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
Table of Contents
Topic
Table of Contents .._... ..ii
Disclaimer and Acknowledgements. ... .v
Introduction ... 1
I. Safety First: A Gallon of Prevention is Worth a Mile of Cure.. _. .._..._.._... 1
II. Prevention by Design: How to Ensure Hydrates Won’t Fog ... 5
A. Where Do Hydrates Form in Offshore Systems?. ... .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
3. Amount of Inhibitor Injected Into Pipeline ... 16
a. Amount of Water Phase.. ... 16
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
5. Computer Program for Second Approximation ... .20
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 3. Solubility of MeOH and MEG in the Gas ... .25
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
G. Hydrate Control Through Chemical Inhibition and Heat Management .... ..4 1
1. Inhibition with Methanol or Mono-ethylene Glycol.. ... .42
a. Methanol ... .42
b. Monoethylene Glycol.. ... .44
c. Comparison of Methanol and Glycol Injection ... .45
2. Kinetic Control by Anti-Agglomerants and Kinetic Inhibitors ... .45
a. Anti-Agglomerants.. ... ..4 6 b. Kinetic Inhibition ... .47
3. Guidelines for Use of Chemical Inhibitors.. ... ..5 0 4. Heat Management.. ... .53
a Insulation Methods.. ... ..5 4 b Pipeline Heating Methods.. ... ..5 5 H. Design Guidelines for Offshore Hydrate Prevention ... .55
III. Hydrate Plug Remediation.. ... ..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
E. Recommendations and Future Development Areas ... .93
1. Recommendation Summary for Hydrate Remediation ... .93
2. Recommendations for Future Work.. ... .94
IV. Economics ... ..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.. ... ,109
B.l.HYDOFF.. ... .I09 B.2. XF’AND.. ... ,123
Appendix C. Additional Case Studies of Hydrate Blockage and Remediation.. 128
Appendix D. Compilation of Rules-of-Thumb in Handbook ... .I45 References ... 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 idea for the Handbook was conceived
by Mr. Ben Bloys of ARC0 Exploration and Production Technology Co. This work is a paean to Mr. Bloys’ foresight regarding the state of knowledge in hydrate engineering, 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 who have contributed generously are listed in alphabetical order by company:
Amoco’s Mssrs. George Shoup and J.J. Xiao provided hydrate plug transient- flow 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.
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.
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
2
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.
A hydrate plug moves down a flowline at very high velocites.
Where the pipe bends, the hydrate plug can rupture the flowline through projectile impact.
A hydrate plug moves down a flowline at very high velocites.
Closed Valve If the velocity is high enough, the Closed Valve
Figure 1 - Safety Hazards of Moving Hydrate Plugs
(From Chevron Canada Resources, 1992)
1b)
1a)
3
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. Were out-of-service immediately prior to the incident. 2. Did not have hydrate or freeze protection.
3. Were pressurized while out-of-service. 4. Were being restarted.
5. 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
Figure 2 - Safety Hazards of High Pressures Trapped by Hydrates
(From Chevron Canada Resources, 1992)
Heat Addition
Hydrate Plug Gas
Gas
Pipeline Rupture
Low Pressure
High Pressure
Low Pressure
Hydrate
Plug
Hydrate
Plug
WELLHEAD
SATELLITE
2a)
2b)
4
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.
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.
6
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
Figure 3 - Offshore Well, Transport Pipeline, and Platform
Downhole Safety
Well with
X-Mas Tree
Riser
SEP.
COMP.
DRY
Export
Flowline
Transport Pipeline
(2-60 miles in length)
Platform
Bulge from Expansion
Ocean
Mudline
Blockage in
Riser
Blockage in
Flowline
Blockage in Tree,
Manifold, Well
- Depth 6000 ft
7
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
Figure 4 - Water Temperature vs. Depth
(Gulf of Mexico)
10
100
1000
10000
20
30
40
50
60
70
80
9 5/8 inch
13 3/8 inch
20 inch
30 inch
Christmas
Tree
Wellhead
Downhole
Completion
Mudline
Swab Valve
Master Valve
Downhole
Safety Valve
Crossover Valve
Wing Valve
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.) Risk of Hydrate Formation Problems
<1000 A hydrate problem will probably not occur
≤1500 Without inhibition a hydrate problem may occur
≤2000 Without inhibition a hydrate problem will occur
≥3000 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
9
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
2500
2000
1500
1000
500
0
30
40
50
60
70
80
30%
MeOH
20%
MeOH
10%
MeOH
Hydrate
Formation
Curve
Hydrate
Forming
Region
7 Miles
10
15
20
25
30
35
40
45
50
Pressure
(psia
)
Figure 6 - Offshore Pipeline Plotted on Hydrate Formation Curves
(From Notz, 1994)
Hydrate
Free
Region
10
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
Figure 7 - Typical Transport Pipeline Plotted on
Hydrate Formation Curves
(From Todd, 1997)
0
500
1000
1500
2000
2500
3000
30
35
40
45
50
55
60
65
70
75
Pressure(psia)
Separator
Wellhead
Hydrate
Formation
Curve
10% MeOH
Figure
8 -
Typical
Offshore
Pbtform
Schematic
(From Manning and Thompson, 1991)
-u
Table 1 - Platform Processing Conditions
(From Manning and Thompson, 1991)
Location Pressure(PSIA) Temperature(oF) Mol/Hr Mol Wt Frac. Vap BPD @60F
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
Table 2 - Gas and Liquid Compositions on Platform
(From Manning and Thomson, 1991)
#1 #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 Inlet Fluid 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 248oF 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 472oF 0.0544 0.0000 0.0665 0.0000 0.0834 0.0000 0.0935 0.0000 0.1002 0.0000 0.0000 657oF 0.1342 0.0000 0.1641 0.0000 0.2058 0.0000 0.2308 0.0000 0.2472 0.0000 0.0000 Total Mol/Hr 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 Comp.(Mol Frac.) 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 0.00999 0.002135 0.017764 0.000398 0.000354 1.3E-05 CO2 0.0000 0.001304 0.000935 0.000395 0.00128 0.001283 0.000854 0.00111 0.000448 0.000398 2.32E-05 Methane 0.0043 0.42762 0.170392 0.061975 0.69145 0.694509 0.279249 0.767528 0.087314 0.077977 0.003338 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 0.08717 0.086334 0.199829 0.059332 0.242716 0.22876 0.032016 i-butane 0.0562 0.033794 0.05984 0.081205 0.013479 0.013199 0.051238 0.009112 0.077701 0.075325 0.014435 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 n-pentane 0.1438 0.020161 0.03602 0.094344 0.005419 0.005098 0.048676 0.003929 0.089057 0.095217 0.040401 Hexane 0.1995 0.010736 0.016941 0.065133 0.002365 0.002091 0.039283 0.00197 0.062111 0.077535 0.074892 248oF 0.1398 0.002404 0.001848 0.017143 0.000654 0.000456 0.027327 0.000649 0.018329 0.032004 0.176941
340oF 0.0145 0.000174 2.23E-05 0.001297 6.6E-05 2.53E-05 0.005551 7.41E-05 0.001793 0.003227 0.12715
413oF 0.0020 2.27E-05 0 0.000169 9.44E-06 0 0.001281 1.3E-05 0.000249 0.000442 0.108848
472oF 0.0000 0 0 0 0 0 0 3.71E-06 4.98E-05 8.84E-05 0.096918
657oF 0.0000 0 0 0 0 0 0 0 0 0 0.239094
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
12
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. Rules-of-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
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 mono-ethylene 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.
Fi ur a - H rat Formati (From Katz 19591 4- 3- 2- 3- 4 J, I I I 6o)oo I I 35.00 45.00 55.00 65.00 75.00 30.00 40.00 50.00 70.00 80.00
Temperature (F)
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 0.9267 16.043 14.867 Ethane 0.0529 30.070 1.591 Propane 0.0138 44.097 0.609 i-Butane 0.00182 58.124 0.106 n-Butane 0.00338 58.124 0.196 Pentane 0.0014 72.151 0.101 1.000 17.470
Gas Gravity Mol Wt of Gas Mol Wt of Air
= =17 470=
28 966 0 603 .
. .
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 C W M(100 - W)
= (1)
where:
∆T = hydrate depression, (Teq - Toper) oF,
C = constant for a particular inhibitor (2,335 for MeOH; 2,000 for MEG) W = weight per cent of the inhibitor in the liquid, and
15
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−xMeOH) (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 M T + C ∆ ∆ = × × × + = 100 32 11 32 11 2335 131.
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.
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 temperature of 39oF, 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 x-axis and water content is read on the y-x-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).
Figure 10 - Water Formation Curve
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-of-Thumb 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
Figure 11 - Methanol Lost to Vapor
(From Sloan, 1998)
Temperature, OF
20 30 40 50 60 70 80 90 100
% 1
I t I I I III I, I I, I I I I I I, 1 III I,, 1 I, I,, III,
5 Ls
isobaric Vapor Phase Distribution for
Methanol in Hydrate-Foxming Systems
,z -
InK,, = a + b[l/T(R)]
a
b
-3,0
1000
psia
8.41233
-7250.20
,- 0 I-0
2000 psia 6.82227
-6432.23
,- 6-0
3000
psia
5.70578
-5738.48
s III 1111,,,,,,,,,,,,,,,,,,,,,,,,,,rZ.lOE-3 ZOOE-3 1.9oE3 l.mE-3
Fimre 12 - Mono-Ethylene Glvcol Lost to Vapor
xx)- 100 = 60 = 40- 20- IO = 6= 4- 2- I =‘ 0.6 = a4 - r(From Townsend and Reid, 1972)
18
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 Mol Wt Avg Mol Wt in Mixture
yi MW yi•MW Methane 0.7160 16.04 11.487 Ethane 0.0473 30.07 1.422 Propane 0.0194 44.09 0.855 n-Butane 0.0079 58.12 0.459 n-Pentane 0.0079 72.15 0.570 Nitrogen 0.0596 28.01 1.670 Carbon Dioxide 0.1419 44.01 6.245 1.000 22.708
Gas Gravity mol wt gas mol wt air
22.708
28.966 0.784
= = =
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 C W
100M - MW
=
Where:∆T = Temperature Depression (65oF - 38oF= 27oF), M = Molecular Weight for Methanol (= 32.0) C = Constant for Methanol (= 2335)
Rearranging the Hammerschmidt equation W = 100 M T M T + C ∆ ∆ = × × × + = 100 32 27 32 27 2335 27
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:
- 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 lb MeOH M lb MeOH 618.4lb H O m m m 2 = + ×100% MMscf O H lb MMscf day gal lb bbl gal day O bblH2 m m 2 4 . 27 2 . 3 1 34 . 8 42 25 . 0 =
20
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-of-Thumb 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-of-Thumb 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).
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) Pipeline Inlet Pressure - Starting high pressure
2) Cold Pipeline Pressure - Pressure at the coldest part of the pipeline. 3) Pipeline Inlet Temperature - Starting warm temperature.
4) Cold Pipeline Temperature - Temperature at the coldest part of the pipeline. 5) Gas Gravity - Gas gravity, calculated by the steps in Section II.C.1 and Example 4. 6) Gas Flow Rate - Gas flow in the pipeline measured in MMscf/d.
7) Condensate Rate - Condensate flow in the pipeline measured in bbl/d. 8) 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
