62 - Hvdrate Dissociation with Water Present _

Water To= 40°F -

Wall

Hydrate

Water

T, = 33°F

‘5 x? 4 Moving Boundary

-

To= 40°F

Wall

T,= 40°F

v-v~*FiMoving Boundaries

x

1

dissociation temperature (set by the line pressure) at the ice-hydrate interface, where it remains uniform throughout the hydrate layer. As a result, there are two two-phase boundaries: a slowly dissociating water-ice boundary (X 1), and a second, rapidly dissociating ice-hydrate boundary (X2). We are particularly interested in the rate of progress of X1, which determines the disappearance of the final solid (ice), since any solid phase constitutes a flow obstruction in a pipeline. Hydrate dissociation to a low pressure almost always results in an ice problem which may be more difficult to remove than the initial hydrate. Hydrate removal is accomplished by both depressurization and heat influx from the surroundings, while an ice plug removal must rely on heat influx alone. As a result an ice plug may dissociate more slowly than a hydrate plug. For example, if a 16 inch line containing only methane is depressured to atmospheric pressure, 85 days are required for radial dissociation of an ice plug, while only 17 days would be required for dissociation of a hydrate plug to water if the pressure was maintained at 450 psig. These calculated results are based upon the radial dissociation model of Kelkar, et al. (1997) in which radial dissociation prevails. Austvik (1997) noted some exceptions to radial dissociation, particularly for plugs of low porosity/permeability or for very long plugs. Plug permeability may decrease considerably during the first hours after plug formation; this suggests that plugs should be dissociated as soon as possible to take advantage of higher porosity.

III.C.1.b Hydrate Depressurization from Both Sides of Plug. There are two reasons for the preferred method of two-sided hydrate plug dissociation: 1. For a single plug, dissociation from both sides eliminates the safety concern of having a projectile in the pipeline. 2. Two-sided dissociation eliminates the Joule-Thomson cooling which may stabilize the downstream side of the plug. With radial dissociation along the plug, twosided dissociation is more than twice as fast as single-sided dissociation. For the above reasons, a hydrate plug should be dissociated through a second production line, if available. If this is impossible, depressurization through a service line for injecting inhibitors at the well head; in this case provision should be made for removing or bypassing the check valve in the service line at the well head. In some cases, as in Case Study 14, it may be worthwhile to connect a floating production vessel to the manifold or wellhead for depressurizing the upstream side of the plug. _____________________________________________________________________ Case Study 13. Gulf of Mexico Plug Removal in Gas Export Line. A hydrate blockage in the export line from Shell’s Bullwinkle platform in the Green Canyon Block 65 to the Boxe platform was reported in DeepStar Report A208-1 (Mentor

77

Subsea, 1995, page 52). The 12 inch, 39,000 ft. line was un-insulated line. Seawater temperature was 50oF at the base of the platform in 1400 ft. of water. Gas gravity was 0.7, without condensate. Flow rate was 140 MMscf/d at an inlet pressure of 800 psi. Gas hydrates formed during a re-start after the platform was shut down due to a hurricane. During the shut-in period the gas dehydrator was partially filled with water. After production was restarted, since the dehydrator was not cleaned out properly, it was not dehydrating gas as designed, and wet gas entered the export riser, causing water condensation and hydrate formation. A complete hydrate blockage formed in less than one hour, just past the base of the export riser at a low spot. To remove the blockage, the line was depressured on both sides of the plug. Then methanol was circulated into the line to accelerate the hydrate dissociation rate. After complete removal of the hydrates, the dehydrator was cleaned, inspected and restarted properly. The entire remedial operation required 36 hours to complete. The major cost was the lost production time. _____________________________________________________________________ When depressurization cannot be easily achieved from both sides of a plug, then more costly steps may be required to balance the depressurization to ensure platform safety, as indicated in the following case study. _____________________________________________________________________ Case Study 14: Removal of North Sea Hydrate Plug by Depressuring Both Sides. This case study is a remediation summary of hydrate blockage in an ARCO 16 inch, 22 mile long pipeline between a North Sea gas field well and platform. Plug Formation Setting The gas field is located in the southern North Sea and consists of three subsea wells, flowing into a subsea manifold with a capacity of four well inputs. A graphical representation of the field is shown in Figure 64. The well’s gas compositions, temperature, and pressure promote hydrate formation, consequently mono-ethylene glycol (MEG) is injected into the manifold and wellheads to thermodynamically inhibit hydrates. The inhibited water, gas, and condensate is then pumped through a 22 mile, trenched, insulated export pipeline to a processing platform where water is removed from the condensate. The MEG in the pipeline is recycled and piped back to the manifold via a 3 inch pipeline piggybacked to the export line. Blockage On April 14th, 1996 an unusually large liquid slug over-ran the platform primary separator causing a temporary shut down. The liquid slug was remediated, but complete blockage of the pipeline had occurred during shut-down. It was hypothesized that the blockage was a result of a hydrate plug. The reasons were:

78

Figure 64 - Offshore Platform and Manifold (From Lynch, 1996)

Host Platform Well

Well

36 km - 16” Export Pipeline

Manifold

Well Fourth Intake

• • •

•

The pipeline free water, recovered during depressurization at the platform, did not contain MEG inhibitor. The 3 inch MEG inhibitor line had ruptured. Through back-pressurization, the blockage was found to be 150 meters away from the platform. At this location, the pipeline was exited the mudline allowing contents to be rapidly cooled by ocean currents, causing hydrate formation. Slight decreases in pressure determined that the blockage had some porosity. This had also been observed for several Statoil hydrate plugs (see Tommeliten Field Case Studies C.15, C.16, and C.17 in Appendix C. In contrast however, two DeepStar field trials C.26, and C.27 formed low-porosity, low-permeability plugs which would transmit pressure very slowly and withstand high pressure drops.) The liquid slug which shut down the compressors probably was caused by a partial hydrate plug pushing a fluid front down the pipeline as it moved.

The blockage’s proximity to the platform posed serious safety concerns. Pipeline depressurization was necessary to dissociate the hydrate; however it had to be done on both sides of the hydrate plug. If only the blockage’s platform side was depressured, the pressure differential would cause a projectile to form which could destroy the riser piping and damage the platform. The projectile would be lifethreatening to workers on the platform and result in costly damages to the platform itself. Consequently, depressurization had to be done through both the platform and the subsea manifold to ensure safety. Projectiles could form due to dissociation, if gas became trapped within multiple plugs. Slow depressurization was required to remove pressure build-ups in the hydrate plug(s). Several methods were considered.

Depressurization Method Initial Ideas Three questions were raised to determine a proper depressurization method. 1. Will the remediation process effectively depressurize the pipeline? 2. What is the cost of equipment and modifications? 3. How much time is needed to complete the remediation? Based on these questions, process engineers, consultants, safety management, and diving specialists proposed three potential depressurization methods. They were: 1) Jack-up Rig. Method: Tow a jack-up rig to the site. From the rig, attach a high pressure riser to the manifold’s subsea tree and flare exiting gas via the rig’s flare stack. Modification: A spool piece would have to replace a non-return valve on the manifold’s fourth well intake. Time Required: A drilling rig was not currently available, consequently a delay of approximately eight weeks was needed to locate a suitable rig. The time required for hydrate removal could be twelve weeks. Estimated Cost: $1,980,000

79

Feasibility: The large amount of time required to locate a jack up rig made this an ineffective remediation method, useful in the absence of other methods. 2) MEG Injection Line Method: Connect the subsea manifold’s spare fourth flange to the 3inch MEG pipeline and flare gas at the platform. Modification: Subsea work would require a spool piece installed between the two pipelines. Secondly, a method of injecting methanol was needed to prevent future hydrate growth. The platform (while in operation) required significant modification to connect the MEG pipeline to its flare stack. To further complicate the matter, all of the MEG currently in the pipeline would need to be stored on the platform, which had limited storage space. Time Required: Six to eight weeks. Estimated Cost: Unknown, expected to be higher than the other methods based on the large amount of modifications that were required. Feasibility: Substantial modifications to the platform made this remediation method costly and impractical. It was deemed unusable in any circumstance. 3) Floating Production and Storage Vessel (FPSO) Method: Connect a FPSO with a processing plant and flare to the subsea manifold’s fourth flow loop and process the exiting gas. The connection between the manifold and FPSO would be made through a high-pressure, flexible riser. Modification: The platform required no modifications. A diving rig was required to do the subsea work. A valve skid containing both emergency shutdown valves (ESDV’s) and a MEG injection valve was also needed. The flexible riser and the manifold would be connected with a spool piece. Figure 65 is a schematic of the design. Time Frame: A FPSO was available for immediate use, consequently the required time was expected to be 6-8 weeks. Estimated Cost: $1,906,000. Feasibility: This method proved to be the most feasible. The immediate availability of a FPSO and diving rig allowed modifications to begin. It was estimated that the FPSO could be at the site and begin within two weeks. Establishing Procedures/Permits It took approximately two weeks to develop potential remediation processes. Procedures were then written to firmly establish the processes required for the pipeline depressurization. Procedures considered the safety, process, and coordination requirements between the diving rig and the FPSO. All parties were educated about the tasks involved. Government permits were applied for at the Health and Safety Executive Pipeline Inspectorate (HSE) and the Department of Trade and Industry Oil and Gas Office (DTI) for additional gas flaring and well modification. The permits were

80

Figure 65 - Preliminary Remediation Set-up (From Lynch, 1996) Collar Buoy FPSO FPSO process and flares exiting gas from the manifold

280 meter High Pressure Riser 5 Ton Clump Weight

Valve Sled

16” Export Pipe

Manifold

expedited by local agencies to prevent delay in hydrate removal. Two weeks were required to prepare procedures and permits for depressurization. In the meantime, the FPSO and diving rig were being equipped for the operation and moving to the field.

Depressurization of the Pipeline Operations The divers first task was to manually locate the subsea manifold’s fourth intake and to isolate it from any trees or flow loops. The fourth well intake was then modified with a spool piece for connection with the high-pressure riser. The valve skid was now ready to be put in place. Due to the sandy ocean bottom, it became necessary to provide a foundation for the valve skid. The valve skid was placed on a concrete mattress and then stabilized with gravel bag supports coupled with Tirfors, chain blocks, and ground anchors. This insured that no movement would transfer from the flexible riser to the valve skid. The valve skid contained ESDV’s and a MEG injection system for the pipeline. Figure 66 is a figure of the subsea valves and their attachment to the manifold. The diving rig then inspected the flexible riser route to ensure that is was clear of debris. It proceeded to deploy 920 ft. of the high pressure riser via a tugger rigged with a dead man’s anchor. The MEG in the riser provided some buoyancy, consequently the line was anchored through concrete mattresses. A five ton clump weight was placed at the bottom of the riser with a buoyancy collar attached to the surface. The FPSO could only process gas at 600 psig, consequently it required some modification to process the 1300 psig pipeline gas. Additionally, a quick-release valve (QVD) was needed to enable the FPSO to escape from the riser in case of an emergency. This complicated the design because current quick-release valves could not withstand pressures of 1300 psig. Initial design placed choke valves in the riser to reduce pressure for the quick-release valve, however this caused control problems and was deemed impractical. An innovative new quick-release valve was developed with a standard valve weak link with three additional hydraulic jacks for manual release. This valve could withstand 1500 psig of pressure, allowing choke valves to be placed on the ship’s deck which simplified control issues. This design enabled a safe, simplified, control of gas pressures from the deck of the FPSO. A description of the system is shown in Figure 67. The buoyancy of the riser prohibited pipeline intake through the FPSO’s moonpool. Spool pieces were used to allow riser intake from the side of the ship deck. The riser was also steam traced with 1000 ft. of 1 inch piping to maintain the minimum process temperature required by the FPSO.

81

Figure 66 - Valve Sled with Manifold Interface (From Lynch, 1994)

6” Manuli Riser

ESD Valves

ME

Manifold

GI nje ctio nL

Existing 1500 PSI Flange

Valve Sled

ine

Figure 67 - Design with High Pressure Quick-Release Valve (From Lynch, 1996)

Initial Design

Final Design

Low Pressure Quick-Release Valve FPSO

High Pressure Quick-Release Valve FPSO

Choke Valves

Choke Valves

The High Pressure QR Valve allowed choke valves to be placed on the deck of the FPSO. This design easied pipeline control tremendously.

Figure 68 is a complete picture of the FPSO attachment to the subsea manifold. All valves and risers were tested and shown to be in working order. Overall the modification and installment procedures required one week before pipeline depressurization could begin.

Determining the Pipeline Minimum Pressure Reducing pipeline pressure too much could result in ice formation. This causes significant problems because ice melting might have required significantly more time, than hydrate dissociation. Ice formation was prevented through use of the hydrate equilibrium curve (Figure 69) for the field. At constant low pressure, hydrates will continually dissociate, maintaining the equilibrium temperature at that given pressure. As the graph illustrates, the equilibrium pressure at 320F was 200 psig. To prevent ice formation, the pipeline pressure could not drop below 175 psig. Consequently, the FPSO reduced the pipeline pressure to 185 psig to maximize hydrate dissociation without ice formation. Depressurization Twenty three days were required to completely dissociate the pipeline hydrate. Heat transfer between the ocean and the pipeline was slow because the line was trenched and insulated in the sea floor. Dissociation was slightly facilitated by occasional back-pressuring which drew methanol into the plug. Back-pressuring also proved beneficial in determining the location of the plug. Figure 70 shows the pressures in the pipeline throughout the depressurization process. Note the slight pressure increases that occurred during depressurization. These formed as a result of gas pockets suddenly releasing as the plug was dissociated. The pressure was monitored for 12 hours after the hydrate was thought to be dissociated. No pressure variation was noticed so the flexible riser was recovered and the depressurization apparatus dismantled. Throughout the whole operation, no equipment failure occurred and the operation progressed smoothly. Recommissioning the Pipeline After the hydrate was dissociated, there remained significant amounts of free water in the pipeline. The pipeline had to be re-commissioned carefully to prevent reformation of hydrates. Above normal amounts of MEG were added to the system before pipeline start-up. One gas well was opened and the platform flow high to maintain low pressure, preventing hydrate formation. The high intake caused a high gas velocity which facilitated rapid water removal. The first 12 hour night shift reported 7000 ft3 of water received from the separator, the water which would result

82

Figure 68 - Complete FPSO/Manifold Interface (From Lynch, 1996)

Sea Surface

FPSO

Chute/Disconnec t Umbilical Manuli Hose Collar Buoy

Hose Clamp

Strops 34 km 16” Export Pipeline

Manuel Ball Valve

Manifold

Clump Weight Safety Valves

Figure 69 - Hydrate Formation Curve (From Lynch, 1996)

1400 1200

Pressure (psig)

1000

Hydrates

800 600 400

No Hydrates

200 0 30

35

40

45

50

Temperature (oF)

55

60

65

Figure 70 - Pressure of Manifold and Platform During Hydrate Remediation (From Lynch, 1996)

450 Platform

400

Manifold

Pressure (psig)

350 300 250 200 150 100 50 0 0

2

4

6

8

10 Time (days)

12

14

16

18

20

from a 1.25 mile long (non-porous) hydrate plug. The high flow rate of gas was maintained until the water contained 40% MEG, ensuring that the line was fully inhibited. The pressures and intakes were then returned to normal operating levels.

Conclusions The remediation team removed the hydrate plug efficiently. They achieved a monumental task in a very short period of time, preventing more severe economic losses. Figure 71 provides a timetable of the remediation process. The procedure and methodology followed could be applied to many different situations. Communication, clear objectives, and excellent resources helped in removing the hydrate plug. Despite the efficient remediation effort, the economic impact of the hydrate plug was substantial. The cost of depressurizing the pipeline was almost 3 million dollars, without counting lost production. On top of this, relations between the buyers and producers were tested, due to lack of production. Fortunately, good initial relations between the two reduced the impact of the disruption. This case study shows the potential financial loss that can result from hydrate plugs. Hydrate prevention is key in preventing significant economic and production losses. _____________________________________________________________________

III.C.1.c Hydrate Depressurization from Both Sides of Plugs with Significant Liquid Heads. Results similar to those of Case Studies 13 and 14 may not be applicable to very deep ocean plugs. When depressuring a multi-phase deepwater pipeline the hydrostatic pressure (or head) of the liquid against the face(s) of the plug may be higher than the hydrate dissociation pressure. However, the removal of fluids from each side of a hydrate plug may be difficult. To date there is little documented experience for depressuring plugs with liquid heads in deepwater lines. However the situation has been evaluated in light of most of the case studies in Appendix C, and recommendations are provided in Example 14. ____________________________________________________________________ Example 14. Methods of Fluid Removal in Plugged Deepwater Lines. This example abstracts an in-depth study of fluid removal as a preliminary step to depressurizing lines done in DeepStar Report A208-1 by J. Davalath (December 1995). Figure 72 shows the Lw-H-V equilibrium conditions for the Hercules and Jolliett fluid conditions in a 50 mile pipeline in 4000 ft. of water in the Gulf of Mexico. When a blockage occurs, if the gas is not vented, the temperature rapidly decreases to 40oF with a pressure between 2000-3000 psia (a subcooling of 30-33oF). After gas venting the pressure is still 1000-1300 psia, a factor of 5-6 times greater than the

83

Figure 71 - Schedule for Complete Plug Remediation (From Lynch, 1996) TASK NAME Orwell Pipeline Blocked

01

APRIL 08 15 22 4/14/96

29 06

MAY 13 20

27

JUNE 03 10 17

Attempts to move plug Development of Jack-up Rig Development of FPSO Decision Made Development of Detailed Design HAZOP/Safety Study FPSO-Manifold InterfaceFab. FPSO Modifications Subsea Installation FPSO Transit FPSO-Manifold Hookup Depressurization of Line Dissociation of Plug Pipeline Unblocked

6/2/96

MEG Injection w/ production Full Production Resumed

6/6/96

Figure 72 - Hydrate Formation Conditions (From Deepstar A-208-1, 1995) 3500 Hercules 3000

Jolliet Cool Down Conditions Before Venting Gas at Platform

Pressure (psia)

2500 2000

HYDRATES

1500 Shut-In Conditions After Venting Gas

1000

NO HYDRATES

500 Required Pressure to Dissociate Hydrate Plug

0 20

30

40

50

Temperature (oF)

60

70

80

equilibrium pressure (200 psia) at the ocean floor temperature (40oF) with a subcooling of 22oF. To initiate hydrate dissociation, the hydrostatic head must be removed below 200 psia, to about 150 psia where the equilibrium temperature is 25oF, slightly inside the ice formation region, so that a 15oF temperature gradient will cause heat to flow from the ocean to the hydrate. In a worst-case scenario, the entire volume from the platform to the manifold must be removed. Assuming only 70% of the pipeline volume is filled with liquid, the volume to be removed would be 12,000 bbls in an 8 inch line and 26,000 bbls in a 12 inch line 50 miles long. The techniques listed in Table 8 were considered for liquid head removal. All of the options in Table 8 require that the plug location be determined and that the pipeline have access points in order to remove the pressurizing liquid and plug. If there are no access points, the line will have to be hot-tapped. The figures in the example indicate that workover vessels need to be positioned above the plug. Of the seven options summarized in Table 8, those with gas lift were eliminated due to low liquid removal rates. None of the depressurization options were recommended; however, multiple access ports at 4 mile intervals were recommended with use of coiled tubing as described in Section III.C.4 on mechanical removal.

Table 8. Techniques to Remove Liquid Head Above a Hydrate Plug Option for Removing Liquids

Issues/Limitations

1. Multiphase Pumping to Surface (Figure 73) at a rate of 5000 BOPD to remove liquids in 3-6 days 2. Subsea separator; vent gas & pump liquid to surface 3. Gas lift pipes on each side of plug (Figure 74)

temporary deployment; electrical submersible pump; handle large liquid volume on workover vessel deploy separator/pump hardware subsea

4. Multi-phase pumping with gas lift 5. Combine subsea separator with gas lift 6. Displace with nitrogen from platform 7. Launch a gel or foam pig followed by nitrogen

84

extremely slow: 21 days to remove 12,000 bbl from 8” line; 25+ days to remove 26,000 bbl from 12 inch line similar issues to Option 1 too slow; similar issues to Option 2 requires large volumes of N2 at high P gel pigs separate gas and liquid; access point must be large enough to introduce pig

Fiaure

73

-

Pipeline Depressurization -Multiphase Pump Option (From

Ft.

Deepstar

Hydrate PLug 1 RCiV

A-208-1,

1995)

Methods

r ure 74 F (From Deepstar A208-1,' 1995)

4000 Ft.

An alternative to pumping the fluids to the surface is to discharge the fluids into a parallel, unblocked flowline. This method would require access points along the pipeline to locate the plug and remove the liquids to the parallel pipeline. _____________________________________________________________________

III.C.1.d. Depressurizing One Side of Plug(s). Rule of Thumb 20 indicates that multiple hydrate plugs should be assumed to exist in a shut-in line. With multiple plugs, substantial gas may be trapped between the plugs, and depressurization techniques should be similar to depressurization through one side of a plug. The overriding safety concern is that a plug might dislodge from the pipe wall to become a projectile which can rupture a line or vessel. Table 9 gives a procedure for depressurizing one side of a hydrate plug. A similar procedure can be used with multiple hydrate plugs when liquid heads exist on each side of the plug. DeepStar A208-1 presents Figure 75 to illustrate the situation to remove two hydrate plugs without an intermediate access point. In this case, it is assumed that there are multiple access points to the pipeline, so that the general position of the plug(s) can be located by pressure differential. The procedure in Table 9 was slightly modified from that proposed by the Canadian Association of Petroleum Producers , in Guideline for Prevention and Safe Handling of Hydrates (1994), and that proposed in DeepStar Report A208-1. ____________________________________________________________________ Table 9. Procedure for Depressurization of One Side of a Hydrate Plug, or Multiple Plugs without an Intermediate Access Port. When there is only the option to depressurize one side of a hydrate plug, there are two major concerns for plug removal: (a) that the plug may dislodge and be propelled in the pipe, becoming a severe safety problem (see Section I) as well as damaging equipment, and (b) because the plug is porous and permeable, JouleThomson cooling of gas flow may cause the downstream end to progress further into the hydrate stability region. The following depressurization procedure attempts to address both concerns. While depressurization is most often used for hydrate it is normally preceded by attempts to place inhibitor adjacent to the blockage; this is difficult because flow is restricted. 1. Depressurize the line by removing the fluids at a slow rate though access ports on each side of the plugs. If a substantial liquid head is present, the procedure to reduce the pressure could be one of the seven discussed in Example 14.

85

Fipure 75 - Suggested Procedure to Remove Multiple Hydrate Plums Pump rl

(From Deepstar A-208-1,1995)

r-l Pump

Depressurize at Slow Rate

Hydrate Equilibrium _______________________ _______ ______________________ Pressure

_ _ _ _ _ _ _, ____--;_---;_--__-___--__ Mamtam Pressure Slightly Below Hydrate Equilibrium Pressure

(For Controlled Dissociation

2. Before the hydrate dissociation pressure is reached, the pressure should be reduced slightly (e.g. 100 psia), via the access port valves. After each of several pressure reductions wait for the pressure to be equalized across the plug. Plug permeability and porosity permits pressure communication to determine gas volumes on each side. While the hydrate plugs are porous, as indicated in the Statoil Gullfaks case, pressure equalization may be as slow as 3 psi/hour if substantial liquid flows through the plug. 3. Maintaining a low ∆P across hydrate plugs will reduce the threat of a projectile by providing both a low driving force and a downstream gas cushion (See Example 15) for any dislodged plug. In addition a low ∆P across the plug minimizes JouleThomson cooling at the plug discharge end. 4. Reduce the pressure in stages to a level slightly below the equilibrium pressure, pausing for equilibration at each stage. Do not reduce the pressure below that required to reduce the hydrate equilibrium temperature below the ice point. If the pressure is reduced too substantially, an ice plug will result which may be difficult to dissociate. 5. If hydrates are dissociating (but remain in the line) the pressure will slowly rise to a level equal to the hydrate equilibrium pressure at the ocean bottom temperature. If hydrates have dissociated, the line pressure will remain below the hydrate equilibrium pressure. 6. When the plug completely dissociates there will be no ∆P across the section which had contained the plug and Section III.D. should be consulted for system start-up.

While the above method represents an ideal depressurization from only one side, frequently a non-ideal depressurization must be achieved, as in the following case study for a plug which had low liquid permeability, with a very low gas to oil ratio. It should be noted that liquid permeability through a hydrate plug is about a factor of 1000 lower than that of gas. ____________________________________________________________________ Case Study 15. Line Depressured from One Side for Hydrate Plug Removal. In January 1996 Statoil (Gjertsen et al., 1997) depressured a hydrate plug in a North Sea line which was alternatively used as a black oil producer and a gas injector to maintain reservoir pressure. The oil and water production rates were 18,000 ft3/day and 16,242 ft3/day respectively, and the gas to oil ratio was usually 100-360 scf/ft 3, a fairly low value. The line and plug location method is in Case Study 12 in Section III.B.2.b. Since the plug was about mid-way along the 1.6 mile pipeline, there was not an option of using an inhibitor because pipeline topology prevented inhibitor contact with the plug. Since there were no connections at the well the plug had to be depressurized

86

from the platform side only. By considering the hydrate formation curve it was determined that the plug equilibrium pressure was 261 psia but that ice would form when the pressure was below 115 psia. Figure 76 shows the depressurization of the line, with the upstream pressure, the platform pressure, and the pressure drop. During dissociation the pressure was decreased in steps, and a slow bleed through was observed from 0-73 hours, from 7390, 95-105 hours, and from 105 through 120 hours. During the time prior to 120 hours, the pressure was above the hydrate equilibrium pressure, and while the upstream pressure decreased steadily, it never decreased to the downstream pressure, indicating that the plug was not very permeable to black oil. A second mechanism was that the light oil ends may have been flashing to maintain a constant pressure upstream. However the increase in downstream pressure occurred much more rapidly as the downstream pressure was lowered, indicating that the plug was porous, even to the black oil. After about 120 hours the line pressure was maintained between 145 -261 psia downstream of the plug. The plug dissociated about 50-60 hours after the downstream pressure had been reduced sufficiently for melting by heat influx from the ocean. This was indicated by a sudden upstream pressure decrease from 1890 psig to 1160 psig, while the downstream pressure increased from 218 psig to 1015 psig during the same period. The pressure was decreased to 145 psig and kept there for over 30 hours to melt the remainder of the hydrates. Restart of the well (see Case Study 18 Section III.D) was accomplished two weeks after the original plug developed. This case is another indication of the long times required to remediate a hydrate plug. ____________________________________________________________________ Case Studies C.25, C.26, and C.27 in Appendix C are an overview of DeepStar Wyoming field studies of hydrate formation and dissociation from one side of the plug. These studies have the best instrumentation of any hydrate studies to date, and provide several exceptions to the concepts in this portion of the handbook. For example, in two of three cases, relatively impermeable plugs were formed, one of which withstood a ∆P of 475 psi and was propelled down the pipeline at a velocity of 270 ft/s. In each DeepStar field trial, depressurization was done gradually in stages from one side of a hydrate plug with prior testing to ensure that an absorbing gas “cushion” existed downstream. Where the hydrate plug existed upstream of an above-ground bend, angle, or valve, the test was aborted and the plug was depressured from both sides due to safety reasons. In depressuring one side of a hydrate plug, it is instructive to simulate the worst-case as a dislodged, frictionless, piston projectile in a pipeline, as in Example 15.

87

Figure 76 - Pressure Change During Depressurization (From Gjertsen et al, 1997)

3000 Subsea Pressure

Pressure (psig)

2500

2000 Topside Pressure

1500

1000

500

Pressure Difference

0 0

50

100

150 Time (hours)

200

250

____________________________________________________________________ Example 15. Simulation of Hydrate Projectile Upon Depressuring One Side of Plug. Xiao and Shoup of Amoco (1996 a,b,c, 1997) performed a series of simulations of a hydrate projectile in preparation for depressurization from one side of a hydrate plug in a Kerr-McGee, Wyoming 4 inch line. The plug was conservatively modeled as a frictionless piston. Using OLGA the steady state flow in the line was modeled prior to blockage formation. The model included pipeline topography to obtain steady state liquid volumes trapped at low points in the pipeline. The total mass flow was 92 BOPD and 4.166 MMscf/d. Figure 77 shows pipeline topography and the liquid holdup. At a ground temperature of 34oF, the pipeline was simulated as shut-in for 8 hours, resulting in a simulated plug formation. Hydrate plugs were initially situated at 7,550 ft. from the inlet of a 17,000 ft. pipeline, with upstream pressures of 1150 psig and 575 psig and a constant initial downstream pressure of 50 psig. Transient velocities of two plugs were simulated after formation: (a) a 20 lbm plug which was 5 ft. long, and (b) a 137 lbm plug which was 30 ft. long. Velocity profiles were obtained for each plug, propelled by the initial pressure differentials of 1100 psi and 525 psi., against an initial pressure of 50 psig with a closed valve at the line end.. For an upstream pressures of 1150 psig, the plugs reached a peak velocity 740 ft/s (smaller plug) and 450 ft/s (larger plug). For an upstream pressure of 575 psig, the plugs reached a peak velocity of 550 ft/s (smaller plug) and 340 ft/s (larger plug). The inertial effects of the gas caused rapid acceleration and the final position of the larger plug (700 ft. and 1,700 ft. from the pipe discharge at initial upstream pressures of 1150 psig and 575 psig respectively) was governed by a pressure balance, caused by expansion of the upstream gas and compression of the downstream gas. The simulation indicated that liquid condensate present in the line had very little effect on the plug maximum velocity when condensate was injected far away from the plug initial position. Figure 78 shows the plug velocity as a function of pipe position for the case of 1150 psig upstream pressure with a 137 lbm plug. Plug simulation results were used to plan and execute field plug dissociation tests. The calculated plug velocity was an acceptable match with measured plug velocities in the field with a gamma-ray detector. It should be noted that modeling the plug as a frictionless piston provides conservative results. The modeled plug will be slowed by any friction between plug and the pipe, as well as by blow-by of gas at the wall and through the porous plug. ____________________________________________________________________

88

Figure 77 - Topography and Steady-State Holdup Profile (From Xiao and Shoup, 1996)

5360

0.14

Pipeline 5340

Holdup

0.12

0.1

5300 0.08

5280 5260

0.06

5240 0.04

5220 0.02

5200 5180

0

0

2000

4000

6000

8000

10000

12000

Pipeline Distance (ft)

14000

16000

18000

Holdup

Station Elevation (ft)

5320

Figure 78 - Plug Velocity vs. Plug Location (From Xiao and Shoup, 1996) 500

Upstream pressure=1 150 psig Downstream pressure = 50 psig 137 Ibm plug

4%

4Oc

350

8

30a

.s H

250

3 3 0

200

150

loo

50

0 10500

11500

12500

Pipeline Distance, ft

13500

14500

15500

16500

III.C.2. Chemical Methods of Plug Removal. When the pipeline is completely blocked, it is difficult to get an inhibitor such as methanol or ethylene glycol next to the plug without an access port in the plug proximity. While plugs have been proved to be very porous and permeable, particularly in gas systems (see Section III.C.1.a) a substantial gas volume between the plug and injection points (platform or wellhead) hinders contact, particularly when the line cannot be depressured to encourage gas flow through the plug. Without flow, inhibitors must displace other line fluids through density differences to reach plugs which are close to the platform. Because flowlines have large variations in elevation it is unlikely that an inhibitor will reach a plug without flow. Nevertheless standard practice is to inject inhibitor from both the platform and the well side of a plug, in an attempt to get the inhibitor next to a plug. Sometimes the increased density of heavy brines can provide a driving force to the hydrate plug face. Methanol or glycol injection is normally attempted first in a line. Density differences act as a driving force to get inhibitor to the face of the plug, causing glycol to be used more than methanol. The reader is also referred to Section III.B.2.a. “Filling the Line/Well with an Inhibitor or Mechanical/Optical Device.”

III.C.3. Thermal Methods of Plug Removal. When the ends of a hydrate plug cannot be located, heating is very dangerous because the pressure rises exponentially with temperature. Both ends of a hydrate plug can seal the high pressure resulting from hydrate dissociation with heating, and the line can burst as a result. Such a problem is indicated in Case Study 4 of Section I. Rule of Thumb 21. Because the limits of a hydrate plug cannot be easily located in a subsea environment, heating is not recommended for subsea dissociation. However, heating is a viable option for topside hydrate plugs on a platform where a thermocamera can be used to determine the plug limits (and where the possibility of multiple plugs has been eliminated). Similarly in a plugged well where the upper plug end is available, heating may be one of the primary options, as indicated in the below case studies. Heating a plug in a well can be accomplished using a heated wireline broach, similar to tool the shown in Figure 56, as discussed on page 68. _____________________________________________________________________ Case Study 16. Plug Dissociation by Heating in a Well. A hydrate plug was experienced in a well feeding a jackup platform in the Norwegian sector in mid-May 1997. A hydrate plug, initially caused by pressurization of the well with water, formed

89

below the downhole safety valve in the well. This is a particularly precarious condition which can result in a well blow out, if it is not handled properly. Field personnel first attempted to decrease the pressure in steps to just above the hydrate equilibrium pressure and unsuccessful attempts were made to push MEG through the hydrate plug. The next action was to inject MEG into the well leaving only a small gas volume at the top of the well. With a higher pressure atop the plug, the only way to get gas into the well was by hydrate dissociation via MEG. When the pressure dropped to 4280 psia, MEG was re-injected into the well until the pressure rose to 4930 psia. A total of 0.14 gallons of MEG were re-injected, indicating that a very small amount of hydrates had dissociated. It was concluded the plug had very low permeability and dissociated very slowly. This concluded the period of “getting to know the plug.” At that point the pressure was reduced atop the well to 15 psia and shut-in so that only the additional static head (394 ft. above the plug) maintained pressure above the plug. The pressure recovered to 100 psia as an indication that hydrates were dissociating upon pressure reduction. There were at least six similar pressure reduction and recovery confirmations that hydrates were dissociating in the well; each time pressure increases exponentially approached an asymptote of 100 psia. It was determined the keep the pressure at 15 psia on top of the well to provide constant hydrate melting. The plug temperature was approximately 48oF. Five hours after maintaining the pressure at 15 psia, the hydrate dissociation was complete and the pressure atop the well rose to 160 psia. The entire hydrate plug melted 12 days after the initial formation. Questions remained concerning why the plug did not respond to MEG injection, so that depressurization had to be used. _____________________________________________________________________

III.C.4. Mechanical Methods of Plug Removal. Pigs are not recommended to remove a hydrate plug, because compression usually compounds a plug problem. Even for partial plugs, hydrate formation at low lying points of the flowline may cause the pig to become stuck. If a number of hydrate particles are present in the line, pigging could result in a more severe plug. Coiled tubing is the final option for hydrate removal. The tubing is put into the pipeline through a lubricator, usually at a platform or floating workover vessel, in an effort to get an inhibitor such as glycol to the face of the plug. Coiled tubing is 1/2 to 3-1/2” OD tubing of a maximum length between 15,000 and 29,000 ft. (Sas-Jaworsky et al., 1993). The bend radius at the base of the platform riser presents a limit to coiled tubing penetration, with a minimum radius of 6-10 ft.,

90

but a preferred minimum radius of 20 - 60 ft. Penetration distance is a function of tubing size and pipeline diameter as shown in Table 10.

Table 10. Penetration Distance of Coiled Tubing (DeepStar A208, 1995) Tubing Size Flowline Size Penetration inch inch ft. 1.5 1.75 - 2.0

4 or 6 4 or 6

3,000 - 5,000 6,000 - 8,000

See Case Study 11 (Section III.B.2.a) for a successful example of hydrate plug removal with coiled tubing and glycol jetting. In other case histories coiled tubing has been used successfully. For example coiled tubing was recently used to dissociate a plug at Statoil’s Statfjord field (Urdahl, 1997). Coiled tubing is expensive, requiring special rigs. The daily cost of coiled tubing in 1997 is $1 million/d to rent the rig. Coiled tubing technology is being developed. For hydrate applications, three new types of coiled tubing are listed from the DeepStar A208-1 report by Mentor Subsea (Davalath, 1995): 1. Coiled tubing can get hydraulic drilling equipment to the plug (Figure 79). 2. A tractor can be used to pull the coiled tubing through the flowline from the platform side (Figure 80) in lines larger than 4 inch ID at a speed of 5400 ft/hr with penetration distances to 15,000 ft. Testing is underway in Deepstar Project 3202. 3. A promising coiled tubing being developed is composite coiled tubing. The tubing walls are porous to allow air/gas to lubricate the tubing travel for further penetration. Demonstration has yet to be done. With the use of coiled tubing it is important to remember that as much as 170 scf of gas evolves from each ft3 of dissociated hydrate. Coiled tubing must have gas flowby capability in the drive mechanism at the tubing front. This will prevent either pushing the tubing from the plug face or line over-pressure. For example with the pigdriven coiled tubing shown in Figure 79, gas must be produced from the tubing.

III.D. Avoiding Hydrates on Flowline Shut-in or Start-up Shut-in and start-up are primary times when hydrates form. On shut-in the line temperature cools very rapidly to that of the ocean floor (40oF for depth greater than 2000 ft.) so that the system is almost always in the hydrate region if the line is not depressured. At that condition, multiple hydrate plugs can form. For a planned shutin, two actions are recommended: (a) inject a large amount of inhibitor such as methanol or ethylene glycol, and (b) depressure the pipeline as soon as possible. Case Study 11 (Section III.B.2.a) illustrates a hydrate plug formation due to an unexpected shut-in when methanol could not be injected. It is not clear that the line 91

FiQure

79

-

Drillin

Head

for

Solids

Removal

(From Deepstar A-208-1, 1995) /Coiled

Tubing

Insulation

SLip Actuating

sups,

w/

Flow

II’

-Drlll

Integrutirlg

Reversing

/Wiper

\\

Nut

Seals

Sub

Disks

Motet-

Stationary Rotating Flow

Nozzles

Cutter Grater

Blades Type

Cutting

Plate

Figure

80

-

Coiled (From

Tubing Deepstar

Tractor A208-1,

(Fluid

Driven

Version)

1995)

API

Tractor Section NorndForce Tractor FOrce

\

Flow

TrKtion

for

Force

Connection

was depressured immediately after shut-in, but the plug formation was removed via coiled tubing with glycol jetting. Case Study 17 also illustrates the value of line depressuring on shut-in. _____________________________________________________________________ Case Study 17. Multiple Plug Formation after Pressurized Shut-in. The following study is from DeepStar Report A208-1 (Mentor Subsea, 1995, page 31). Due to a problem at a gas plant a 6 inch 600 ANSI flowline was shut-in at 1000 psi, but it was not depressured for six days. The normal flow in the pipeline was gas with 2% H2S and condensate in the amount of 50 bbl/MMscf. To remove the blockage the wellhead side of the line was depressured by venting over a 15-20 minute period. Then the valve at the header side was vented. During this operation, one of the hydrate plugs partially melted, dislodged from the line and was propelled by the high-pressure gas trapped inside the line. In this case there were at least two low spots in the line, where sufficient water accumulated to form multiple hydrate plugs. The plug length was estimated to be 33 ft. and the gas trap between the plugs was estimated to be 160 ft. long. The fast-moving hydrate plug blew a hole through a tee near the header within half a second after the valve was opened at the header. The impact of the plug and associated debris caused one fatality and one injury to personnel operating the valve. Follow-up investigations and math modeling showed that 230 - 820 ft. of high pressure gas in a 6 inch line would be sufficient to cause the damage that occurred. In subsequent operations, hydrate plugging was prevented by: (1) injecting methanol or glycol during each start-up, (2) for planned shutdowns, a hydrate inhibitor was injected prior to stopping flow followed by depressurization, and (3) for unplanned shutdowns, the pipeline was depressured within the first 24 hours following shut in. _____________________________________________________________________ On start-up before reaching steady state, all parts of the system are particularly susceptible to hydrates, while the system is heating with warm fluids from the reservoir. During this time small hydrate particles which have formed may be compacted by flow (or by pigs) to form a plug. A typical start-up procedure involves injecting large amounts of inhibitor and using diesel fuel. _____________________________________________________________________ Case Study 18. Pipeline Start-up after Hydrate Formation. In 1996 a Statoil black oil pipeline plug occurred in the Norwegian sector of the North Sea, as described in Case Study 15 (Section III.C.1.d). After several precautions, the pipeline was depressured from one side of the plug, and when the plug had melted the line was maintained at atmospheric pressure for over one day to eliminate the light components which might form hydrates.

92

Before start-up, methanol was injected in the amount of 530 gallons in the 6 inch ID, 1.6 mile line from the platform. The pipeline was then pressurized with diesel from the platform to the sub-sea valve, in an amount which indicated that the pipeline was nearly empty of liquid after the previous depressurization to atmospheric conditions. A further injection of diesel corresponding to two pipeline volumes was pumped into the pipeline and well. Subsequently the well and the pipeline were put into production without any hydrate problems. _____________________________________________________________________

III. E. Recommendations and Future Development Areas III.E.1. Recommendation Summary for Hydrate Remediation. The lessons of hydrate plug remediation may be summarized succinctly: 1. Hydrate plugs are always dissociated, but the time scale is usually days to weeks. Deliberate changes and Patience are required. Hourly changes are ineffectual. 2. Multiple hydrate plugs should always be assumed and treated as a safety hazard. 3. Many hydrate plugs are porous and transmit pressure easily while acting to obstruct flow. Some plugs are permeable to gas, but less so to condensate or black oil. This concept controls many aspects of hydrate dissociation, including radial depressurization, Joule-Thomson cooling through the plug, and the fact that depressurization may cause the plug downstream temperature to decrease below the hydrate equilibrium temperature. 4. Methods are not well-defined for locating hydrate plugs and determining their length. However, knowledge of the precise location and length of a plug would be a vital help in dissociation. 5. Attempts to “blow the plug out of the line” via a high upstream pressure always results in a larger, more compacted hydrate. 6. Depressurization from both sides of hydrate plugs is the preferred method of removal, from both safety and technical viewpoints. This implies access points at both plug ends through dual production lines, service lines, etc. 7. If the pressure is decreased too much, the hydrate plug will rapidly form an ice plug which may be more difficult to dissociate. 8. In a deepwater line a liquid head on a hydrate plug may be sufficient to prevent depressurization. Liquid heads removal is a current challenges to flow assurance. 9. In some cases, depressurization from one side of a plug has been safely done. 10. Heating is not recommended for hydrate plugs without a means for relieving the excess gas pressure when hydrates dissociate. 11. Coiled tubing represents the primary mechanical means for dissociating hydrates. 12. Usually methanol or glycol is injected into plugged flowlines, but this is seldom effective due to the necessity to get the inhibitor at the face of the plug. 13. Inhibitor injection and de-pressuring techniques are available for system shut-in and start-up - two times of jeopardy in formation of hydrate plugs.

93

III.E.2. Recommendations for Future Work. Recommendations for future work to aid remediation supplements those from DeepStar Report A208-1 (Mentor Subsea, 1995) based upon case studies represented in the body of this report and in Appendix C. 1. Investigate the use of various access points along a flowline to allow (1) locating the plug, (2) removal of liquid head at each side of a plug, and (3) depressuring from each side of the plug. Such options include (a) multiple access points along a pipeline, (b) dual production lines, (c) wellhead access through service lines with check valves removed or bypassed, and (d) blind flanges and valves at manifold. 2. Investigate the use of various coiled tubing techniques to enter a long distance subsea line, such s (a) locomotive-type device for pulling coiled tubing, (b) pigs mounted outside of coiled tubing to assist penetration, (c) composite coiled tubing to reduce drag. 3. Consider using a long radius riser (from 20-80 ft.), eliminating bends and “S” configurations where water might accumulate, and reducing line low spots. 4. Eliminate un-necessary restrictions and valves in the system and provide for heating or methanol injection where Joule-Thomson cooling is a problem. Consider installing a heater on the platform to prevent hydrate formation in the choke and/or separator. 5. Consider providing pressure and temperature monitors a various points along the pipeline. Provide for hydrate prevention at these instrument points. 6. A mathematical model should be refined and verified to include radial dissociation of a hydrate plug. A proven, predictive model for hydrate dissociation is not currently available.

94

IV. Economics Economics provide the motivation for all engineering action. When we ask, “Why should hydrates be of concern?” the ultimate answer relates to economics. Even concerns of higher value (e.g. safety or the environment) relate directly to economics because such concerns can prevent process operations. The present section is aimed at providing economics in terms of hydrate safety, prevention, and remediation - the previous three major sections of the handbook. In every example provided, a time stamp enables the reader to update the economics, using such tools as the Consumer Price Index.

IV.A. The Economics of Hydrate Safety While insurance actuaries can set a price on life and limb, usually an ethical concern for worker well-being dictates safe operation, and companies take welldeserved pride in the number of “accident-free days.” While safety is related to costs, the policy is invariably, “Safety at all costs,” or “If we cannot operate safely, we cannot operate.” Consideration of the Section I five case studies, plus Case Study 17 in Section III.D all imply a direct relationship between safety and cost, because blowout and severe process damage occurred in all cases. Lysne (1995, p. 7,8) lists three such incidences in which hydrate projectiles erupted from pipelines at elbows and caused the loss of three lives and over $7 million in capital costs.

IV.B. The Economics of Hydrate Prevention The Guidelines for Hydrate Prevention Design (Section II.H) are certain to involve economics which relate to individual cases, for example the cost of a heating system installed around a instrument gas control valve. Frequently such costs can be minimized in the original process design, without expensive retrofits to correct deficiencies. In this section we are concerned with the economics of two principle prevention means: (1) chemical injection and (2) heat management. IV.B.1. Chemical Injection Economics. In the United States in 1996 the oil and gas production industry used an estimated 400 million pounds of methanol, the most-used hydrate inhibitor (Houston, 1997). Shell’s methanol usage in deepwater is forecast at 50 million pounds per year. With expanding deepwater work the use of methanol is expected to grow 50 - 75% over the next five years. These economics provided the initial motivation to investigate hydrate prevention via other means.

95

IV.B.1.a. Economics of Methanol and Mono-ethylene Glycol. One of the most comprehensive documented economic studies of methanol injection was provided by DeepStar I CTR 240 by INTEC Engineering (December 1992). In that work chemical injection costs (including MeOH) were reported for two Gulf of Mexico cases: (a) the Jolliet reservoir which is naturally gas lifted, and (b) the Hercules reservoir has a heavier crude with low GOR (500 scf/b). The study recommends that there should be one transmission line per chemical and a subsea distribution system, with the main features: • • • •

one surface pump per chemical on the host platform one subsea transmission line per chemical subsea distribution using remotely adjustable, pressure compensated flow control valves packaged into control pods, and use of steel or stainless steel subsea chemical transmission lines.

Details of annual hydrate chemical costs for 1-well and 20-well cases, 60 mile lines, are provided in Table 11. Table 12 gives capital costs for methanol injection systems in 1 well and 20 wells for the Jolliet and Hercules reservoirs. It should be noted however, that both tables are based solely upon methanol only in the free water phase. As noted in Sections II.D.2 and II.D.3. frequently methanol losses to the vapor and condensate phases are quite important. The amounts of chemical injection should be based upon the methods of Section II.D, recalling the relative advantages and disadvantages of each inhibitor. For example, methanol is significantly dissolved in the vapor and liquid hydrocarbon phases, not just the free water phase (considered in Table 11). Methanol had a delivered cost to an offshore Gulf of Mexico platform of $2.00 per gallon during the 1996-7 winter. Such costs fluctuate significantly and are somewhat seasonal; typical dockside North Sea methanol costs were $0.11/lbm ($0.72/gallon) and ethylene glycol cost were $0.27/lbm during the 1997 summer. Since methanol recovery is not economical, methanol injection is normally considered as an operating cost. The Deepstar Study CTR 221-1 (Paragon Engineering, 1994) shows methanol recovery to be very expensive in Table 3 of Case Study 7 in Section II.G.1.a. For methanol recovery late in the life of a field, the total installed cost on an existing platform was estimated at $16.7 million ($20 million total installed cost with a new platform) while the annual operating cost is $6 million. For ethylene glycol (MEG) a low vapor pressure results in a smaller recovery column, making the economics much more favorable.

96

Table 11. Cost of Methanol Usage for Jolliet and Hercules Reservoirs in Gulf of Mexico (from DeepStar I CTR 240) H2O

Subcool

No. life Well yr

WHP psia

Oil

Gas

bbl/D

Mscf/d

bbl/D

∆T( F)

wt% MeOH Cost MeOH gpm k$/yr

Jolliet “ “

1 “ “

1 5 8

3,317 1,970 911

2,500 600 43

1,670 3,268 850

2 17 4

46.3 38.8 27.8

35.3 33.1 27.3

0.026 0.206 0.040

7.65 60.6 11.8

Jolliet “ “

20 “ “

1 5 10

2,821 1,449 1,123

4,400 16,400 5,100

2,948 33,948 36,210

4 124 172

43.9 34.4 30.8

34.8 31.1 29.2

0.051 1.412 1.832

15.0 415.6 539.2

Hercules “ “

1 “ “

1 5 8

2,325 1,737 1,824

1,367 465 23

869 376 30

0 666 22

41.2 37.0 37.7

33.9 32.3 32.6

0 7.889 0.263

0 2,322 77.4

Hercules “ “

20 “ “

1 5 10

2,325 1,064 1,064

2,700 22,700 19,100

3,000 12,500 11,700

0 4,540 5,157

41.2 30.0 30.0

33.9 28.7 28.7

0 47.75 54.24

0 14,054 15,964

Rsrvr

o

Table 12. Transmission Lines (60 miles) Sizing, Costs and Pumping Skid Costs (From DeepStar I. CTR 240) Reservoir

No. Wells

Min. Line ID (in)

Line Cost MM$

Skid Cost k$

Jolliet Jolliet

1 20

0.306 0.780

1.03 1.11

5.20 30.00

Hercules 1 1.629 1.79 34.00 Hercules 20 2.815 1.79 89.50 Additional cost of valve, actuator, manifolding, and packaging = $6,700/well. Rule-of-Thumb 22. Methanol loss costs can be substantial when the total fraction of either the vapor or the oil/condensate phase is very large relative to the water phase. Sections II.C. and II.D. provide a quantitative means of validation of the above Rule-of-Thumb. Example 7 provides a conservative sample calculation in which 15% of the methanol is lost to the vapor and liquid hydrocarbon. Statoil provided the below table showing a reduction in condensate price for different methanol concentrations (>30 ppm by wt) in a condensate.

97

Table 13. Cost Penalties for Methanol in Propane (from Austvik, 1997) MeOH conc in Reduction in 1993 Price (comment) C3H8 ppm (wt) 0-30 30-50 50-100 100-200 200-300 >300

0 0-$2/metric ton (MT = 2205 lbm) $2-4/MT (or $0.25 - $0.50/ Bbl) $4-6/MT (excludes some crackers) $6-9/MT (excludes most crackers) $9-40/MT (reduced confidence in product)

IV.B.1.b. Economics of New Types of Inhibitors. Notz (1994) provided one of the best comparisons of operating costs for methanol with kinetic inhibitors in Tables 14 and 15 for a Texaco field in the North Sea. Table 14. Relative Usage of Methanol and Kinetic Inhibitor in a North Sea Field (P. Notz, July 26, 1994) Pipeline (in)

phase

Life yrs of Use

H2O avg, bbl/d

Time in hydrate zone, hr

Max ∆T, o F

wt% MeOH in H2O

MeOH 1000 lbm

KI 1000 lbm active

16 “ “

multi “ “

0 7 15

304 287 150

0 2.3 40.9

no hyd 11.7 31.4

0 16 33

0 20.9 19.3

0 0.409 NA*

8 “ “

liquid “ “

0 7 15

346 295 118

0 7.9 43.2

no hyd 17.5 19.4

0 20 21

0 21.5 8.8

0. 0.441 0.170

12 “ “

gas “ “

0 17 8.4 25.5 28 9.7 7 10 24.6 30.8 33 5.9 15 4 72.9 32.0 33 2.4 NA* = conditions too severe for kinetic inhibitor (KI)

0.128 NA* NA*

98

Table 15. Comparison of Methanol and Kinetic Inhibitor Cost in North Sea (P. Notz, July 26, 1994)

Line (in)

16 8 12

phase

multi liquid gas

Years When Kinetic Inhibitor is Effective Use Methanol Kinetic Yrs Inhibitor1 MM $MM MM $MM lbm lbm

MM lbm

$MM

Replacing MeOH with KI Whenever Possible KI1, MeOH2 Total MM MM lbm Cost lbm $MM

7-9 6-15 1-4

72.9 52.5 33.0

22.1 15.9 10.0

0.36 1.05 0.03

25.9 52.5 15.6

7.8 15.9 4.7

0.36 1.05 0.03

3.2 9.3 0.26

Over Entire 15 Year Life of Reservoir Methanol

50.0 0 17.4

1

This includes the cost of methanol solvent for the kinetic inhibitor This is the methanol cost in those years when a KI cannot be used because ∆T > 27oF

2

Grainger (1997) compared inhibition costs of methanol, glycol, and a Threshold Hydrate Inhibitor (THI) which consisted of kinetic inhibitors, a corrosion inhibitor, and a solvent. Table 16 represents dock delivery costs, without shipping to the platform.

Table 16. Comparison of Three Types of Inhibitor Costs in the North Sea (M. Grainger, August 21, 1997) Chemical

MEG

MeOH

THI

Conc/bbl H2O,wt% Quantity, lbm Cost/bbl H2O

15 61.7 $16-$17

15 61.7 $6.5 - $7.5

0.25 0.882 $8-$10

From the above table, operating cost benefits appear marginal (better than MEG, worse than MeOH). Bloys et al. (1995) suggested that economics were favorable for new developments (due for example, to capital savings of avoiding regeneration systems) but marginal for retrofits of systems with traditional inhibitors such as monoethylene glycol. The incentive for newer kinetic control methods is a substantial capital cost reduction by the elimination of the need for offshore platform equipment, and a small operating cost reduction. In one high water production North Sea field, BP reckoned the capital costs savings at $50 million for platform costs including methanol injection costs, glycol drying, and regeneration (Argo and Osborne, 1997).

99

18.4 9.3 5.5

For example, BP currently operates some Southern North Sea pipeline wet, thereby saving the capital cost of drying the gas on the platform. In addition to capital cost, a savings may be realized on the platform itself. Rule-of-Thumb 23. The cost of a fixed leg North Sea platform is $77,000/ton. The above Rule-of-Thumb was given by Edwards (1997). BP would like to use unmanned platforms, but the inhibitor recovery units on some platforms prevents doing so. As additional costs, Edwards also estimated the operation of an inhibitor recovery unit at 2 hrs/day operator time and maintenance requires 600-700 hr/year at $85/hr. The economics of anti-agglomerants are much less certain than those stated above for kinetic inhibitors. No documented costs of anti-agglomerants were found. However, anti-agglomerant economics should include such factors as emulsion breaking, recovery, and disposal.

IV.B.2. Heat Management Economics. Of the two heat management techniques (insulation methods and pipeline heating) only the insulation state-of-the-art is established sufficiently for economics to be available. However, deepwater development is causing the cost of such technology to change rapidly, and the information contained here should be updated by knowledgeable workers. IV.B.2.a. Economics of Insulation. The minimum overall coefficient achievable with a non-jacketed system is 0.3 BTU/hr-ft2-oF (from DeepStar Report IIA CTR A601-a, 1995) and costs are typically $50-$300/ft for pipes with diameters between 8 inches and 12 inches. Rule-of-Thumb 24. In order to achieve a desired heat transfer coefficient of 0.3 BTU/hr-ft2-oF, a non-jacketed system costs $1.5 million per mile. Typical costs of insulation via bundled lines are $1.5 -$2.0 million/mile. Figures 43 and 44 compare the cost of the three above types of insulation for water depths of 6000 ft over 60 miles at oil production rates of 25,000 and 50,000 bbl/d, respectively. If an average U = 0.3 BTU/hr-ft 2-oF is required with a flowline pressure of 4000 psia, bundled flow lines are more cost effective. Technical details and associated economics are provided in Section II.G.4.a.

100

IV.C. The Economics of Hydrate Remediation When hydrate blockages occur, production is shut in. When coupled with the fact that all hydrate-blocked lines and wells have to be re-commissioned, the question arises about how lost production should be treated - i.e. as lost or as deferred revenue. There is consensus that shut-in production should be counted as lost revenue for reasons including the following: 1. Usually deferred production is counted at the end of reservoir life, so that the time value of money is considered. A dollar today is worth more than a dollar tomorrow due to inflation. 2. Fields are frequently sold over their lifetime, and deferred cost means lost revenue during the ownership of a field. 3. Contracts specify delivery and penalties for non-delivery of hydrocarbon. Production losses due to hydrates are site-specific, but are enormous when considered collectively. From the hydrate group with the largest world-wide remediation experience, Austvik of Statoil(1997) indicated the magnitude of the problem by saying, “At any instant in the North Sea, there is probably a hydrate blockage which requires remediation.” As one onshore example, despite large quantities of methanol injection for hydrate prevention, Todd et al. (1996) report 66 hydrate blockages occurred in one well and production line during winter of 19951996, resulting in production losses of more than $240,000. Offshore hydrate remediation techniques are very costly if they are not explicitly included into the initial design. For example, the ARCO Case Study 14 represented a fortunate instance (in April 1996) of having an extra flange available at the manifold for depressurization. In this case two solutions were technically available: 1. Jack-up Rig. Tow a jack-up rig to the site and attach a high pressure riser to the manifold’s subsea tree. Flare exiting gas via the rig’s flare stack. The estimated cost: was $2 million and a delay of approximately eight weeks was needed to locate a suitable rig. The time required for hydrate removal could be twelve weeks. 2. Floating Production and Storage Vessel (FPSO). Connect a FPSO with a processing plant and flare to the subsea manifold’s fourth flow loop. The estimated cost was $1.9 million and a FPSO was available for immediate use, reducing the required time to 6-8 weeks. Other techniques such as the use of coiled tubing were not available at the time. (The daily cost of coiled tubing was $1 million/d to rent the rig in July, 1997.) The final cost of depressurizing the ARCO pipeline was almost 3 million dollars,

101

without production losses. Even with such high costs, the loss of production usually causes time to be the deciding resource during remediation. During remediation periods, gas supply is usually met via substitution. However, the borrowing capacity is typically limited to 5 times the daily capacity, so that gas supplies are purchased from the spot market. Typical non-delivery penalty costs are $50,000/day after tax on a gas production unit of 125MM scf/d. Nondelivery contract pressures may be eased by considering hydrates as a “Force Majeure” as done in ARCO Case Study 14, implying that no penalties should be incurred because there was no human error.

102

Appendix A. Gas Hydrate Structures, Properties, and How They Form The following discussion is excerpted from the monograph by Sloan (1998, Chapters 2 and 3), to which the reader may wish to turn for a more complete explanation. Two recent hydrate conference summaries (Sloan et al., 1994; Monfort 1996) also provide research and applied perspectives of the hydrate community. Gas clathrates are crystalline compounds which occur when water forms a cage-like structure around smaller guest molecules. While they are more commonly called hydrates, a careful distinction should be made between these non-stoichiometric clathrate hydrates of gas and other stoichiometric hydrate compounds which occur for example, when water combines with various salts. Gas hydrates of current interest are composed of water and the following eight molecules: methane, ethane, propane, isobutane, normal butane, nitrogen, carbon dioxide, and hydrogen sulfide. Yet other apolar components between the sizes of argon (3.5 Å) and ethylcyclohexane (9Å) can form hydrates. Hydrate formation is a possibility where water exists in the vicinity of such molecules at temperatures above and below 32oF. Hydrate discovery is credited in 1810 to Sir Humphrey Davy. Due to their crystalline, non-flowing nature, hydrates first became of interest to the hydrocarbon industry in 1934, the time they first were observed blocking pipelines. Hydrates concentrate hydrocarbons: 1 ft3 of hydrates may contain 180 scf of gas. Hydrates normally form in one of three repeating crystal structures shown in Figure A.1. Structure I (sI), a body-centered cubic structure forms with small natural gas molecules found in situ in deep oceans. Structure II (sII), a diamond lattice within a cubic framework, forms when natural gases or oils contain molecules larger than ethane but smaller than pentane. sII represents hydrates which commonly occur in hydrocarbon production and processing conditions, as well as in many cases of gas seeps from faults in ocean environments. The newest hydrate structure H (sH) named for its hexagonal framework, has cavities large enough to contain molecules the size of common components of naphtha and gasoline. Some initial physical properties, phase equilibrium data, and models have been determined for sH and one instance of in situ sH in the Gulf of Mexico has been found. Since information on structure H is in the fledgling stages, and since it may not occur commonly in natural systems, most of this appendix concerns sI and sII.

A.1. Hydrate Crystal Structures. Table A.1 provides a hydrate structure summary for the three hydrate unit crystals (sI, sII, and sH) shown in Figure A.1. The crystals structures are given with reference to the water skeleton, composed of a basic "building block" cavity which has twelve faces with five sides per face, given the abbreviation 512. By linking the vertices of 512 cavities one obtains sI; linking the faces of 512 cavities results in sII; in sH a layer of linked 512 cavities provide connections. 103

Fimre A-l - Three Hydrate Unit Crystals and Constituent Cavities (From Sloan, 1998)

Structure

Structure IJ I

136 Water Molecules 46 Waler Molecules

Structure H 34 Water Molecules

Spaces between the 512 cavities are larger cavities which contain twelve pentagonal faces and either two, four, or eight hexagonal faces: (denoted as 51262 in sI, 51264 in sII, or 51268 in sH). In addition sH has a cavity with square, pentagonal, and hexagonal faces (435663). Figure A.1 depicts the five cavities of sI, sII, and sH. In Figure A.1 a oxygen atom is located at the vertex of each angle in the cavities; the lines represent hydrogen bonds with which one chemically-bonded hydrogen connects to an oxygen on a neighbor water molecule. Table A.1 Geometry of Cages in Three Hydrate Crystal Structures in Figure A.1 Hydrate Crystal Structure Cavity Description Number of Cavities/Unit Cell Average Cavity Radius, Å Variation in Radius1, % Coordination Number2 Number of Waters/Unit Cell

I Small Large 512 51262 2 6 3.95 4.33 3.4 14.4 20 24 46

II Small Large 512 51264 16 8 3.91 4.73 5.5 1.73 20 28 136

H Small Medium Large 512 435663 51268 3 2 1 3 3 3.91 4.06 5.713 Not Available 20 20 36 34

1. Variation in distance of oxygen atoms from center of cage. 2. Number of oxygens at the periphery of each cavity. 3. Estimates of structure H cavities from geometric models

Inside each cavity resides a maximum of one of the small guest molecules, typified by the eight guests associated with 46 water molecules in sI (2[512]•6[51262]•46H2O), indicating two guests in the 512 and 6 guests in the 51262 cavities of sI. Similar formulas for sII and sH are (16[512]•8[51264]•136H2O) and (3[512]•2[435663]•1[51268]•34H2O) respectively. Structure I, a body-centered cubic structure, forms with natural gases containing molecules smaller than propane; consequently sI hydrates are found in situ in deep oceans with biogenic gases containing mostly methane, carbon dioxide, and hydrogen sulfide. Structure II, a diamond lattice within a cubic framework, forms when natural gases or oils contain molecules larger than ethane; sII represents hydrates from most natural gas systems gases. Finally structure H hydrates must have a small occupant (like methane, nitrogen, or carbon dioxide) for the 512 and 435663 cages but the molecules in the 51268 cage can be as large as 0.9 Å (e.g. ethylcyclohexane). Structure H has not been commonly determined in natural gas systems to date.

A.2. Properties Derive from Crystal Structures. A.2.a. Mechanical Properties of Hydrates. As may be calculated via Table A.1, if all the cages of each structure are filled, all three known hydrates have the amazing property of being approximately 85% (mol) water and 15% gas. The fact that the water content is so high suggests that the mechanical properties of the three hydrate structures should be similar to those of ice. This conclusion is true to a first approximation as shown in Table A.2, with the exception of thermal conductivity and thermal expansivity. Many sH mechanical properties of have not been measured. 104

Table A.2 Comparison of Properties of Ice and sI and sII Hydrates Property Spectroscopic Crystallographic Unit Cell Space Group No. H2O molecules Lattice Parameters at 273K Dielectric Constant at 273 K Far infrared spectrum H2O Diffusion Correl Time, (µsec) H2O Diffusion Activ. Energy(kJ/m) Mechanical Property Isothermal Young’s modulus at 268 K (109 Pa) Poisson’s Ratio Bulk Modulus (272 K) Shear Modulus (272 K) VelocityRatio(Comp/Shear):272K Thermodynamic Property Linear. Therm. Expn: 200K (K-1) AdiabBulkCompress:273K(10-11Pa) Speed Long Sound:273K(km/sec) Transport Thermal Condctivity:263K(W/m-K)

Ice

Structure I

Structure II

P63/mmc 4 a =4.52 c =7.36 94 Peak at 229 cm-1. 220 58.1

Pm3n Fd3m 46 136 12.0 17.3 ~58 58 Peak at 229 cm-1 with others 240 25 50 50

9.5

8.4est

8.2est

0.33 8.8 3.9 1.88

~0.33 5.6 2.4 1.95

~0.33 NA NA NA

56x10-6 12 3.8

77x10-6 14est 3.3

52x10-6 14est 3.6

2.23

0.49±.02

0.51±.02

A.2.b. Guest: Cavity Size Ratio: a Basis for Property Understanding. The hydrate cavity occupied is a function of the size ratio of the guest molecule within the cavity. To a first approximation, the concept of "a ball fitting within a ball" is a key to understanding many hydrate properties. Figure A.2 may be used to illustrate five points regarding the guest:cavity size ratio for hydrates formed of a single guest component in sI or sII. 1. The sizes of stabilizing guest molecules range between 3.5 and 7.5 Å. Below 3.5Å molecules will not stabilize sI and above 7.5 Å molecules will not stabilize sII. 2. Some molecules are too large to fit the smaller cavities of each structure (e.g. C2H6 fits in the 51262 of sI; or i-C4H10 fits the 51264 of sII). 3. Other molecules such as CH4 and N2 are small enough to enter both cavities (512+51262 in sI or 512+51264 in sII) when hydrate is formed of single components. 4. The largest molecules of a gas mixture usually determines the structure formed. For example, because propane and i-butane are present in many natural gases, they will cause sII to form. In such cases, methane will distribute in both cavities of sII and ethane will enter only the 51264 cavity of sII. 5. Molecule sizes which are close to the hatched lines separating cavity sizes exhibit the most non-stoichiometry, due to their inability to fit securely within the cavity. Table A.3 shows the size ratio of several common gas molecules within each of the four cavities of sI and sII. Note that a size ratio (guest molecule: cavity) of approximately 0.9 is necessary for stability of a simple hydrate, given by the 105

Figure A-2 - Relative Sizes of Hydrate Guest and Host Cavities (From Sloan, 1998)

superscript “F”. When the size ratio exceeds unity, the molecule will not fit within the cavity and the structure will not form. When the ratio is significantly less than 0.9 the molecule cannot lend significant stability to the cavity. Table A.3 Ratios of Guest: Cavity Diameters for Natural Gas Hydrate Formers

Molecule N2 CH4 H2S CO2 C2H6 C3H8 i-C4H10 n-C4H10

Cavity Type=> Guest Dmtr (Å) 4.1 4.36 4.58 5.12 5.5 6.28 6.5 7.1

(Molecular Diameter) / (Cavity Diameter) Structure I Structure II 512 51262 512 51264 0.804 0.855F 0.898F 1.00 1.08 1.23 1.27 1.39

0.700 0.744F 0.782F 0.834F 0.939F 1.07 1.11 1.21

0.817F 0.868 0.912 1.02 1.10 1.25 1.29 1.41

0.616F 0.655 0.687 0.769 0.826 0.943F 0.976 F 1.07

F indicates the cavity occupied by the simple hydrate former

As seen in Table A.3, ethane as a single gas forms in the 51262 cavity in sI, because ethane is too large for the small 512 cavities in either structure and too small to give much stability to the large 51264 cavity in sII. Similarly propane is too large to fit any cavity except the 51264 cavity in sII, so that gases of pure propane form sII hydrates from free water. On the other hand, methane's size is sufficient to lend stability to the 512 cavity in either sI or sII, with a preference for sI, because CH4 lends slightly higher stability to the 51262 cavity in sI than the 51264 cavity in sII. A.2.c. Phase Equilibrium Properties. In Figure A.3 pressure is plotted against temperature with gas composition as a parameter, for methane+propane mixtures. Consider a gas of any given composition (marked 0 through 100% propane) on a line in Figure A.3. At conditions to the right of the line, a gas of that composition will exist in equilibrium with liquid water. As the temperature is reduced (or as the pressure is increased) hydrates form from gas and liquid water at the line, so three phases (liquid water + hydrates + gas) will be in equilibrium. With further reduction of temperature (or increase in pressure) the fluid phase which is not in excess (water in pipeline environments) will be exhausted, so that to the left of the line the hydrate will exist with the excess phase (gas). All of the conditions given in Figure A.3 are for temperatures above 32oF and pressures along the lines vary exponentially with temperature. Put explicitly, hydrate stability at the three-phase (LW-H-V) condition is always much more sensitive to temperature than to pressure. Figure A.3 also illustrates the dramatic effect of gas composition on hydrate stability; as any amount of propane is added to methane the structure changes (sI sII) to a hydrate with much wider stability conditions. Note that a 50% decrease in pressure is needed to form sII hydrates, when as little as 1% propane is in the gas phase.

Æ

106

Figure A-3 - Three-Phase (Lw-H-V) Equilibria of Methane+Propane Mixtures (From Sloan, 1998)

of

.-

Any discussion of hydrate dissociation would be incomplete without indicating that hydrates provide the most industrially useful instance of statistical thermodynamics prediction of phase equilibria. The van der Waals and Platteeuw model which forms the basis for HYDOFF was formulated after the determination of sI and sII structures shown in Figure A.1. With the model, one may predict the threephase pressure or temperature of hydrate formation, by knowing the gas composition. For further detailed discussion the reader is referred to Sloan (1998, Chapter 5). A.2.d. Heat of Dissociation. The heat of dissociation (∆Hd) may be considered to be the heat (rigorously, enthalpy change) required to dissociate hydrates to a vapor and aqueous liquid, with values given at temperatures just above the ice point. For sI and sII, to a fair engineering approximation (±10%) ∆Hd depends mostly on crystal hydrogen bonds, but also the cavity occupied within a wide range of component sizes. Enthalpies of dissociation may be determined via the univariant slopes of phase equilibrium lines (ln P vs. 1/T) in previous paragraphs, using the Clausius-Clapeyron relation [∆Hd = -zR d(ln P)/d(1/T)]. As one illustration, simple hydrates of C3H8 or iC4H10 have similar ∆Hd of 55,500 and 57,200 BTU/(lbmol gas) because they both occupy 51264 cavities, although their guest:cavity size ratios differ (0.943 and 0.976). As a second illustration, similar slopes of lines in Figure A.3 show that mixtures of CH4 + C3H8 have a value of ∆Hd = 34,000 BTU/(lbmol gas) over wide ranges of composition, wherein C3H8 occupies most of the 51264 cavities, while CH4 occupies a small number of 51264 and many 512. Figure A.4 shows similar line slopes (and thus ∆Hd values) for binary mixtures of methane when the large guest is changed from C3H8, to i-C4H10, to n-C4H10. Since natural gases almost always contain such components, ∆Hd = 34,000 BTU/(lbmol gas) is valid for most natural gas hydrates.

A.3. Formation Kinetics Relate to Hydrate Crystal Structures. The answer to the questions, "What are hydrates?" and “Under what condition do hydrates form?” in the previous sections is much more certain than answers to "How do hydrates form?". We don’t know how hydrates form, but we can make some educated guesses about kinetics. The mechanism and rate (i.e. the kinetics) of hydrate formation are controversial topics at the forefront of current research. The kinetics of hydrate formation are clearly divided into three parts: (a) nucleation of a critical crystal radius, (b) growth of the solid crystal, and (c) the transport of components to the growing solid-liquid interface. All three kinetic components are under study, but an acceptable model for any has yet to be found. A.3.a. Conceptual Picture of Hydrate Growth. In a conceptual picture, this laboratory proposed that clusters at the water-gas interface may grow to achieve a critical radius as shown schematically in Figure A.5, by the following steps: 1. When natural gases dissolve in water there is conclusive evidence that water molecules organize themselves to maximize hydrogen bonding around each apolar molecule. The resulting liquid clusters resemble the solid hydrate cavities of 107

Figure A-4 - Three-Phase (Lw-H-V) Equilibria of Methane+ (Propane and Tvo Butanes) (From Sloan, 1998) ,27

1

0

l-

1

0

‘-

, ,3$,

TEMPERATURE , , 4p , 47

TEMPERATURE

(OF) 55

(1000/K)

67

7

Figure A-5 - Schematic Model of Hydrate Cluster Growth (From Sloan, 1998)

+

A. Initial Condlflon Pressure and temperature in hydrate’ forming region, but no gas molecules dissolved in wafer

Gas

6. Labile Clusters Upon dissolu&n of gas in water. labile ctusters form immediately.

,C. Agglomeration Labile clusters agglomerate by sharing. faces, thus increasing disorder.

D. Primary Nuclealion and Growth When the size of cluster agglomerates nacbes a critical value, growth begins.

2.

3.

4.

5.

Figure A.1. These fluid clusters are envisioned to join other clusters as the beginning of the hydrate crystallization process. Figure A.5 indicates an autocatalytic reaction mechanism hypothesized for hydrate formation based upon limited experimental evidence. The figure depicts the progress of molecular species from water [A], through metastable species [B] and [C], to stable nuclei [D] which can grow to large species. At the beginning of the process (point A), hydrogen-bonded liquid water and gas are present in the system. Water clusters around gas molecules to form both large and small clusters [B] similar to the hydrate cages of sI and sII. At point [B], the cages are termed “labile” - they are relatively long-lived but unstable. The cages may either dissipate or grow to hydrate unit cells or agglomerations of unit cells [C], thus forming metastable nuclei. Since these metastable unit cells at [C] are of subcritical size, they may either grow or shrink in a stochastic process. The metastable nuclei are in quasi-equilibrium with the liquid-like cages until the nuclei reach a critical radius. After attaining the critical radius [D], the crystals grow rapidly in a period sometimes called catastrophic growth. In our conceptual picture, when the system is heated, it is driven to the left in Figure A.5, and stable hydrate crystals are dissociated. Once the hydrate dissociation point is reached and passed, there are still labile microscopic species in the water that range in size from multiple hydrate unit cells [C] to metastable nuclei [B]. These residual structures are present up to a certain level of thermal energy above dissociation. At temperatures below that upper boundary, these species causes a decrease in induction or metastability time of a successive run, because the “building blocks” of crystals remain in the liquid. However, once about 100ºF is passed, no residual structure remains to promote hydrate formation.

The above cluster model conceptual picture is most likely to occur at the interface, either in the liquid or the vapor side. The reader should note that the above is a largely unproven hypothesis, whose only justification is to serve as a mental picture for qualitative predictions and future corrections. In contrast to well-determined thermodynamic properties, kinetic characterization of hydrates is very ill-determined. One has only to turn to the recent review of hydrate kinetics by Englezos (1995) or to the author’s monograph (1998) to determine the following unsettling facts which act as a state-of-the-art summary: •

• • • •

Hydrate nucleation is both heterogeneous and stochastic, and therefore is only approachable by very approximate models. Most hydrate nucleation models assume homogeneous nucleation and typically cannot fit more than 80% of the data generated in the laboratory of the modeller. Hydrate growth kinetics are apparatus-dependent; the results from one laboratory are not transferable to another laboratory or field situation. In both kinetics and thermodynamics the hydrate phase is almost never measured. The hydrate dissociation models derived from solid moving-boundary differential equations do not account for the porous, surface formation, and occlusion nature of hydrates on a macroscopic scale. No satisfactory kinetic model currently exists for formation or dissociation. Due to the unsatisfactory state of hydrate kinetics knowledge, this area is the subject of intensive research at the present. 108

Appendix B. User’s Guide for HYDOFF and XPAND Programs A Word of Caution While it is hoped that the programs accompanying this book will be of use in estimating the limiting conditions of hydrate formation, the author should not and cannot be held totally accountable for the use of the predictions which the program provide. If there is a safety consideration or an important process decision to be made based upon the program’s predictions, the user is cautioned to obtain a second opinion from someone knowledgeable in hydrate phase equilibria, before proceeding.

Executive Summary

Program Specifications This program has been developed to run in IBM-PC compatible computers having DOS as operating system. The program is executable without any additional hardware or software requirements. Contents of the Disk The 3.5 in. disk provided with this handbook contains four files: 1. HYDOFF.EXE, an executable file to prediction hydrate formation conditions, 2. FEED.DAT, a file to be used as external input of the feed components and composition for HYDOFF. FEED.DAT is an optional file; it should be noted that HYDOFF will run regardless whether the file FEED.DAT is present. 3. XPAND.EXE an executable file to determine the isenthalpic (∆H=0) and isentropic (∆S=0) gas expansion conditions, and 4. HYDCALC.XLS, a shortcut estimation spreadsheet to calculate methanol or monoethylene glycol amounts. Use of this program is specified in Section II.B. Appendix B provides common examples using HYDOFF and XPAND which may then be modified by the engineer for his/her own purposes. Section B.1 considers the use of HYDOFF (and FEED.DAT), while Section B.2 details the use of XPAND.EXE.

B.1. HYDOFF B.1.a. Running the Program The program can be executed directly from the 3.5 in disk or copied to the hard-drive and then executed. It is recommended to make a backup copy of the

109

program in case problems occur (e.g. virus). At the DOS prompt, simply type HYDOFF and follow the instructions given by the program.

B.1.b. Program Overview The essence of the program is same as the program accompanying the monograph by Sloan (1998), to which the reader is referred for a full explanation. The program has the central purpose of providing information about hydrate phase equilibria with and without thermodynamic inhibitors. However, the version accompanying this handbook has been abbreviated for rapid use. The program provides pressure predictions of structure I and II hydrates at a given temperature with and without thermodynamic inhibitors (methanol, salt (NaCl), or mixtures thereof) at three- and four-phase conditions (I-H-V, LW-H-V, LW-H-V-LHC). The method used by the program for hydrate phase equilibria is based on the van der Waals and Platteeuw model, as described by Sloan (1997, Chapter 5) and the hydrocarbon fluid phases are modeled with the Soave-Redlich-Kwong equation of state with parameters obtained from experimental measurements.

B.1.c. Specifications for a Problem Before any calculation is performed by the program, the user is asked to input some basic information, such as: units that he/she prefers to operate in, components present in the feed, feed composition, temperature, type and amount of thermodynamic inhibitor(s). The feed components and composition can be directly input in the program or specified in the FEED.DAT file which can be read by the program. It should be noted that the FEED.DAT file must be present in the same directory as HYDOFF.EXE. The units and feed composition can be changed at any point during the execution of the program without actually exiting. Note: When specifying components directly in the program (i.e., not using FEED.DAT for feed input) components can be separated by a space or comma or . The program has a MAIN MENU that directs the user to the desired type of calculation. Once a particular calculation is chosen, the user is asked to enter the temperature, and if applicable, concentration of thermodynamic inhibitor(s) in the free aqueous phase. It should be noted that at no point in the program is the user asked to enter an initial guess for the calculations (for pressure predictions). The program has its own

110

internal initial guess. Also, the user does not have to specify the equilibrium phases for any calculation. The equilibrium phases are given as output of the predictions.

B.1.d. What to Expect for an Answer

1. 2. 3. 4. 5.

The standard output for hydrate phase equilibria calculations will display: Equilibrium phases (I-H-V, LW-H-V or LW-H-V-LHC). Equilibrium pressure. Hydrate equilibrium crystal structure (sI or sII). Phase components and compositions (i.e. feed, fluid hydrocarbon, and hydrate). Fractional occupancy of cages by hydrate formers in each type of hydrate cavity.

Different outputs will be shown for each calculation type. Examples to follow will better illustrate how the program is structured and the format of the output.

B.1.e. Some Important Notes The program is structured to prompt the user whenever incorrect or improper information is input. Following is a list of limitations and guidelines of which the user should be aware. 1. The maximum number of components is limited to 17 (seventeen). 2. The weight percentage of methanol as inhibitor is limited to 50 wt%. 3. The freezing point depression for systems containing both methanol and salt is determined by additive contributions of methanol and salt in solution. 4. The total amount of methanol is assumed to be in the aqueous phase. Possible partitioning of methanol into other phases (condensate or gas) is neglected. Example 1 - Temperature and Pressure predictions for Hugoton Gas (experimental data by Kobayashi, R., et al. (1951)) Gas Composition:

Component

Mole %

Methane Ethane Propane i-Butane n-Butane Nitrogen n-Pentane n-Hexane

73.29 6.70 3.90 0.36 0.55 15.00 0.20 0.00

Pressure prediction @ T = 51.35 °F

111

HYDRATE PREDICTION PROGRAM:

HYDOFF

(ACCOMPANYING THE OFFSHORE HYDRATE HANDBOOK) Release Date : July 3rd, 1997 COPYRIGHT : Professor E. Dendy Sloan Center for Hydrate Research Department of Chemical and Petroleum-Refining Engineering Colorado School of Mines, Golden, CO 80401 PHONE:(303) 273-3723

FAX:(303) 273-3730

This program has been designed to provide phase equilibria of hydrates in a manner consistent with available experimental data. Your comments and feedback are welcome for future improvement of the program. Press RETURN to continue ... AVAILABLE UNITS ARE AS FOLLOWS : (1) (2)

TEMPERATURE Fahrenheit Kelvin

PRESSURE psia kPa

Please select the desired set of Units : 1 The program has been designed to allow the user to input the feed components and composition directly in the program or through an external file, namely, FEED.DAT If the user wishes to read the feed components and composition from FEED.DAT, please make sure the information is entered correctly into FEED.DAT (user has to CHANGE the COMPOSITIONS ONLY) and FEED.DAT is in the same directory as the executable HYDOFF.EXE file.

Is the FEED COMPONENTS and COMPOSITION saved under FEED.DAT (No=1 Yes=2)? 1

How many COMPONENTS (excluding Water) are present? 8 sII HYDRATE FORMERS 1. Methane 4. i-Butane 7. Nitrogen

2. Ethane 5. n-Butane 8. Carbon Dioxide

3. Propane 6. Hydrogen Sulfide

NON-HYDRATE FORMERS 9. n-Pentane 13. Octane

10. i-Pentane 14. Nonane

11. Hexane 15. Decane

112

12. Heptane 16. Toluene

Which Components are present? Please list Hydrate formers first 1 2 3 4 5 7 9 11 Enter the MOLE FRACTIONS of each Component : Mole Fraction of

Methane

: 0.7329

Mole Fraction of

Ethane

: 0.0670

Mole Fraction of

Propane

: 0.0390

Mole Fraction of

i-Butane

: 0.0036

Mole Fraction of

n-Butane

: 0.0055

Mole Fraction of

Nitrogen

: 0.1500

Mole Fraction of

Pentane

: 0.0020

Mole Fraction of

Hexane

: 0.0000

THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE (1) (2) (3) (4) (5) (6)

MAIN Program for Equilibrium Hydrate Predictions Display CURRENT Feed Composition Change FEED Composition Change Program UNITS DISCARD all Data and begin NEW Problem Exit HYDOFF Program

1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

1 Enter the required Temperature (in 51.35

F)

THREE-PHASE (Lw-H-V) EQUILIBRIUM CONDITION Temperature : 51.35 F Equilibrium PRESSURE :

399.92

psia

Press RETURN to Continue . . . Equilibrium Hydrate : STRUCTURE II Composition of Phases at Equilibrium

113

Experimental pressure 365.1 psia

FEED .7329 .0670 .0390 .0036 .0055 .1500 .0020 .0000

Methane Ethane Propane i-Butane n-Butane Nitrogen n-Pentane n-Hexane

VAPOR .7329 .0670 .0390 .0036 .0055 .1500 .0020 .0000

HYDRATE .5777 .0299 .3076 .0408 .0063 .0377 .0000 .0000

Press RETURN to Continue . . . Fractional Occupancy of Cages SMALL .6916 .0000 .0000 .0000 .0000 .0461 .0000 .0000

Methane Ethane Propane i-Butane n-Butane Nitrogen n-Pentane n-Hexane

LARGE .0444 .0739 .7602 .1008 .0155 .0011 .0000 .0000

Do you wish to do another calculation at the SAME composition? (No=1 Yes=2) 1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

7 THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE (1) (2) (3) (4) (5) (6)

MAIN Program for Equilibrium Hydrate Predictions Display CURRENT Feed Composition Change FEED Composition Change Program UNITS DISCARD all Data and begin NEW Problem Exit HYDOFF Program

6 End of run : HYDOFF Stop - Program terminated.

114

Example 2 - Pressure prediction with methanol (experimental data by Ng, H.-J., and Robinson, D.B. (1983)) HYDRATE PREDICTION PROGRAM: HYDOFF (ACCOMPANYING THE OFFSHORE HYDRATE HANDBOOK) Release Date : July 3rd, 1997 COPYRIGHT : Professor E. Dendy Sloan Center for Hydrate Research Department of Chemical and Petroleum-Refining Engineering Colorado School of Mines, Golden, CO 80401 PHONE:(303) 273-3723

FAX:(303) 273-3730

This program has been designed to provide phase equilibria of hydrates in a manner consistent with available experimental data. Your comments and feedback are welcome for future improvement of the program. Press RETURN to continue ...

AVAILABLE UNITS ARE AS FOLLOWS : (1) (2)

TEMPERATURE Fahrenheit Kelvin

PRESSURE psia kPa

Please select the desired set of Units : 1

The program has been designed to allow the user to input the feed components and composition directly in the program or through an external file, namely, FEED.DAT If the user wishes to read the feed components and composition from FEED.DAT, please make sure the information is entered correctly into FEED.DAT (user has to CHANGE the COMPOSITIONS ONLY) and FEED.DAT is in the same directory as the executable HYDOFF.EXE file.

Is the FEED COMPONENTS and COMPOSITION saved under FEED.DAT (No=1 Yes=2)? 1 How many COMPONENTS (excluding Water) are present? 7 sII HYDRATE FORMERS 1. Methane 4. i-Butane 7. Nitrogen

2. Ethane 5. n-Butane 8. Carbon Dioxide NON-HYDRATE FORMERS

115

3. Propane 6. Hydrogen Sulfide

9. n-Pentane 13. Octane

10. i-Pentane 14. Nonane

11. Hexane 15. Decane

12. Heptane 16. Toluene

Which Components are present? Please list Hydrate formers first 1 2 3 5 7 8 9

Enter the MOLE FRACTIONS of each Component : Mole Fraction of

Methane

: 0.7160

Mole Fraction of

Ethane

: 0.0473

Mole Fraction of

Propane

: 0.0194

Mole Fraction of

n-Butane

: 0.0079

Mole Fraction of

Nitrogen

: 0.0596

Mole Fraction of

Carbon Dioxide

: 0.1419

Mole Fraction of

Pentane

: 0.0079

THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE (1) (2) (3) (4) (5) (6)

MAIN Program for Equilibrium Hydrate Predictions Display CURRENT Feed Composition Change FEED Composition Change Program UNITS DISCARD all Data and begin NEW Problem Exit HYDOFF Program

1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

2 Enter the required Temperature (in 47.03

F)

Enter the WEIGHT PERCENT of Methanol (up to 50wt%) 10 FOUR-PHASE (Lw-H-V-Lhc) EQUILIBRIUM CONDITION WITH INHIBITOR(S) Inhibitor :10.00 wt% Methanol Temperature : 47.03 F Equilibrium PRESSURE :

773.01

psia

116

Experimental pressure 800.6 psia

Press RETURN to Continue . . .

Equilibrium Hydrate : STRUCTURE II Composition of Phases at Equilibrium FEED .7160 .0473 .0194 .0079 .0596 .1419 .0079

Methane Ethane Propane n-Butane Nitrogen Carbon Dioxide n-Pentane

VAPOR .7160 .0473 .0194 .0079 .0596 .1419 .0079

LIQUID .7159 .0473 .0194 .0079 .0596 .1419 .0079

HYDRATE .6033 .0405 .2615 .0132 .0167 .0647 .0000

Press RETURN to Continue . . . Fractional Occupancy of Cages SMALL .7630 .0000 .0000 .0000 .0221 .0679 .0000

Methane Ethane Propane n-Butane Nitrogen Carbon Dioxide n-Pentane

LARGE .1036 .1094 .7064 .0358 .0011 .0390 .0000

Do you wish to do another calculation at the SAME composition? (No=1 Yes=2) 1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

2 Enter the required Temperature (in 33.71

F)

Enter the WEIGHT PERCENT of Methanol (up to 50wt%) 20 FOUR-PHASE (Lw-H-V-Lhc) EQUILIBRIUM CONDITION WITH INHIBITOR(S) Inhibitor :20.00 wt% Methanol Temperature : 33.71 F Equilibrium PRESSURE :

566.2

psia

117

Experimental pressure 691.8 psia

Press RETURN to Continue . . . Equilibrium Hydrate : STRUCTURE II Composition of Phases at Equilibrium FEED .7160 .0473 .0194 .0079 .0596 .1419 .0079

Methane Ethane Propane n-Butane Nitrogen Carbon Dioxide n-Pentane

VAPOR .7159 .0473 .0194 .0079 .0596 .1419 .0079

LIQUID .7159 .0473 .0194 .0079 .0596 .1419 .0079

HYDRATE .5931 .0367 .2772 .0139 .0150 .0642 .0000

Press RETURN to Continue . . . Fractional Occupancy of Cages SMALL .7618 .0000 .0000 .0000 .0199 .0709 .0000

Methane Ethane Propane n-Butane Nitrogen Carbon Dioxide n-Pentane

LARGE .0786 .0991 .7487 .0375 .0007 .0317 .0000

Do you wish to do another calculation at the SAME composition? (No=1 Yes=2) 1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

7 THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE (1) (2) (3) (4) (5) (6)

MAIN Program for Equilibrium Hydrate Predictions Display CURRENT Feed Composition Change FEED Composition Change Program UNITS DISCARD all Data and begin NEW Problem Exit HYDOFF Program

6 End of run : HYDOFF Stop - Program terminated.

118

Example 3 - Temperature and Pressure predictions with salt(s) (experimental data by Dholabhai, P.D., et al. (1994)) HYDRATE PREDICTION PROGRAM:

HYDOFF

(ACCOMPANYING THE OFFSHORE HYDRATE HANDBOOK) Release Date : July 3rd, 1997 COPYRIGHT : Professor E. Dendy Sloan Center for Hydrate Research Department of Chemical and Petroleum-Refining Engineering Colorado School of Mines, Golden, CO 80401 PHONE:(303) 273-3723

FAX:(303) 273-3730

This program has been designed to provide phase equilibria of hydrates in a manner consistent with available experimental data. Your comments and feedback are welcome for future improvement of the program. Press RETURN to continue ... AVAILABLE UNITS ARE AS FOLLOWS : (1) (2)

TEMPERATURE Fahrenheit Kelvin

PRESSURE psia kPa

Please select the desired set of Units : 1 The program has been designed to allow the user to input the feed components and composition directly in the program or through an external file, namely, FEED.DAT If the user wishes to read the feed components and composition from FEED.DAT, please make sure the information is entered correctly into FEED.DAT (user has to CHANGE the COMPOSITIONS ONLY) and FEED.DAT is in the same directory as the executable HYDOFF.EXE file.

Is the FEED COMPONENTS and COMPOSITION saved under FEED.DAT (No=1 Yes=2)? 1 How many COMPONENTS (excluding Water) are present? 2 sII HYDRATE FORMERS 1. Methane 4. i-Butane 7. Nitrogen

2. Ethane 5. n-Butane 8. Carbon Dioxide NON-HYDRATE FORMERS

119

3. Propane 6. Hydrogen Sulfide

9. n-Pentane 13. Octane

10. i-Pentane 14. Nonane

11. Hexane 15. Decane

12. Heptane 16. Toluene

Which Components are present? Please list Hydrate formers first 1 8 Enter the MOLE FRACTIONS of each Component : Mole Fraction of

Methane

: 0.8470

Mole Fraction of

Carbon Dioxide

: 0.1530

THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE (1) (2) (3) (4) (5) (6)

MAIN Program for Equilibrium Hydrate Predictions Display CURRENT Feed Composition Change FEED Composition Change Program UNITS DISCARD all Data and begin NEW Problem Exit HYDOFF Program

1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

1 Enter the required Temperature (in 40.01

F)

THREE-PHASE (Lw-H-V) EQUILIBRIUM CONDITION Temperature : 40.01 F Equilibrium PRESSURE :

496.75

psia

Experimental pressure 494.6 psia

Press RETURN to Continue . . .

Equilibrium Hydrate : STRUCTURE I Composition of Phases at Equilibrium Methane Carbon Dioxide

FEED .8470 .1530

VAPOR .8470 .1530

Press RETURN to Continue . . .

120

HYDRATE .7222 .2778

Fractional Occupancy of Cages SMALL .7737 .1034

Methane Carbon Dioxide

LARGE .6610 .3191

Do you wish to do another calculation at the SAME composition? (No=1 Yes=2) 1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

a given given T given T given T

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

5 Enter the MOLE FRACTIONS of each Component : Mole Fraction of

Methane

: 0.823

Mole Fraction of

Carbon Dioxide

: 0.177

PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

a given given T given T given T

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

3 Enter the required Temperature (in 47.93

F)

Enter the WEIGHT PERCENT of Salt 5.02 THREE-PHASE (Lw-H-V) EQUILIBRIUM CONDITION Inhibitor : 5.02 wt% NaCl Temperature : 47.93 F Equilibrium PRESSURE :

980.03

psia

121

Experimental pressure 1012.4 psia

Press RETURN to Continue . . .

Equilibrium Hydrate : STRUCTURE I Composition of Phases at Equilibrium FEED .8230 .1770

Methane Carbon Dioxide

VAPOR .8230 .1770

HYDRATE .7150 .2850

Press RETURN to Continue . . . Fractional Occupancy of Cages SMALL .8028 .1136

Methane Carbon Dioxide

LARGE .6566 .3305

Do you wish to do another calculation at the SAME composition? (No=1 Yes=2) 1 PLEASE CHOOSE ONE OF THE FOLLOWING OPTIONS (1) (2) (3) (4)

PRESSURE Pressure Pressure Pressure

PREDICTION prediction prediction prediction

at at at at

(5) (6) (7) (8)

Change FEED Composition Change UNITS Return to MAIN Menu Quit HYDOFF

a given given T given T given T

TEMPERATURE with Methanol with Salt (NaCl) with Salt+MeOH

7 THE FOLLOWING OPTIONS ARE CURRENTLY AVAILABLE (1) (2) (3) (4) (5) (6)

MAIN Program for Equilibrium Hydrate Predictions Display CURRENT Feed Composition Change FEED Composition Change Program UNITS DISCARD all Data and begin NEW Problem Exit HYDOFF Program

6 End of run : HYDOFF Stop - Program terminated.

122

B.2. XPAND

B.2.a. Program Overview This program is used to calculate Joule - Thomson cooling of a gas with expansion across a restriction, such as a control valve. Please note that this program can only calculate gas expansions which contain methane, ethane, propane, n-butane, i-butane, and i-pentane. The program will not accurately calculate expansions for gases containing nitrogen, carbon dioxide, or hydrogen sulfide.

B.2.b. Running the Program The file is located in the floppy which has been attached to this handbook. To install XPAND: 1) Insert the disk into the drive. 2) Copy the file XPAND.EXE from the disk to the hard drive. 3) Obtain/copy the file DOSXMSF.EXE to the same hard drive directory. After copying, to access the program on your computer, you must be in MSDOS or a Windows MS-DOS prompt. To run XPAND, do the following: 1) Locate the directory which contains XPAND.EXE and DOSXMSF.EXE 2) Type “XPAND” The program will run and with the initial display “Enter the number of components”. Execute the program through the following steps: 1) Enter the number of components in the expanding gas. The value entered must be between 1-6. 2) A menu will be displayed listing six different gas components. Select the components which are present in the natural gas by entering the number corresponding to each component and pressing . Continue to do this until all the components in the gas are entered. 3) A screen appears requesting input of the mole fraction of each component specified in the previous screen. After entering each value, press . Note: The composition of the gas has to be entered on a mole fraction basis and not on a mole % basis. 4) A prompt appears requesting you to enter the following a) the upstream pressure (psia) before the gas expansion, b) the upstream temperature (oR) before the gas expansion, and

123

c) the downstream pressure (psia). Press after each entry. 5) A prompt appears requesting input of a first guess (oR) of the downstream temperature T2. This guess is the decreased temperature after expansion. Once T2 is entered, a table appears listing the initial conditions and the ∆H across the expansion. For Joule-Thomson cooling, at the correct T2 the ∆H across the expansion should be negligible (zero). Consequently, guesses for T2 should be input until the ∆H is within ±0.500 BTU/lbmol. Once this is done, record the XPAND initial and final conditions, before pressing enter to leave the program.

B.2.c. Output from the Program This method may be used to get the final temperature upon expansion of a gas from an upstream temperature and pressure to a downstream pressure. However, because the expansion curves are not linear in pressure and temperature, repeat this process with the same upstream temperature pressure, but with several intermediate downstream pressures. Plot the ∆H=0 expansion pressure-temperature line to determine an intersection with the hydrate formation line, obtained using HYDOFF.

Example 1 - Step-by-step calculation of the gas expansion found in Example 12, Section II.F.3. These steps were used to calculate the final temperature of a gas expanded from 1500 psia, 100 oF to 300 psia.

Gas Composition:

Component

Mole %

Methane Ethane Propane i-Butane n-Butane i-Pentane

92.70 5.30 1.40 1.40 0.34 0.14

Enter the number of Components: 6 Which components are present? 1= CH4, 2= C2H6, 3= C3H8 4= i-C4H10, 5= n-C4H10, 6= i-C5H12 Component 1: 1 Component 2: 2

124

Component 3 Component 4 Component 5 Component 6

3: 4: 5: 6:

Enter the mol fraction of each component. Methane: 0.927 Ethane: 0.053 Propane: 0.014 i-Butane: 0.014 n-Butane: 0.0034 i-Pentane: 0.0014 Enter P1 (psia): 1500 Enter T1 (R): 559.7 Enter P2 (psia): 300

1st

Input your guess for T2 (R) (Enter “0” to exit the program). 520 8.336287E-01 9.461145E-01 P1 = 1500.000 psia P2 = 300.000 psia

Guess

T1 = 559.700 R T2 = 520.000 R

1st delta H = 891.234 BTU/lbmol Ideal gas delta H = -376.414 BTU/lbmol 2nd delta H = 201.219 BTU/lbmol Total delta H = 313.602 BTU/lbmol 1st delta S = Ideal gas delta S = 2nd delta S = Total delta S =

.179 BTU/lbmol-R 2.501 BTU/lbmol-R .059 BTU/lbmol-R 2.620 BTU/lbmol-R

If the above values are unsatisfactory, enter another guess for outlet temperature in degrees Rankine.

2nd Guess

Input your guess for T2(R) (Enter “0” to exit the program). 500 8.336287E-01 9.377816E-01

125

P1 = 1500.000 psia P2 = 300.000 psia

T1 = 559.700 R T2 = 500.000 R

1st delta H = 891.234 BTU/lbmol Ideal gas delta H = -562.102 BTU/lbmol 2nd delta H = 216.348 BTU/lbmol Total delta H = 112.784 BTU/lbmol 1st delta S = Ideal gas delta S = 2nd delta S = Total delta S =

.179 BTU/lbmol-R 2.136 BTU/lbmol-R .070 BTU/lbmol-R 2.245 BTU/lbmol-R

If the above values are unsatisfactory, enter another guess for outlet temperature in degrees Rankine.

3rd

Input your guess for T2(R) (Enter “0” to exit the program). 488.7 8.336287E-01 9.324399E-01 P1 = 1500.000 psia P2 = 300.000 psia

Guess

T1 = 559.700 R T2 = 488.700 R

1st delta H = 891.234 BTU/lbmol Ideal gas delta H = -665.909 BTU/lbmol 2nd delta H = 225.689 BTU/lbmol Total delta H = -.364 BTU/lbmol 1st delta S = Ideal gas delta S = 2nd delta S = Total delta S =

.179 BTU/lbmol-R 1.926 BTU/lbmol-R .078 BTU/lbmol-R 2.027 BTU/lbmol-R

If the above values are unsatisfactory, enter another guess for outlet temperature in degrees Rankine. Input your guess for T2(R) (Enter “0” to exit the program). 0

The 3rd guess of T2 = 488.7 oR resulted in a XPAND calculation of ∆H = - 0.364 BTU/lbmol for the 6 component gas mixture. This value of Total delta H is sufficiently close to zero indicating an isenthalpic expansion process. This result indicates that a pressure drop from 1500 psia, 100 oF to 300 psia will cause a gas temperature reduction to 29 oF (488.7 oR). Several such calculations at intermediate downstream pressures should be done, because the expansion P-T line is non-linear. The intersection point of the P-T expansion line (obtained from several XPAND calculations) with the hydrate formation line (obtained from HYDOFF) will differ from the intersection point obtained by just using a straight line drawn between

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the two end points for the P-T expansion (1500 psia, 100 oF, and 300 psia, 29 oF) and the hydrate formation line

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Appendix C - Additional Case Studies of Hydrate Blockage and Remediation Case Study C.1*1 Placid experienced a hydrate plugging problem in an export pipeline. The prospect was located at Greens Canyon Block 29 in the Gulf of Mexico in 1527 ft of water. A flexible line was installed between the floating production platform to the top of a rigid riser, located 200 ft below the water line. The flexible pipe was 12 inch ID and 16 inch OD with a working pressure rating of 2160 psi. The export line carried gas and condensate over a distance of 52 miles. Flowing conditions prior to the blockage were 12 MMSCFD of gas, 5500 BOPD condensate. The API oil gravity was 49. The gas gravity was 0.68. The pipeline inlet conditions were 70oF and 1050 psi. Over the first few weeks of production, the wells did not produce significant quantities of water. To save operating costs, the gas dehydrators were shut down. When additional wells were brought onstream, there was some residual water-base completion fluid being produced. When the wet gas and condensate entered the cold export line (65oF), water condensed and accumulated at the bottom of the catenary loop in the flexible line at 200 ft below the surface. Since the line was not being pigged, water was being accumulated in this low spot. The high pressure gas exposed to the cold water in the flexible line formed a complete hydrate blockage over a period of 14 hours, causing the line pressure to increase to 1800 psi before production was stopped. The blockage was located by venting the gas above the plug and filling the void with liquid. The volume of liquid and pressure was recorded. The volume of fluid required to fill the line corresponded to approximately 200 ft of pipeline, suggesting that the blockage was located near the surface. The blockage length was suggested to be 8 to 10 ft long. The export line was depressurized on both sides and the gas dissociated from the hydrates was vented. The line was successfully pigged with the product gas and condensate the next day. This incident resulted in three days of production downtime at an operating cost of $40,000. To prevent hydrate formation three changes were made to the pipeline operations: -methanol was injected -gas was continuously dehydrated and -the line was cleaned periodically with foam pigs.

1

Studies from DeepStar II.A. CTR 208A-1 by Mentor Subsea (1996) denoted by “*”

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Case Study C.2* Chevron had a 4 inch OD, 2200-ft long gas flowline plugged with hydrates during the winter. This flowline is in the Whitney Canyon field located in the Carter Creek area of Wyoming. The flowing conditions were 120°F and 360 psig at the wellhead. The ground surface temperature was -20°F, which was well below the hydrate formation temperature at 360 psig. The flowline is wrapped with heating tape and insulation to keep the line warm enough to prevent freezing or hydrate formation. Before this blockage occurred, there were no hydrate inhibitors used. A corrosion inhibitor was used to prevent corrosion. The line is not equipped for pigging. The line ID is 3.826 inch with a working pressure limit of 1800 psi. The flowline material is carbon steel A333. The heat input was lowered to conserve electrical energy consumption. However, there was no mechanism to monitor the fluid temperature throughout the line to insure that hydrates would not form as the heat input was reduced, a blockage occurred. A combination of depressurization, chemical, and thermal techniques was used to remove the plug. First, the pressure on both sides of the plug was equalized so that the plug would not move like a projectile. Then, the pressure on both sides of the plug was reduced. Methanol was injected upstream of the hydrate plug. Then, the line was heated using the heating tape. This was effective in dissociating the hydrate plug. Production was shut down for one day for this remedial operation. There were several lessons learned from this experience. Future operations considered the use of hydrate inhibitors in the winter months. Currently Chevron is installing pumps to inject a kinetic inhibitor or alternative cost-effective chemicals.

Case Study C.3* In Chevron's platform operations in the Gulf of Mexico, typically, hydrates form in the gas-lift distribution valves on the platform. The gas is generally not dehydrated. In the winter as the gas is throttled through the distribution valve, the Joule-Thomson cooling across the valve drop causes hydrate formation (see Section II.E). The gas pressure is approximately 1100 psi. The problem is usually not severe. Since surface access is usually available to the blocked location, methanol can be injected to clear the blockage in the line. To prevent this problem, typically, methanol is injected. One solution recently being tested is to vary the gas flow rate to keep the valves and gas distribution lines warm enough to keep them above the hydrate formation temperature.

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Case Study C.4* Chevron reported a hydrate problem in their Carter Knox field in South Central Oklahoma. Hydrates formed in an uninsulated 4 inch Schedule 80 (4 inch ID, 4 ½ inch OD) sales gas line. Flowing wellhead conditions were 105°F and 5750 psi. After choking the well stream to 620 psi at the production unit, the temperature drops to approximately 62°F at the pipeline inlet. The production unit is designed to remove liquids from the well stream but the gas is saturated with water vapor and there is always some liquid carryover into the vapor phase. In the winter when the ambient temperature is in the upper 40's, the gas cools rapidly due to the cold environment. Before hydrates formed, there was no methanol or other chemicals injected at the wellhead or at the processing unit. The well was flowing 200 bbl/day of oil (API 57) and 7.5 MMscf/d of gas. Water production rate was 10 bbls/day. Two flow meters were installed about 120 ft downstream from the production unit on the sales line. One meter is 4 inch ID with a 2 1/4 inch orifice plate and another meter is 3 inch ID with a 2 1/8 inch ID orifice plate. Additional pressure drop occurred under flowing conditions at the second meter. This caused hydrates to form at the second meter. In fact, the hydrate accumulation near the meter caused an erroneous flow reading that deviated from the first meter. This was an early indicator of the hydrate formation and it was detected before a complete blockage occurred. It took several hours for the hydrates to form. To remove the hydrate plug, the line was depressurized and a pump injected methanol into the line. The production unit was pre-heated to 190°F prior to start-up. It took four hours to completely remove the hydrate accumulation. Furthermore, production was shut down for about eight to ten hours. Based on this experience, methanol is currently injected at the rate of 10 gallons/day whenever ambient temperature drops below 50°F. The operator is currently considering changing the 3 inch ID flow meter to a 4 inch ID flow meter to eliminate the restriction in the sales line.

Case Study C.5* Chevron reported several incidents of hydrate blockages in onshore gas gathering lines in Canada. In one incident, a complete blockage formed in a 6 inch, 15 mile pipeline. The pipe was X42, rated to a working pressure limit of 1000 psi. The line was insulated with a polymer coating which is sufficient to keep the gas above the hydrate formation temperature under flowing conditions. The condensate content was approximately 20 bbls/MMscf. Although there was no free water, the gas was saturated with water vapor at the pipeline inlet pressure and temperature. The condensed water contributed to forming the hydrate plug. Ambient temperature is approximately 3 to 5°C (37 to 41°F). The blockage occurred during an extended

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shut-in period over a 300-ft section underneath a road crossing. Previously, hot taps had located a blockage in the same location. While hot tapping was an option, in this case, it was considered too risky. Furthermore, hydrates do not typically form in these 6 inch lines if depressurized within the first 24 hours. To remove the blockage, two methods were used simultaneously. First, the line was depressurized on both sides of the plug. Then, a welding rig applied electrical current directly to the 300-ft section of the steel pipe. The line was heated to 20 to 25 °C (68 to 77°F) using the welding rig. This approach was effective in melting the hydrate plug. The remedial operation took two days to complete.

Case Study C.6* LASMO experienced a wax and hydrate combination in its Staffa field in the UK sector of the North Sea in 1993. A single, uninsulated, 8 inch flowline was installed between two satellite wells and a minimum processing platform facility (Ninian Southern Platform), located 6.3 miles away. Furthermore, there was no capability of round-trip pigging the line because a single line was used. The seabed terrain near the tree was uneven and the flowline passed over another flowline about 1.2 to 1.9 miles from the tree. Production conditions were 6000 BOPD with a GOR of 1600 scf/bbl, 0.5 to 1% water cut. The produced fluid consisted of a high GOR, high API gravity crude with some water. Fluids were produced from the reservoir by a pressure decline mechanism. The average cloud point temperature of the crude oil was 79°F. The wax content in the crude oil was 5%. The flowing wellhead conditions were 942 to 1595 psia and 122 to 194°F. Due to the very high heat losses to the sea through the uninsulated line, the unseparated multi-phase stream cooled to the seabed temperature within 1.2 to 1.9 miles from the tree. The fluid arrived at the platform at a temperature of 44°F, which was well below the wax cloud point temperature. Without thorough documentation, it is believed that hydrate formation (due to erratic methanol injection) might have served as a nucleation point to cause wax precipitation in this line. In any case, wax deposited in the flowline within a period of several days after production was started. Even though certain paraffin inhibitors were used, they were not completely effective. Periodically, the flowline was soaked with chemical solvents without much success. Sometimes, pressure was applied to force the plug, but this actually exacerbated the problem by accumulating the paraffin into a ball. Thermochemical, heat generating chemicals were considered, but were rejected because they were considered relatively new technology.

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As a contingency plan, LASMO developed an inductive heating coil to be deployed using an ROV to heat the flowline and melt the wax inside the line. Although this technique was developed, it was never implemented in the field. Two problems with this technique were that a significant amount of power and time were required to heat the flowline and its contents. Furthermore, even after melting the wax and flowing it, it could cool and re-deposit before arriving at the platform. Approximately 1.2 miles of the pipeline, filled with a wax blockage, was cut out and replaced. Even after replacing the blocked section of the line, the line became plugged with wax a second time. Injection of chemical inhibitors, methanol or solvent soaking did not work. In 1995 due to multiple problems with hydrates and wax, LASMO abandoned the field. Repeated attempts to clear the blockages with chemical such as methanol have failed and the operated decided that it was not economical, considering the amount of reserves remaining, to replace another section of pipe as was done in 1993.

Case Study C.7* Texaco experienced a hydrate plug in a 12-3/4 inch gas export line at a platform, located in Garden Banks 189. The water depth is 725 ft. The line connects to a larger gas transportation line located on the seafloor. In this case, the gas was not dehydrated sufficiently before pumping the gas into the export line. As a result, the water vapor condensed and settled out in an U-bend at the bottom of the riser. The condensed water collecting at the low spot formed hydrates. In this case, hydrates formed very rapidly and formed a near-complete blockage before it was detected. The line injection pressure rose very rapidly. To remove the hydrate plug, the gas was vented from the platform end and methanol was lubricated down the riser. The line had a check valve downstream of the riser to prevent gas from backflowing to the platform. After injecting some methanol, the hydrates completely melted and the line was cleared. A total of twenty to thirty 55-gallon drums of methanol was used for the entire operation. Production of 8000 bbls of liquid/day and 70 MMscf/d from the platform was shut down for two to three days during this remedial operation.

Case Study C.8* Texaco reported a hydrate restriction in another gas export line from a platform at Greens Canyon Block No. 6 in 600 ft. of water. In this case, hydrates slowly accumulated in a 10-3/4 inch line over a period of several days. While production was not shut down, two actions was taken to remove the restriction: (1)

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the gas dehydrator was turned on to remove water vapor from the gas stream and (2) methanol was injected into the gas export line.

Case Study C.9* Texaco also reported a gas hydrate blockage in an instrument isolation valve block in their Strathespay field in the North Sea. However, there have been no reports of hydrate blockage in the flowline because the line is adequately insulated. This field is located in 442 ft of water. The valve block has a 1/4 inch ID port leading to a pressure transducer. Since the fluid is static in this section of the line, the produced gas had water vapor that condensed and formed hydrates. The valve block and pressure port is uninsulated and exposed to very cold seawater (4°C). The hydrate blockage resulted in erroneous pressure transducer readings. To remove this blockage, the line was purged with methanol. Periodically, the line is now purged with methanol to prevent this problem. This workover operation, however, is undesirable and increases operating cost. One design flaw with this system is that the transducer line (1/4 inch ID) is situated above the valve block. Even if this line is periodically filled with methanol, the fluid will drain out and into the flowline. This will allow the wet gas to enter the transducer line and plug it with hydrates. One design option is to change the orientation of the valve block so that the transducer line is connected to the bottomside of the valve block instead of the top side. With this configuration, the line can be filled with an oil-based gelled fluid, mixed with methanol, glycol or an oil-based fluid between the flowline and the transducer sensor. Otherwise, it may fill with water, causing hydrate formation. In deepwater systems where transducers may be changed as part of a larger system, isolation valves may not be necessary.

Case Study C.10* Elf Norge has reported hydrate formation in their North East Frigg subsea flowline. The 16 inch flowline transported gas condensate from a subsea template with six wells, located 11.1 miles from the Frigg platform. During some period, only one well was flowing at a rate of 35 MMscf/d. At this low gas flow rate, most of the water and condensate settled out and accumulated in the pipeline. After a few days, the gas flow rate was increased by starting three other wells. After the gas flow rate increased to 70 MMscf/d, the pressure and liquid level in the inlet gas-liquid separator became unstable. The wells were shut down. The separator was found filled with hydrates. Samples taken from the separator contained large, solid blocks of hydrates, which took about one day to melt.

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Analysis of the liquid samples showed that the methanol content was 11-wt%, which was well below the 26-wt% required to avoid hydrate formation. However, Elf reported that the flowline did not plug with hydrates although it experienced subcooling up to 6°C. Hydrates were found just downstream of the choke on the platform. Due to Joule-Thomson cooling (see Section II.E) the gas/water mixture experienced the lowest temperature downstream of the choke. Before re-starting production, the separator was depressurized and circulated with steam to remove the hydrates. About 9000 gal of methanol were injected into the pipeline inlet, the outlet and upstream of the pipeline outlet choke. An additional 21,000 gal of methanol was injected during the first two days of restart, when the gas flow rate was gradually re-established. The liquid outlet valve of the inlet separator was severely eroded during the hydrate formation period. This might have been due to a combination of metallic particles, scale, or hydrate crystals flowing at high velocities through the valve. The valve had to be replaced. Another reason for forming hydrates downstream of the choke was the lack of an upstream heater. In many subsea completions, a heater is installed upstream of the separator and choke to prevent hydrates or wax formation and to improve the separation efficiency.

Case Study C.11* The following information was provided by Marathon on gas hydrate formation observed in a gas export pipeline from their Ewing Bank 873 platform in the Gulf of Mexico: "Hydrate formation occurs in the gas export line from the Ewing Bank 873 platform The line leaves the platform and contains a 900-ft deep loop before joining a subsea "T" connection. The line is 8 inch nominal size. The water depth ranges from 775-ft at the EW 873 platform to a maximum of 950-ft then 470-ft at the subsea connection. Seafloor temperature is estimated to be 55°F. Hydrate formation is inferred from pressure buildup in the line, and the fact that methanol can be successfully used to remediate. Methanol is pumped continuously for inhibition at approximately 140 gal/day for 32 Mmscf/d. The pressure drop in the line is a function of flow rate. It is normally in the range of 50 to 100 psi, depending on flow rate. It can be modeled accurately. If it increases much beyond the normal level (say an additional 30 psi), then a slug of methanol is periodically pumped. The hydrate restriction appears to be between the EW873 platform and the low point. Pigging has not been attempted, for a variety of reasons, but primarily due to high risk for minimal benefit. Methanol is cheap and low risk. The routine technique of depressurizing the line is not used at EW 873 because shutting-in production would be required."

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Case Study C.12* Phillips reported gas hydrate plugging problems in their Cod pipeline in the North Sea. The pipeline is 47 mile, 16 inch (ID=15.124 inch) carbon steel, designed to transport gas and gas condensate from the Cod platform to the Ekofisk center. The liquid is a light hydrocarbon with a specific gravity of 0.66. The current Cod production is approximately 35 MMSCFD and 1700 BPD of condensate. Gas hydrates completely plugged the Cod pipeline several times. In March 1978 hydrates formed and a pig became stuck in the hydrate accumulation. The hydrates were removed by depressurizing the line. The line was backflowed in an attempt to remove the pig. The backflow attempt was unsuccessful. While the pigs remained in the line, the restriction did not prevent the gas flow. A slug of 1700 gallons of methanol was pumped to try to dissolve all the hydrates in the line. During the re-start, methanol was continuously injected into the pipeline. On the Cod platform, even though the gas stream was dried adequately, the liquid condensate stream was not dried properly. Therefore, the wet condensate stream mixed with the high-pressure gas to form hydrates in the pipeline. Since 1981 the operating pressure has declined so that the pipeline is now operating outside the hydrate-formation conditions.

Case Study C.13* Texaco performed field tests in several of their Wyoming wells to evaluate the use of PVP, a kinetic inhibitor (see Section II.F.2.b). The kinetic inhibitor can be used at very low concentrations, ranging from 1/2 to 1 wt% instead of using 10 to 50 wt% of methanol to achieve the required level of hydrate inhibition. Prior to the field tests, these Wyoming wells and flowlines were experiencing hydrate plugging problems in the wells and the surface flowlines at methanol injection rates of 30 gallons/day. Flowing wellhead conditions were up to 2000 psi and 52 to 56 oF. Gas production ranged from 0.8 to 1.4 MM scf/d. Freshwater production rate ranged from 2 to 40 bbls/d. Methanol was replaced with a 4% polyvinylpyrrolidone (PVP) solution. The 4% PVP solution consisted of 4-wt% PVP, 16-wt% water and 80-wt% methanol. The PVP solution was pumped at a rate of 2 to 21 gallons/day, representing an aqueous phase concentration of less than 0.05 wt%. At these concentrations, the kinetic inhibitor was effective in preventing hydrates. This represents a cost savings in the order of 50% compared to using 100% methanol.

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Case Study C.14* Similar to Case Study 13, Texaco conducted another series of field tests in East Texas to evaluate PVP, a kinetic gas hydrate inhibitor. In this field, tests were conducted on 4 inch to 6 inch flowlines that were one to eight miles long. The gas flow rate ranged from 1 to 24 MM scf/d. Water flow ranged from 0.8 to 40 bbls/day. Similar to the Wyoming field tests, hydrates formed rapidly when the methanol rate was greatly reduced. Following depressurization subsequent hydrate plugging was prevented by injecting the kinetic inhibitor at concentrations in the range 0.1 to 0.5 wt% of the aqueous phase. Texaco has completed extensive testing of kinetic gas hydrate inhibitors in onshore U.S. fields. Many of their fields are currently using kinetic inhibitors to reduce methanol consumption costs. Texaco is continuing to experiment with alternative chemicals for optimizing costs and for application in offshore flowlines.

Combined Case Study C.15 Statoil conducted 19 controlled field experiments of gas hydrate blockage formation and dissociation. A comprehensive summary is listed in the references by Austvik et al., 1995, 1997. The experiments were done in 1994 using a 6 inch test/service subsea line in their Tommeliten Gamma field. The line is connected to the Edda platform, located 7.1 miles away from the subsea manifold. Two, 9 inch production lines and one 6 inch test/service line are installed to carry the flow from a subsea production manifold. The manifold gathers the flow from six subsea wells. Condensate content is 16wt% and water content is 2wt%. Nineteen hydrate formation and dissociation experiments were conducted using the 6 inch test/service line, in three types of experiments as follows: 1. Continuous flow - Statoil lowered the flowing temperature by reducing the flow rate and entered the hydrate region. 2. Continuous flow without methanol injection- Production rate was reduced and methanol injection is stopped. 3. Re-start after shut-in using four approaches: a. Cool pressurized line; re-start without methanol injection. b. Cool pressurized line; re-start with 5-wt% methanol injection. c. Pressurize line from template side; re-start at high flow rate. d. Pressurize line from platform side; re-start at high flow rate.

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During these experiments, Statoil measured pressure and temperature at the following places: (1) at the manifold, (2) at the top of the riser upstream of the heater, (3) at the choke, and (4) in the separator. Statoil also used two gamma densitometers to detect the arrival of slugs and hydrate lumps on the platform. A thermocamera was used to detect the temperature profile of the topside lines and to detect ice/hydrate formation. Table C.1 summarizes the observations in these field tests and operations used to form and remove hydrate blockages. Following are general conclusions reported by Statoil on these field experiments: 1. Hydrates formed easily and rapidly after fluid conditions entered the hydrate region. In some cases, hydrate chunks flowed to the platform and plugged the topside piping, valves and bends. 2. Underinhibition of methanol increases rate of hydrate formation and risk of plugging. Field tests were done at 5-wt% methanol. Laboratory tests performed with 10 to 20-wt% methanol also found similar results (reported by Yousif et al., 1996). 3. Hydrate plugs were porous and permeable. hen the plug was subjected to a differential pressure, the gas from the manifold side flowed through the plug. This was indicated by a gradual drop in pressure at the manifold when the gas was being vented from the platform side. See Case Study 12 (Section III.B.2.b) for a plug less permeable to a Statoil black oil. 4. Gas flow through the plug causes Joule-Thomson cooling leading to additional hydrates or ice. If additional hydrates or ice form in pore spaces within the hydrate plug, the dissociation rate will be reduced. 5. Combinations of depressurization and methanol injection were effective to remove all plugs. Methanol can be injected at the manifold end or at the platform end. 6. Methods to remove hydrates in the topside piping include injecting methanol and/or spraying warm water on the outside surface. However, heating the pipe from the outside can be risky. If the gas released from hydrate dissociation is not properly vented, the trapped gas may potentially over-pressure the line. 7. Statoil also concluded that the results and recommendations developed from these field experiments cannot be directly applied to other fields with different conditions and fluid compositions.

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Case Studies C.16 and C.17 This case study summarizes two blocking events in the above Statoil field study on hydrate formation in the Tommeliten Field of the North Sea. Case Study C.16. The experiment originated as a depressurized line that was brought into production. Methanol was injected continuously into the line throughout the start-up process to prevent hydrate formation. When the production reached a rate of 12 MMscf/d, methanol injection was stopped, allowing hydrates to form at the temperatures of 60oF. The riser temperature was 16oF below the hydrate formation region. After several partial blocking events, a complete hydrate plug formed approximately 2.5 miles from the platform. (26 hours after start-up). The plug location was estimated from evaluating the rate of pressure change on both plug sides. Upon blockage, the pipeline was depressurized to dissociate the hydrate plug. Additionally, 3400 gallons of methanol were injected into the wellhead to assist in dissociation. Due to the fact that MeOH had to travel five miles, the horizontal nature of the pipeline, small buckling in the pipeline, and liquid present in the pipeline, it is believed that the MeOH never reached the plug. One-sided depressurization of the pipeline removed the plug after seven days. The total blockage time was 25 days.

Case Study C.17. The uninhibited line was shut-in at full well pressure and cooled to ambient sea temperature. The line was then started and began producing at a rate of 12MM scf/d without any methanol present. The production line was maintained for 40 hours without any hydrate blockage of the line. Several blocking events occurred topside before a blockage occurred somewhere between the template and riser. After observing pressure changes on both sides of the plug, it was determined that the plug was approximately 2.5 miles away from the platform. The hydrate plug was removed through one-sided depressurization. The hydrate plug dissociated slowly, taking nine days before it was removed. Figure C.1 shows the measured pressure difference across the two plugs in Case Studies C.16 and C.17 as a function of time. These curves have been generated removing large pressure fluctuations that occurred while reducing the pressure. The figure highlights the change of permeability of the plug as a function of time. Figure C.2 shows the pressure in the riser during the hydrate removal process. The equilibrium pressure for the hydrate plugs was approximately 200 psi at the ambient temperature. Plug 1 was kept under the equilibrium temperature until it was dissociated. Plug 2 was temporarily kept above the equilibrium point to limit the cooling effects caused by Joule-Thomson cooling. It was thought that this practice had little effect on increasing the rate of dissociation.

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Figure C-1 - Pressure Difference Across Plugs (From Berge, 1996)

1600

Pressure Difference (psi)

1400 1200

Plug 1 (Case Study 16)

1000 800 600 Plug 2 (Case Study 17)

400 200 0 0

50

100

150 Time (hours)

200

250

300

Figure C-2 - Riser Pressure vs. Time (From Berge, 1996)

400 350

Pressure (psi)

300 250 Plug 1 (Case Study 16)

200 150 100 Plug 2 (Case Study 17)

50 0 0

50

100

150 Time (hours)

200

250

300

Case Study C.18 Occidental Oil and Gas Company reported hydrate blockages forming in a gas and associated condensate transport line located in the North Sea. Hydrate plugs usually form in subsea interfield pipelines and in the bottom of incoming risers. The export pipeline operates at 4930 psig with a wellhead temperature of 86oF, which cools down to the ambient sea temperature of 35oF at the outlet. The cold temperatures place the pipeline within hydrate formation conditions for the gas. To combat this, methanol is injected maintaining 25 wt% in the free water phase. Hydrates form when insufficient amounts of methanol are injected into the pipeline. Early symptoms of hydrate formation are increases in differential pressure and reductions in gas production. A late symptom of hydrate plugs is complete blockage of flow. When blockages occur in the pipeline, two methods are used to remediate plugs. The first method consists of methanol injection and depressurization of the pipeline from both sides; the usual time needed to remove blockages through this method is 1/2-1 days. Depressurization can be avoided by adding large volumes of methanol until dissociation occurs, the usual time needed to carry out this remediation is 4-14 days. Occidental also emphasized the importance of minimizing the differential pressures across the plug to prevent hydrate projectiles. Secondly, they emphasized that the pressure must be maintained above 87-145 psig. If the pressure drops below these values, the equilibrium temperature moves well below 32oF, causing ice formation. Ice cannot be dissociated through depressurization and consequently takes more time to remove than hydrate plugs.

Case Study C.19 Amoco reported hydrate plug formation in a 70 mile export pipeline located in the North Sea. Under normal operating conditions, the gas is dehydrated and then compressed from 350 psig to 1300 psig. The concentration of water in the gas phase is usually low enough to prevent free water formation. However, the line had not been pigged for three months and during that time offshore process upsets were thought to allow free water into the line. High pressure drops began to form in the pipeline, requiring pigging, but the pig became stuck in the line and had to be removed through flow reversal. Hydrate slush appeared with the pig on the offshore platform. After pigging, the pipeline became completely blocked with hydrates approximately 30 miles from the offshore platform. The amount of gas used to displace the pig was utilized to estimate the plugs location. Two possible tools for pipeline remediation were methanol injection and depressurization of the pipeline. Methanol could not be used as a remediation method because of the plug’s distant location; consequently two-sided depressurization became the only viable means of dissociating the hydrate plug. Depressurization was

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carried out over a two week period, and was done in slow steps to prevent any high pressure buildups due to multiple plugs. After eight weeks, the plug was completely dissociated and full production could resume. The line was restarted by slowly sweeping the pipeline with dry gas, building up to high gas rates. The line was consistently pigged, first with undersized pigs and then full-sized. No problems were witnessed during start-up. The hydrate remediation process lasted eight weeks and cost $500,000 to carry out. Overall, the plug shut-down production for three months and cost $5.5 million due to remediation expenses and loss of sales.

Case Study C.20 Petrobras reported a hydrate blockage in a subsea manifold, located around 2000 ft water depth. The manifold was initially loaded with water, and was not drained and loaded with ethanol prior to production start-up, as is normal practice. Consequently, a hydrate plug formed in the manifold, blocking valves in a production line. However, production was maintained through a test production line. Two methods were attempted to dissociate the pipeline. First, ethanol was injected into the manifold to begin dissociation. Some dissociation did occur (indicated by pressure increases), but the hydrate plug was still present after 2 days. Depressurization of the manifold was then used to dissociate the plug. Depressurization was carried out on both sides of the plug, dissociating the plug in twelve hours. Start-up of the pipeline was carried out by filling the manifold with ethanol and then resuming production. Overall, the hydrate plug was in the manifold for sixty days, but production was maintained throughout that time via a test production line. During depressurization, all production from the wells flowing into the manifold had to be shut down. The total economic loss due to the hydrate was 31,500 bbl oil and the wages of two engineers(1 week) and two technicians (3 days).

Case Study C.21 Barker and Gomez (1989) describe an Exxon experience with a hydrate in a well located in 1,150 ft of water off the California coast. While drilling, gas flowed into the well from the formation, channeling through the primary cement column at 7,750 ft, and the migrating gas entered the freshwater mud at the subsea wellhead. Due to difficulties with the wellhead hanger packoff, the gas influx was stopped by perforating the casing, with a result of severing the drillstring and stripping it up through the BOP’s until the severed drillstring end was above the gas sand.

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A through drillstring perforating gun was then run to shoot the 7 in. casing just above the gas snad. The gas influx was killed by pumping a 14.2 lbm/gal mud down the drillstring and into the formation at surface pressures up to 3,100 psi. At the conclusions of the kill operation, both the chokeline and the kill ine were found plugged. Subsequent operations were hampered by the inability to use either line. After cementing operations which secured the well bore, the BOP’s were recovered. Hydrates and trapped gas were found in the chokeline and the kill line of the bottom eight riser joints.

Case Study C.22 A second Exxon drilling instance was reportedby Barker and Gomez (1989) in 3,100 ft of water in the Gulf of Mexico, with a ocean bottom temperatuere of 40oF. Gas flowed into the well and plugged the choke and kill lines. After four days of warm drilling mud circulation, the lower-middle ram-type BOP’s could not be completely opened or closed, possibly because of hydrates in the ram-block recesses. The drillstring was perforated about 400 ft above the annular gas/liquid contact. After coiled tubing was run inside the drillstring, hot mud was circulated and gas was allowed to migrate into the coiled-tubing/drillstring annulus before being circulated out of the well. Three sets of successively shallower performations were required to remove the gas completely in the annulus. After all ram-type BOP’s were opened, the drillstring was backed off at 5,000 ft. and recovered, and a cement plug was set in the casing. The well was secured and the BOP’s were pulled, resulting in a recovery of hydrates. Testing of BOP’s at the surface indicated that the failure was not caused by mechanical failure from the BOP’s which were then free of hydrates.

Case Study 23 Davalath and Barker (1993) described a hydrate problem in 595 ft. of water located offshore South America. The well was completed with a 7 inch casing and 3.5 inch tubing. Production was gas and condensate at several hundred barrels per day with a water cut of about six percent. A 15 hour production test was followed by a 25 hour shut-in period to collect reservoir pressure buildup data. The well was shut-in at the surface, which exposed the tubing to high pressure gas and cold 45oF water, which led to the formation of hydrates. Under these conditions the tubing fluid was about 29oF below the hydrate formation temperature. Wireline tools were blocked by a bridge inside the tubing string and further pulling caused separation. Subsequently the lubricator was found to be full of hydrates.

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Attempts were made to melt hydrates by (1) pouring glycol into the top of the tubing, (2) using heated mud and seawater, (3) increasing the pressure up to 7,000 psi at the surface to break the hydrate plug. The above attempts were unsuccessful and the authors noted that the pressure increase caused a more stable hydrate, rather than blowing it from the tubing. A coiled tubing string was stripped inside the tubing and 175oF glycol was circulated to the hydrate plug at 311 ft. Direct contact with the hot glycol removed the hydrate plug but more than 13 days were lost because of this incident.

Case Study 24 Davalath and Barker (1993) also reported hydrate formation during well abandonment in the Gulf of Mexico. During normal production methanol was injected at the subsea tree. After stopping production the flow lines and tree piping were filled with seawater and corrosion inhibitor from the surface to the seafloor. During plug and abandonment operations, the operator found ice-like solids inside the tubing bore of the tree at the seafloor and in the annulus bore. The solid hydrate plugs were dissolved by circulating heated CaBr2 brine through a coiled tubing string run inside the tubing.

Case Studies 25, 26, 27 Three controlled hydrate field tests were completed on Devon Energy-Kerr McGee 900 psia gas condensate line in the Powder River Basin of Converse County, Wyoming from 1/27/97 to 2/20/97. The object of the tests was to show that one-sided depressurization can be safely performed in the field. As indicated in the Hydrate Plug Remediation portion (II) of this handbook, the standard onshore dissociation procedure is (a) to balance the pressure on both sides and (b) to reduce the balanced pressure to move outside of the hydrate region. The test line was 4 inch, 17,381 ft long from wellhead to separator-receiver (SRU-10) and pig receiver, and mostly buried to a depth of 5 ft with a ground temperature of 34oF. Elevation varied over 250 ft. Normally in winter, the flowline is continually treated with MeOH and pigged daily to prevent hydrate problems. The pipeline had the following instruments at five sites: (1) the wellhead (Werner-Bolley) with P,T sensors, 1.5” flow orifice, back-P control valve, and pig launcher, (2) 3,7852 ft downstream with P,T sensors and blowdown, (3) 5,395 ft downstream with P,T sensors, (4) 6,624 ft downstream with P,T sensing, methanol injection, blowdown capability, and dual gamma-ray sensors to monitor plug velocity, length, and density, (It was difficult to discern the differences between water, plugs, and condensate) and, (5) 11,483 ft with P,T, sensing. At the end of the

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line was a Separator-Receiver Unit (SRU-10) which contained a pig receiver and blowdown. Temperatures were not analyzed because the RTD was an external measurement. However, the pressures at the four sites, the orifice measurement, and the gamma ray measurements proved invaluable in analyzing hydrate formation and dissociation. The following steps were used to conduct a test: • Data collection initiated • Methanol injection stopped at the wellhead • Methanol injection begun at site 4 • Pig launched at site 1 and received at SRU-10 • Blockage formation monitored • Line isolated after blockage formation • Blockage dissociation by blowdown at sites 2,4, or SRU-10. The average steady state liquid holdup at Site 4 is 3.9%. The liquid in the water/condensate plugs was between 4.5 and 4.9%. Average superficial gas velocity was 6.3 ft/s in the pipeline, without blockages. Case Study 25 (Test 1) had 2 blockages. One relatively impermeable blockage was formed in the cold portion of the line between Sites 4 and 5. The other, more permeable blockage was formed in the warm portion of the line. Both were cleared by blowdown at site 4. The differential pressure across the blockages ranged between 112 and 174 psi, corresponding to a total load between 6,300 and 9,800 Newtons. Test 2 was aborted because hydrates formed upstream of site 2 (undesirable form a safety standpoint because site 2 is above ground with 2 ball valves and 2 45o bends. Hydrates were dissociated by reducing balancing the pressures on either side. Case Study 26 (Test 3) resulted in a short (25 ft) blockage with low permeability, which dislodged and passed site 4 with a speed of 270 ft/s, before eroding further down the pipeline. The differential pressure ranged from 271 to 475 psi, corresponding to a total load between 15,300 and 26,900 Newtons, about double that of more porous blockages. Case Study 27 (Test 4) had a blockage which formed on the downstream side of site 4 and then was moved upstream of site 4, via line depressurization at site 2. Each time the plug was driven past site 4, then lodged to form another, less permeable blockage. These plugs were longer (ca. 90 and 175 ft) than those of Test 3. On the next page is a table summarizing the characteristics of the plugs:

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Test Dates Block Time, hrs Plug Length, ft Max ∆P, psi Max Gas Sprfcl Velocity cm/s Max Load, n Leakage, Mass/ Load (g/s/n) Max plug Velocity, ft/s Shr Strss N/cm2

1 1/27-31/97 85 NA 174 12.07

2 2/1-5/97 62 NA Aborted NA

3 2/6-8/97 37 25 390 NA

4 2/19-20/97 143 90, 300, 30, 70 475 1.15

9857 0.00150.0067 NA

NA NA

2960 0.00029

26908 0.00038

NA

270

65

0.13

NA

2.14

2.29

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Appendix D. Rules-of-Thumb Summary A summary is presented for all of Rules of Thumb in the handbook, together with the Section from which they were extracted. As indicated at the outset, these Rules-of-Thumb are based upon experience and they are intended as guides for the engineer for further action. For example, using a Rule-of-Thumb the engineer might determine that a more accurate calculation was needed for inhibitor injection amounts, or that further consideration of hydrates was unnecessary. Rules-of-Thumb are not intended to be “Absolute Truths”, and exceptions can always be found; where possible the accuracy of the Rule-of-Thumb is provided in the appropriate Section. Rule of Thumb 1: (Section II.A) At 39oF, hydrates will form in a natural gas system if free water is available and the pressure is greater than 166 psig.

Rule-of-Thumb 2: (Section II.B.3.a) For long pipelines approaching the ocean bottom temperature of 39oF, the lowest water content of the outlet gas is given by the below table: Pipe Pressure, psia 500 1000 1500 2000 15.0 9.0 7.0 5.5 Water Content, lbm/MMscf Rule-of-Thumb 3: (Section II.B.3.b) At 39oF and pressures greater than 1000 psia, the maximum amount of methanol lost to the vapor phase is 1 lbm MeOH/MMscf for every weight % MeOH in the free water phase. Rule-of-Thumb 4: (Section II.B.3.b) At 39oF and pressures greater than 1000 psia, the maximum amount of MEG lost to the gas is 0.002 lbm/MMscf.

Rule-of-Thumb 5: (Section II.B.3.c) The concentration of methanol dissolved in condensate is 0.5 wt %.

Rule-of-Thumb 6: (Section II.B.3.c) The mole fraction of MEG in a liquid hydrocarbon at 39oF and pressures greater than 1000 psia is 0.03% of the mole fraction of MEG in the water phase.

Rule-of-Thumb 7. (Section II.E) Natural gases cool upon expansion from pressures below 6000 psia; above 6000 psia the temperature will increase upon expansion. Virtually all offshore gas processes cool upon expansion, since only a

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few reservoirs and no current pipelines or process conditions are above 6000 psia.

Rule-of-Thumb 8. (Section II.E.3) It is always better to expand a dry gas, to prevent hydrate formation in unusual circumstances, e.g. changes in upstream pressure due to throughput changes.

Rule-of-Thumb 9. (Section II.E.3) Where drying is not a possibility, it is always better to take a large pressure drop at a process condition where the inlet temperature is high.

Rule-of-Thumb 10. (Section II.F.1.b) Monoethylene gylcol injection is used when the required methanol injection rate exceeds 30 gal/hr.

Rule-of-Thumb 11. Section II.F.2.a) Use of anti-agglomerants requires a substantial oil/condensate phase. The maximum water to oil ratio (volume basis) for the use of an anti-agglomerant is 40:60 on a volume basis.

Rule-of-Thumb 12. (Section II.F.2.b) PVP may be used to inhibit pipelines with subcooling less than 10oF for flow lines with short gas residence times (less than 20 minutes).

Rule-of-Thumb 13: (Section II.F.2.b) VC-713, PVCap, and co-polymers of PVCap can be used to inhibit flow lines at subcooling less than 15oF, with water phase residence times up to 30 days.

Rule-of-Thumb 14: (Section III) Hydrate blockages occur due to abnormal operating conditions such as well tests with water, loss of inhibitor injection, dehydrator malfunction, startup, shutin, etc. In all recorded instances hydrate plugs were successfully removed and the system returned to service.

Rule-of-Thumb 15: (Section III.A.1) In gas-water systems hydrates can form on the pipe wall. In gas/condensate or gas/oil systems, hydrates usually form as particles which agglomerate to larger masses in the bulk streams.

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Rule-of-Thumb 16: (Section III.A.1) Agglomeration of individual hydrate particles causes an open hydrate mass which has a high porosity (often > 50%) and is permeable to gas flow (permeability to length ratio of 8.7 - 11 × 10-15 m). Such an open hydrate mass has the unusual property of transmitting pressure while being a substantial liquid flow impediment. Hydrate particles anneal to lower permeability at longer times.

Rule-of-Thumb 17. (Section III.B.1.a) A lack of hydrate blockages does not indicate a lack of hydrates. Frequently hydrates form but flow (e.g. in an oil with a natural surfactant present) and can be detected in pigging returns.

Rule-of-Thumb 18: (Section III.B.2.a) When a hydrate blockage is experienced, for safety reasons, inhibitor is usually lubricated into the line from the platform in an attempt to determine the plug distance from the platform. Attempts to “blow the plug out of the line” by increasing the upstream pressure will result in more hydrate formation and perhaps rupture due to overpressure

Rule of Thumb 19. Regardless of the method(s) used to dissociate the hydrates, the time required for hydrate dissociation is usually days, weeks, or months. After a deliberate dissociation action is taken, both confidence and patience are required to observe the result over a long period of time.

Rule of Thumb 20. (Section III.C) When dissociating a hydrate plug, it should always be assumed that multiple plugs exist both from a safety and a technical standpoint. While one plug may cause the initial flow blockage, a shut-in will cause the entire line to rapidly cool into the hydrate region, and low lying points of water accumulation will rapidly convert to hydrate at water-gas interfaces.

Rule of Thumb 21. (Section III.C.3) Because the limits of a hydrate plug cannot be easily located in a subsea environment, heating is not recommended for subsea dissociation.

Rule-of-Thumb 22. (Section IV.B.1.a) Methanol loss costs can be substantial when the total fraction of either the vapor or the oil/condensate phase is very large relative to the water phase.

Rule-of-Thumb 23. (Section IV.B.1.b) The cost of a fixed leg North Sea platforms is $77,000/ton.

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Rule-of-Thumb 24. (Section IV.B.2) In order to achieve a desired heat transfer coefficient of 0.3 BTU/hr-ft2-oF, a non-jacketed system costs $1.5 million per mile. Typical costs of insulation via bundled lines are $1.5 -$2.0 million/mile.

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