WT Geoservices Manual
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WELL TESTING TRAINING MANUAL SECTION 1 ............................................................................................... GENERALITIES SECTION 2 ................................................................................. SAFETY PROCEDURES SECTION 3 ..................................................................................... PIPES AND FITTINGS SECTION 4 ........................................................................................................... VALVES SECTION 5 ............................................................................................ FLOW CONTROL SECTION 6 ..................................PRESSURE AND TEMPERATURE MEASUREMENTS SECTION 7 ................................................................................. DEAD WEIGHT TESTER SECTION 8 ................................................................ SEPARATORS AND SEPARATION SECTION 9 ..................................................... SAFETY VALVES AND RUPTURE DISCS SECTION 10 ................................................................ PNEUMATIC CONTROL VALVES SECTION 11 ...................................................................... PNEUMATIC CONTROLLERS SECTION 12 ......................................................... OIL VOLUME (TANKS AND METERS) SECTION 13 ............................................................................. DANIEL ORIFICE METER SECTION 14 ...................................................................................BARTON RECORDER SECTION 15 ............................................................. RANAREX GAS GRAVITOMETERS SECTION 16 .............................................................. GAS FLOW RATE COMPUTATION SECTION 17 ..........................................HYDRATES (HEATER AND TEXSTEAM PUMP) SECTION 18 .............................................................................................. REGULATORS SECTION 19 ...............................................................................BURNERS AND BOOMS SECTION 21 .........................................................................................TRANSFER PUMP
Generalities
SECTION 1 GENERALITIES
1-1
Generalities
1
INTRODUCTION TO WELL TESTING Tests on oil or gas wells are performed at various stages of drilling, completion and production and for different purposes. It is important to understand completely the reasons for each of these tests and what is expected to be accomplish with the results. 1. Drill stem tests (DST) in open hole are normally carried out in exploration wells and while drilling is in progress. Indications of hydrocarbons, either through cuttings, gas cutting of mud or intermediate logs make it interesting to determine whether a true reservoir exists, or simply hydrocarbons which are contained in tight rocks, but are unproductive. These tests are normally short (less than 12 hours) and, if properly performed, provide further evidence of fluid content of the rock, and usually some of the rock parameters (permeability, for example) 2. If logs, DST's and other such information are sufficiently promising, casing will be run and perhaps further testing carried out prior to completion. Such tests will usually be DST's in cased hole. 3. Following the tests in cased hole, completion will usually be made in zone, which gives the best results during the shorter tests. In some circumstances a dual zone completion may be made, if it is sufficiently important to make long tests on two separate zones at the same time. The tests made on completing the well may be called completion or production tests (the name "production test" can be misleading since all routine tests made in a production station are classified as "production tests"). These notes are concerned with DST or production tests immediately on completing the well, sometimes with a rig still present, sometimes after rigging down, but in any case, long before the existence of any permanent production facilities. The routine production tests after installation of facilities do not concern us here, since at that time all the important decisions regarding reservoir development have already been made. The correct interpretation of the first test, made with portable equipment, is on the other hand of vital importance, since much of what comes later depends upon it. What is important to understand is that in many aspects, production (completion) tests are similar to DST's. Both are short term and are designed to give us information not only on fluid content of a reservoir but in particular on rock properties, through correct interpretation of bottom hole pressure transient data. The production test is longer, producing rates can be more realistic, and preliminary information makes possible better planning than in a DST, where testing is often finished before it is realized that important data is missing or tool function was unsatisfactory. The production test attempts not only to fill such gaps, but also to gain additional reservoir information by being considerably longer. Only careful planning and observation can ensure this.
2-2
Generalities
WELL TEST TECHNIQUE
ACQUISITION SYSTEM
VALIDATION
SURFACE TESTING EQUIPMENT
SAFETY EQUIPMENT (S.S.T.T.)
WELL TESTING Customer requirements Reservoir parameters - Kh, S, P. Where do we get the data ? FLOW RATE CONTROL Open hole DST Cased hole DST Safety equipment (S.S.T.T.) FLOW DATA Production testing
DST EQUIPMENT
D/HOLE GAUGES
PRESSURE DATA Recorders Real time gauges ACQUISITION Hardware Software A.L.S. FLUID DATA Sampling Surface & downhole PVT analysis VALIDATION / INTERPRETATION Validating data acquired on site Interpretation on site
3-3
Generalities
2
AIMS OF WELL TESTING − Determine exact nature of produced fluids. §
PVT tests to be performed on recombined samples
− Define well productivity § §
IPR curve for oil wells inflow performance response inflow production relation Deliver ability curve and open flow potential for gas wells
− Evaluate characteristics of the producing formation § §
Static formation pressure Formation flow capacity (kh)
− Evaluate formation damage § §
2.1
Determine if acidifying or other treatment is needed Control results of the treatment operation
WT OPERATIONS − The key to successful test is personnel § § §
Job preparation (Base) Job performance (Well site) Job follow-up (Base)
− Testing is personnel intensive and relies heavily on: § §
2.2
Leadership Team work
TESTING PROGRAMME − Established according to: § §
1
Nature of fluid produced (oil, gas) Reservoir characteristics1 (High, low productivity)
First estimation can be made during clean-up using charts
4-4
Generalities
5-5
Generalities
2.3
SURFACE TESTING - OPERATIONAL ASPECTS 1.
JOB PREPARATION
2.
PRESSURE TESTING
3.
CLEANING UP
4.
MAIN TEST
5.
REPORTING
6.
JOB FOLLOW UP
1.
JOB PREPARATION
CLIENT VISIT: by manager • •
Test program Equipment selection
RIG VISIT: by test supervisor • • •
Layout of basic equipment Piping requirement Boom installation
EQUIPMENT PREPARATION: under test supervisor's control PRE-TEST MEETING: attended by test supervisor • •
Procedures Program changes
EQUIPMENT DISPATCH: base CREW DISPATCH: base • • • • • •
6-6
At least two or three days before test is due Inspection for missing or damages equipment Set up Calibration Pressure testing Sampling preparation
Generalities
7-7
Generalities
2. PRESSURE TESTING The following pressure testing sequence is compulsory before any well opening. The record of the pressure tests should be included in the final well test report. Use the Foxboro Recorder or any other recorder available. TESTING THE LINES (See sketch of "PRESSURE TESTING SEQUENCE") •
The different sections must be hydraulically tested at working pressure. Normally after the well stream leaves the well head, the pressure is reduced in stages. After the pressure is reduced, process components of lower pressure rating may be used. The rule is: A pressure vessel should either be designed to withstand the maximum internal pressure which can be exerted on it under any conditions, or be protected by a pressure relieving device (safety relief valve or rupture disc). To determine system design pressure rating, it is necessary to show pressure-rating boundaries on mechanical flow sheets. Each section of flow line or process component has an assigned operating pressure e.g.: • From the well head or flow head down to the floor choke manifold the working pressure must be higher than the shut-in tubing pressure. This will lead to the choice of the floor manifold assembly. • For subsequent sections the working pressure is determined to suit piping connection.
Note: In case of gas, if use of chicksan cannot be avoided, grease the ball bearings of chicksan swivels and change the packing. •
•
8-8
The separator is provided with pressure relieving devices. All other components are protected by making sure that pressure will always remain lower than the rated working pressure. For all components where working pressure is lower than the shut-in well head pressure, this protection is provided by a surface safety valve (SSV) located on the wing valve of the well head. Surface safety valve. On high-pressure tests (WHP>5000 psig) or in case of sour gas, a surface safety valve (remotely controlled) should always be installed on the wing valve - or upstream of the choke boxes. The flow line pressure sensors (OTIS pilot type P) should actuate this Surface Safety Valve, and also be activation of the emergency shutdown (E.S.D.) stations. In case of sour gas or high pressure, it is mandatory that one of these E.S.D. stations is set-up at the separator, other stations will be set-ups according to the customer's instructions. The pilot to shut in the SSV should be provided on each flow line segment of different working pressure down to the separator. When no surface safety valve is used, it is the operator's responsibility to check and make sure that the pressure always remains lower than the working pressure assigned to each section.
Generalities
3. •
CLEANING UP The duration is variable from a few hours to exceptionally a few days.
•
Separator by passed until: • • • • • •
•
Guide lines • •
4.
BSW lower than 5% Salinity = formation water salinity No acid WHP is changing regularly (liquid has unloaded) Hydrocarbons are being produced At least volume of well has been produced
Q = max. Q compatible with equipment and formation Gas wells Pi - Pwf > .25 WHP Vf > 50 ft/sec
MAIN TEST AFTER CLEAN UP •
Initial shut in to record initial reservoir pressure and temperature
•
Flowing the well at one or several successive flow rates
•
Taking representative fluid samples
•
Final shut in to record build up
PARAMETERS TO BE MEASURED •
Flow rate of fluids produced: oil, gas, and water
•
Pressure and temperature of: • • •
Bottom hole (producing interval) Well head Separator and other surface installations
• Separator gas specific gravity G • Oil shrinkage factor and S.T.O. (Stock Tank Oil) gravity • BSW (Basic Sediment and Water)
9-9
Generalities
5. REPORTING Must contain an accurate and complete record of: •
Test procedure / program
•
Operating and measuring conditions
•
Equipment used
•
Well completion
•
Sequence of events
•
Measured and calculated data
6.
JOB FOLLOW-UP •
Equipment rig down and packing by entire crew
•
Shipping of equipment
•
Debrief • •
•
Equipment reception • •
•
Inspection of missing or damaged equipment Maintenance initiation by test supervisor
Reporting • • •
10 - 10
With management and crew With client by manager and test supervisor
Final well test report Service orders Time sheets by test supervisor
Generalities
2.4
TYPES OF TESTS
BOTTOM HOLE PRESSURE
initial shut-in
clean up
flowing period
final shut-in
time days
flow rate
time
IDEALISED DIAGRAMS OF FLOW AND PRESSURE DURING AN OIL WELL TEST
BOTTOM HOLE FLOWING PRESSURE P 3
GROSS PRODUCTION RATE, B/D Results of a multiple rate test are presented as a plot of Pwf vs. gross liquid production rate
11 - 11
Generalities
IDEALISED AND TRUE IPR CURVES
2.4.1 Inflow Production Relation - IPR The inflow production relation shows the relation between well production rate q, and bottom hole pressure over the entire range of Pwf from zero to Ps. It is determined by producing the well at several different rates (including zero) and measuring the corresponding bottom hole pressures. The slope
∆q of the IPR curve is the productivity index. ∆p
A straight-line extrapolation of measured data points to intercept with the abscissa at Pwf = O gives the zone open flow potential. This is the flow rate that could be obtained if 1 ATM. is applied to the formation face. If one were to plot the IPR curve using data points below the reservoir fluid bubble point, a departure from a straight line would be noted. The Darcy flow relation is linear only for non-compressible (liquid) flow.
12 - 12
Generalities
2.4.2 Pressure and flow diagrams of a gas well back pressure test Bottom hole pressure
Pwi Pwf1 Pwf2 Pwf3 Pwf4 clean up
initial shut-in
T
T
T
T
Final shut-in
time
gas flow rate Q4 Q3 Q2
Q1 time
2.4.3 Testing procedures for high capacity gas wells Gas wells with an open flow potential of over 50 MMSCF/D are classified as high productivity wells. For these wells the backpressure test is the standard means of evaluating the productive capacity. The well is usually cleaned up for a few to 24 hours and closed in for an equal period prior to testing. In the backpressure test, bottom hole pressures and the corresponding surface flow rates are measured during a series of four different flow periods. The flow rate is increased in steps of equal time duration without shutting the well in between. Each flow period is about 4 - 8 hours duration, the time needed for stabilization often taken when the tubing head pressure variation is less than 2 psi/hour. The final shut in period is usually between 12 and 24 hours.
13 - 13
Generalities
2.4.4 Open flow potential of a gas well determined from a back pressure test
Open Flow £
48 / 64 Choke £
£ 36 / 64 Choke £ 28 / 64 Choke
SURFACE PRODUCTION RATE - SCF/DAY
The results of a backpressure test are presented as a plot of surface production rate vs. P²s - P²wf on a log - log grid. Open flow potential is found by extrapolation of the performance line to P²s the flow rate which would occur when Pwf = O. Finding Ps is made by analysis of the pressure build up curve and is covered later in this chapter.
14 - 14
Generalities
2.4.5 Pressure and flow diagrams of an isochronal test of gas well BOTTOM HOLE PRESSURE Pwi
Pwf1
Pwf2 Pwf3
clean up
initial shut in
Pwf4
stabilized Flowing Pressure Time
T
T
T
T
final shut in
GAS FLOW RATE Extended flow Q4 Q3 Q2
Q1 Time
2.4.6 Isochronal test procedures For gas wells where the stabilization time would be too long to use the backpressure test, an isochronal test technique may be used. The isochronal test consists of flowing the well at four different rates for periods of equal duration. Between two flowing periods the well is shut in until stabilization is achieved. The last flow period is extended until stabilized conditions 1 psi/hr tubing head pressure charge is reached; then the well is shut in for an extended build up period of one to three days.
15 - 15
Generalities
2.4.7 Modified isochronal test
BOTTOM HOLE PRESSURE Pwi
Pwf1 Pwf2
t
t
t
t
Pwf3
t
t
Pwf4
t Time
FLOW RATE Q4 Q3 Q 2 Q1
Time
In practice, the "true isochronal test" is often replaced by the MODIFIED ISOCHRONAL TEST, in which the duration of the shut-in period is equal to the duration of the flowing period, regardless if stabilized shut-in pressure has been reached or not.
16 - 16
Generalities
PLOT SHOWING RESULTS OF MODIFIED ISOCHRONAL TEST DATA (P²-P²wf), PSIA² 4 3
5 HR
2 1 HR 0.25 HR 6
10
9 8 7 6 5 4 Slope = 1/n
3 2
10
8
10²
2
3
4 5 6 7 8 9
3
10
2
3
4
FLOW RATE, q, STB/D
The data Q vs. P²s - P²wf taken after ¼ hr, ½ hr, 1 hr, 2 hrs etc., are plotted on log-log paper for each flow rate. On the extended test a point is plotted for stabilized flow near the end of the extended flow period. Lines connecting data points for ¼ hr, ½ hr and 5 hrs will be parallel but have a slope related to the productive capacity. A line of this slope passed through the final extended flow data point can be extrapolated to P²s - P²wf (when Pwf = O) yielding the open flow potential.
17 - 17
Generalities
3
Drill Stem Test (DST) A Drill Stem Test is a temporary well completion The tool features: •
A packer
•
A flow control valve
•
Pressure recording devices
•
Accessory tools (Sampling, Safety, etc.)
A typical DST consists of: •
A short initial flow period
•
An initial shut in period
•
A second or final flow period
•
A final shut in period
•
Direct Fluid type, flow rate
•
Interpretation Effective permeability, formation damage, reservoir pressure, barriers, anomalies and relative size of the reservoir
Results:
18 - 18
Generalities
FIELD PRESSURE READINGS
1. 2. 3. 4. 5. 6. 7. 8. 9.
Initial hydrostatic Set pocket Start of initial flow End of initial flow End of initial shut-in Start of final flow End of final flow End of final shut-in Final hydrostatic
1
9 2
è
8 5 7 BASE LINE
3
é6 TRIP OUT
FSI
FF
4
ISI
é IF
TRIP IN
Two Flow / Two Shut-in DST Chart
19 - 19
Generalities
3.1
TYPICAL DST PROCEDURE
TRIPPING IN THE HOLE As the tools are lowered into the well, fluids enters the tubing via the MRCV. This balances the system: in / out tubing and above / below POTV. SPOT CUSHION Once on depth, the cushion is spotted down the tubing. The cushion may be diesel, water or whatever fluid is desired to allow the correct drawdown on opening. Pumping at +/- 3 Bbls/MN through the tool closes the MRCV. This creates a differential pressure tubing to annulus and thus closes the tool. FIRE GUN After the PACKER is set, pressurizing the annulus to +/- 2000 psi fires the GUNS. This opens the POTV. As the POTV opens a drawdown occurs below the packer, which initiates the firing of the guns. FLOW WELL The well will start to flow after the guns have been fired. The well keeps on flowing, as the POTV is still open. To keep the POTV open a pressure of +/- 2000 psi is held on the annulus. DOWN-HOLE SHUT-IN When bleeding the annulus pressure, the POTV will shut, stopping the flow and allowing a build up pressure below the POTV. Memory gauges in the BUNDLE CARRIER record this build up. REVERSING OUT At the end of the test, it is necessary to reverse out all the produced fluids before unsetting the packer (another solution will be to bullhead the produced fluids in the formation, then the reverse out will be conducted). To do this, we apply +/-3500 psi to the annulus, which ruptures a disc, opening the AORV. The tubing contents are reversed out, the packer unset and the tools pull out of the well.
20 - 20
Generalities
21 - 21
Generalities
3.2
22 - 22
THE TOOLS
Generalities
3.2.1 PACKER The packer provides isolation of the test interval from the annulus, allowing the reservoir to be tested, and in addition facilitates the use annulus pressure-operated test tools. The packer are classified according to there operating mechanism and their purpose. Hook-wall packer: for cased hole test, can be used at all depth. This type of packer can be used up to 10.000 psi and at a maximum of 320°C (160°F). Above these values it is recommended to use a production (permanent) packer. Open-hole packer: conventional packer. Drill collars or perforated anchors are run under the packer. When the string tags the bottom and start taking weight, the packer mechanism compress the rubber components which inflate in order to assure sealing against the bore hole. Inflatable packer: for open or cased hole. A hydraulic pump set at the top of the packer will be actuating by a rotation of the spring. This pump will inflate the rubber components of the packer. Production packer: will be run with wire-line or tubing. Non-retrievable: will have to be drilled out Retrievable: by picking up the string at a certain tension, shear pins will break and release the packer. §
Geoservices packers: ARROW SET 1-X 10.000 psi WP For casing of: 5” – 7” – 9 5/8” BAKER retrievamatics 7500 psi WP For casing of 7” – 9 5/8” MSG packer: high pressure (15.000 psi WP), high temperature. For casing: 7” The Geoservices packers are retrievable hook-wall packers, suitable for compression test spring applications and capable of withstanding TCP underbalance perforating shock. They are designed to operate in both testing and stimulation applications. If TCP and/or stimulation operations are to be conducted it is recommended to use the Baker packer who is equipped with hydraulic operated slips. When running such operations with the Arrow set packers, it is recommended to remove the mechanical hold down slips, thus to avoid any problem when unseating packer.
Setting procedures Due to the fact that the OD of the packer is very close to the ID of the casing or liner in which he is run, the maximum run-in speed should not exceed 10 ft per minute in order to avoid swabbing effect when running or retrieving. An internal by-pass reduces this swabbing effect. The by-pass closes upon setting packer. When releasing, the by-pass opens first to equalize pressures before releasing the upper slips. Run to setting depth, pick up on the tubing and rotate ¼ turn to the right at the packer then lower the tubing slacking off sufficient weight to set the packer. Pull tension to make sure the packer is locked in the set position and that the upper slips are set. After setting the packer, the tubing can be left in compression, tension or neutral. 23 - 23
Generalities Releasing procedures The releasing procedures are the same whether the packer has been in tension or compression set. Set down weight on the packer and rotate tubing ¼ turn to the right at the packer, and then pick up holding right hand torque. The internal by-pass will open, allowing pressure to equalize. Further pick up releases the patented releasing sequential slip system relaxing the elements, allowing the packer to be reset or removed from the well.
RETRIEVABLE PACKER
24 - 24
Generalities
3.2.2 SAFETY JOINT The safety joint provides for an emergency release between the test string and the packer. In the event that the safety joint is released, the overshot can be run to reconnect the work string with the packer assembly. Releasing operation The safety joint is run on the test string directly above the packer. Release is effected by taking an upstrain (max. 10.000 lbs.) on the test string and rotating to the right. Release is controlled by make up torque, which can be varied. Eleven turns at the safety joint are required to back it off. Retrieving operation The safety joint can be reconnected to the work string by slowly setting down and rotating the overshot to the right into the retrieving treads. Prior to reconnect the overshot it is recommended to circulate through in order to clean the threads.
3.2.3 HYDRAULIC JAR The hydraulic jar is used for the purpose of freeing stuck pipe and tools in the well bore. This device delivers heavy impact blows to the test string by storing energy within the tool. In well test application the tool is run directly above the safety joint. The hydraulic jar is designed to transmit torque and withstand severe tensile and compressive loads. Operation To activate the hydraulic jar, the driller pulls up the work string and holds tension. This hook-load will tend to decrease as the jar meters open and it is, therefore, necessary for the driller to continue picks up and hold his tension. The applied tension to the tool cause the oil in the jar cylinder to flow through a flow regulator. This restricts the piston movement to a slow but controlled rate. When the piston reaches the grooved section of the cylinder bore, the oil above the piston dumps into the cylinder below the piston. At this time, the stretch in the work string accelerates 25 - 25
Generalities the mandrel upward until the hammer (mandrel) strikes the anvil (torque sub). This delivers a high impact blow to the stuck tool. When the driller slacks off on the work string, an internal valve is forced open, allowing the oil to by-pass the piston. This allows for rapid re-cocking of the jar.
26 - 26
Generalities
3.2.4 BUNDLE CARRIER The recorder carrier is a full bore tool that may be run in any position in the test string. The recorder carrier will carry a variety of gauges for recording pressure and temperature versus time. Each bundle carrier can record external or internal data and can carry up to four 1 ¼” OD gauge. Operation The gauge carrier is normally run directly below the tester valve to record pressure transient data. The carrier is designed to minimize shock caused by tubing conveyed perforating. Two type of gauge carrier is available: §
Bundle carrier full bore: 2 ¼” ID – 4.9” OD Care should be taken when running this tool. The gauges are fixed on an offset, which conduct to a rotation OD of 6 ¼”. Due to the presence of the shoulder, two gauge carriers cannot be run in tandem. If more than one carrier is requested, a stand of tubing must be run in between the tools.
§
Bundle carrier with straight OD 5” The main point with this type of gauge carrier is the fact that it is not a full bore tool. The offset is internal, avoiding all wire line operation through it.
3.2.5 DOWN HOLE VALVE This valve gives control of communication between the isolated formation zone to be tested and the inside of the test string. It enables to create a differential pressure across the formation well bore in favor of the formation so that the formation fluid can enter the well bore and come up to the surface. The closure of the valve at the end of a flow period permits to record the pressure build up as near as possible to the formation and thus obtain data, which are representative of the formation pressure behaviour. §
Geoservices tester valve POTV: Pressure Operated Tester Valve This valve is run in conjunction with a nitrogen chamber and pressure references tool the ARTS: Annulus Reference Trap System. The valve, run in conjunction with a hydrostatic reference system is a bottom well control valve actuated by application and removal of annular pressure. Application of annulus pressure opens the tool; removal of annulus pressure closes the valve.
Operation As the tool is run with a self-compensating reference system, prior knowledge of bottom hole temperature and pressure is not required within limits of specification. Additionally, tool can be equipped with a lock open feature. With this option installed, the tool can be run in or pulled out of the hole in the open or close position. A pair of retaining segments and button head cap screws attaches the ball to the top sub. The retaining segments have large trunions on which the ball is mounted. The ball sealing system is a metal-to-metal one. A ball operating sub, seal unit and collar are all interconnected to the upper mandrel. A spline and lug on each arm of the ball-operating sub engage slots on the ball. As the
27 - 27
Generalities upper mandrel is moved up or down, the lugs rotate the ball to the open or closed position. The splines perform several functions in the mechanism. The assist piston allows the tool to hold pressure from above. When the pressure above the ball exceeds the pressure below the ball, a force is generated which forces the upper mandrel assembly up, thus maintaining a seal. The control piston separates annulus fluid from the nitrogen. As annulus pressure is increased, the control piston moves down opening the tool, further compressing the nitrogen and helical spring. When annulus pressure is removed, the compressed nitrogen and spring act on the nitrogen side of the piston shifting the tool on the closed position. The tool can be dressed with a lock open feature. When dressed with this option, an indexing sleeve extends through the sleeve and engages G-slots cut into the index mandrel. As the index mandrel moves down through the indexing sleeve, the indexing sleeve rotates. This rotation brings splines on the indexing sleeve into alignment. As the index mandrel moves up in response to a reduction of annulus pressure, the splines contact each other preventing further upward movement of the mandrel, thus the ball is mechanically held open. As the index mandrel is again forced down by application of annulus pressure, the indexing sleeve is again rotated, the splines are taken out of alignment allowing full upward movement of index mandrel allowing the ball to be rotated closed by the ball operating sub. In this configuration it is recommended to use the tool in the fail-safe position as long as wire line or coil tubing operations are not run. When dressed without the lock open feature, the tool is held open with application of annulus pressure and closes when annulus pressure is removed without an intermediate pressure cycle.
28 - 28
Generalities
POTV
ARTS
29 - 29
Generalities
3.2.6 DOWN HOLE SAFETY VALVE The DHSV is a single shot ball valve run in the open position. If required the ball can be closed by applying annulus pressure to burst a high accuracy rupture disc. Once closed the ball will isolate well pressure but will still allow fluid to be pumped through from above. Operation Applying pressure to the annulus closes the valve. This will burst the rupture disc. Once this path is opened, the annulus pressure forces an operating mandrel in the upward direction to rotate a ball valve to the closed position. The ball will not support differential pressures from above allowing the well to be killed by bull heading.
3.2.7 REVERSING VALVE This valve provides a means of communication between the annulus and the test string. This allows the spotting of the cushion, fluids stimulation or the circulation of fluids out of the test string. Three different valves are available: •
The AORV : Annulus Operated Reverse Valve
•
The MRCV : Multi-Reverse Circulating Valve
•
The MRST : Multi-Reverse Spot Tool
The AORV The AORV is a single shot-circulating valve giving unrestricted flow between tubing and annulus. Once open, the tool is retained in this position by a lock ring and cannot be reclosed. The AORV is opened by applied annulus pressure bursting a rupture disc. The pressure acts on an unbalanced piston, forcing the mandrel to the open position. The locking of a mechanism then locks the mandrel in the open position.
30 - 30
Generalities
AORV The MRCV The MRCV is normally run above the POTV. The tool is cycled by the application of 2500 psi differential bias to the tubing. This forces the mandrel assembly to be pumped downward. When the pressure is bled off, a spring forces the mandrel assembly up. Through the mandrel’s motion, an indexing sleeve, concentric to the mandrel assembly, is allowed to rotate. An indexing pin is located in the indexing sleeve, which follows the path of the slots in the indexing mandrel. After four or eight pressure cycles the index pin slides into an elongated slot, which in turn allow the entire mandrel assembly to travel an additional 2 inches, opening the tool. To close the valve, fluid is pumped down the work string and out the ports at a predetermined rate, to cause a pressure drop across the flow orifices. This creates a differential pressure between the upper mandrel seal and the connector sub seals, pushing the mandrel assembly down and closing the tool. When a tubing pressure of 2500 psi above annular hydrostatic is reached, and the pressure bled off, the indexing
31 - 31
Generalities sleeves rotates, moving the indexing pin into the next slot and returning the mandrel assembly to the first closed position.
MRCV
The MRST The multi-reverse spot tool works under the same principle than the MRST. The main difference resides in the fact that this tool offers one more position: the circulating mode. A pressure of 350 psi above hydrostatic, at the tool is applied to the drill string and then bled back to 0 psi to cycle the tool to its next position. A rate of ½ Bbls per minute at 300 psi is required to maintain circulation (spotting). Once pumping has stopped, communication ports close. Circulation may be re-established by again starting the pumps, as long as the pressure in the drill string has not been bled back to annulus hydrostatic.
32 - 32
Generalities
3.2.8 SLIP JOINT The slip joint is a telescopic joint run in the tool string, allowing five feet of free travel. It is balanced to compensate for internal volume changes due to temperature. It is also splined so that torque can be transferred below the tool. Slip joint should be run together in the work string when testing on floating structures. At the time the packer is set the slip joint will be half closed allowing for a maximum of expansion or contraction due to changes in well condition.
Correspondence in between Geoservices and competitors tools Geoservices
Halliburton
Schlumberger
Retrievable packer
RTTS
Positest – Positrieve
Safety joint
RTTS safety joint
Safety joint
Hydraulic jar
Big john jar
Hydraulic jar
ARTS POTV
HRT – PORT LPR-N
PCT
SPOT
OMNI
MCCV
AORV
APR-A
SHORT
DHSV (AOSV)
APR-M
SBSV –PTSV
FBS
APR-M2
FASC – DBS
TTV
TTV
TTV
MRCV
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Generalities
3.3
SUB-SURFACE SAFETY SYSTEM
These sub-surface systems, normally landed in the BOP stack allow quickly shutting in and controlling a well close to surface during a test. These tools can be broken into two main groups: •
THE SUB SEA (S/S) tree for floating rigs.
•
THE SUB SEA VALVE for fixed rigs.
3.3.1 THE SUB SEA TREE The valve assembly provides a fail safe seabed master valve to close the drill/pipe tubing. The latch assembly allows quick disconnection of a floating drilling vessel from the drill string in the hole.
3.3.2 THE LUBRICATOR VALVE Placed below the rig floor (approx. 20 - 40 ft) it enables the upper part of the test string to be used as a wireline lubricator. Negates the need to rig up lubricator (Riser) on top of the flowhead.
3.3.3 RETAINER VALVE This valve is run above the sub sea tree. Operating in conjunction with the valve of the S/S tree, it prevents the contents of the tubing between the S/S tree and surface blowing into the riser and the sea.
3.3.4 THE SUB SEA VALVE Similar to the S/S tree for floaters, this valve is designed for fixed rigs (i.e. Jack Ups). It is again a fail-safe valve located in the BOP, but has no unlatch facility. The S/S tree and S/S valve are hydraulically operated from surface. They are fail-safe in that they require pressure to open the valves; loss of pressure in the control lines closes the valves. Both valves are designed to cut up to 5/16" wireline, and usually with some modification, up to 1" coiled tubing.
34 - 34
Generalities SUB-SURFACE SAFETY SYSTEM
FLOWHEAD
HYDRAULIC HOSE REEL CONTROL CONSOLE
TUBING OR DRILLPIPE
BLIND RAMS CLOSED TREE LATCH
S/S TREE VALVE
S/S TREE VALVE CLOSED
SLICK JOINT PIPE RAMS CLOSED
FLUTED HANGER
35 - 35
Generalities
LUBRICATOR VALVE / RETAINER VALVE
RETAINER VALVE CLOSED ONE STAND OF TUBING / DRILLPIPE
RISER DISCONNECTED
LUBRICATOR VALVE
RETAINER VALVE
RAMS CLOSED
S/S TREE VALVE CLOSED
36 - 36
Safety procedures
SECTION 2 SAFETY PROCEDURES
1 - 22
Safety procedures
1.1 GENERAL LAYOUT AND ENVIRONMENT
1.2
•
Layout of equipment according to classified area and spacing.
•
Units grounding.
•
All electrical connections safe.
•
Anchoring of piping and connections.
•
Color coding to identify WP and fluids.
•
Wind direction.
•
Workplace tidy, clean, not slippery.
•
Hammers.
•
Pressure fittings.
•
Repair of vessels.
INSTALLATION AND INSPECTION OF EQUIPMENT ON SITE
1.2.1 Safety Standards Classified zones: The area around A well head is a type 2 zone within a radius of Separators, a type 2 zone within a radius of
onshore 15 m (45 ft) 10 m (30 ft)
offshore 10 m (30 ft) 3 m (10 ft)*
15 m (45 ft) 15 m (45 ft)
15 m (45 ft) 15 m (45 ft)
NOT ALLOWED NOT ALLOWED
NOT ALLOWED NOT ALLOWED
Provided that the rupture disc is connected to a discharge pipe at atmospheric pressure, ending far away from the rig. Otherwise, the area around the separator is a type 2 zone within radius of 5 m (45 ft).
Gauge tanks, a type 1 zone within a radius of The outlets of flares, safety valves, vents are classified as type 1 zone within a radius of Gas fired heaters: they must not be used in classified type 1 or TYPE 2 ZONES Wireline winches not to be used in classified zones.
2 - 22
Safety procedures
1.2.2
Recommended Practices
Note 1: Installation without a heater - The separator should be located 25 m away from the well head (75 ft) - Offshore, this distance may be reduced to 13 m (40 ft). The separator instrument controls should be supplied with compressed air. - The pressure relief valve must be connected to the flare line. Note 2: Tanks are equipped with a flame arrestor. The sniffer pipe must be connected to the rig flare. Moreover, manhole cover should be bolted during operation. Note 3: In some instances, due to lack of space, all the recommended distances cannot be respected, but: - Equipment must never be installed in the classified zone of the well head (type II zone). - Fired heaters, burners and wireline winches must never be installed in classified zones. - Chief Operator should inform the client and mention it in his report. For further details, please refer to API RP 500 B.
3 - 22
Safety procedures RESTRICTED ZONE - SAFETY STANDARDS
4 - 22
Safety procedures RECOMMENDED OPTIMAL POSITIONING
5 - 22
Safety procedures
1.2.3 PRESSURE FITTINGS Pressure fittings present a major hazard when dealing with pressure. • • • • • • • • • • •
Do not use cast iron fittings Use only stamped fittings Do not use hydraulic fittings for oil and gas service Check inner whole dimension Check the threads Check the thread make up (vanish thread) Do not exceed 3 layers of Teflon on NPT fittings Do not use NPT fittings larger than ½" for 10,000 psi service Do not use NPT above 10,000 psi Use plain plugs to plug NPT fittings Do not work on fittings under pressure
NATIONAL PIPE TAPER " N P T "
NOMINAL SIZE
NUMBER OF TPI
WIDTH OF FLAT F
1/16 ---------1/8
27
0.0014" to 0.0041"
NUMBER OF NUMBER OF TURNS TURNS HANDTIGHT HANDTIGHT ENGAGEMENT ENGAGEMENT (theoretical) (Theoretical)
NUMBER OF TURNS FOR WRENCH MAKE-UP
NUMBER OF VANISH THREAD (Practical)
4.32
OD OF PIPE (Male thread)
0.3125" 7.8 mm
1.36
0.405" 10.3 mm
1/4 ---------3/8
18
0.0021" to 0.0057"
4.10
0.540" 4 to 4.5
4.32
3
3.5
13.7 mm
0.675" 17.1 mm
1/2 ---------3/4
14
0.0027" to 0.0064"
4.48
0.840" 21.3 mm
4.75
1.050" 26.7 mm
6 - 22
Safety procedures
1.2.4 PRESSURE TESTING EVERY TESTING operation involves PRESSURE. For this reason the biggest danger comes from Personnel ATTITUDE. The pressure hazards related to Surface Testing operations are particularly important due to: •
Proximity of operating personnel
•
Vessel size
•
Large number of seals
For these reasons, PRESSURE TESTING of Well Testing Equipment at the base and at the Wellsite constitutes a critical part of MAINTENANCE and PRE-JOB CHECK. The following parameters must be evaluated before undertaking a pressure test: •
Test pressure
•
Periodicity
•
Pressure test fluid
•
Location
•
Procedure TEST PRESSURES EQUIPMENT
WORKING PRESSURE
OFFICIAL TEST PRESSURE
WELLSITE TEST PRESSURE
Vessel, Bonnet, Piping Cross-over, valve body
< 10 000 PSI > 10 000 PSI
2 WP 1,5 WP
WP WP
Valve and seat
ANY RANGE
WP
WP
Never exceed WP during a Wellsite pressure test. Never test a closed Valve above its WP. PRESSURE TESTING FLUID NATURE VS STORED ENERGY EQUIPMENT
(psi)
STORED ENERGY (testing with AIR)
(Testing with WATER)
1 440
1.29 X 108 J
603 J
2 1/2" twin bop
10 000
1.24 X 106 J
4.15 J
Lubricator (2 1/2" ID - 10 K) 4 sections
10 000
1.39 X 107 J
46 J
Separator
TEST PRESSURE
STORED ENERGY
Vessels must be EVACUATED before pressure testing. Use only HYDRAULIC pressure testing.
7 - 22
Safety procedures
1.2.5 SAFETY PROCEDURES Prior to beginning any well test, a safety meeting should be held at which all persons concerned should be present. Testing objectives and emergency procedures will be discussed. A safety meeting must be held at regular intervals during the test. Generally, we have two kinds of oil wells, which are the standard well, and the corrosive well. For both conditions some safety regulations must be respected during the job. E.g.:
Safety gear:
gloves, safety shoes, coveralls, helmets
Fire hazard:
some fire extinguishers present during test
Medical supplies:
sufficient medical supplies for first aid are normally available on location.
Gas hazard
a draeger sniffer with different gas detection tubes
1.3 CORROSIVE CONDITIONS IN OIL AND GAS PRODUCTION Corrosion problems which may occur in drilling or in production of oil and gas, may be caused by: •
Sweet corrosion
•
Sour corrosion.
1.3.1 Sweet Corrosion The cause of sweet corrosion can be summarized as follows: Sweet corrosion is caused by carbon dioxide (CO2), which dissolves in the accompanying water phase and, depending on the partial pressure, considerably lowers the pH so that a highly corrosive environment results. The partial pressure is determined by multiplying the volume percentage of CO2 by the gas pressure in ATM. in the system. This can cause either a uniform corrosion, pitting or ringworm corrosion to occur. The extent of sweet corrosion is expressed as follows: Above 2 ATM. partial pressure: serious corrosion Between 0.5 and 2 ATM. partial pressure: sometimes corrosive Below 0.5 ATM. partial pressure: non-corrosive As production testing is usually of short duration, sweet corrosion is considered of no importance here.
8 - 22
Safety procedures
1.3.2 Sour Corrosion Sour corrosion is caused by the presence of H2S and moisture in the production stream, even when the quantities are slight. It can manifest itself as follows: A) HYDROGEN SULPHIDE STRESS CORROSION CRACKING This type of corrosion causes cracks in the material, which eventually fails under load or internal stress; failure may occur at any time during the working life of the material even almost immediately after it is put into service. B) EMBRITTLEMENT The hydrogen derived from the hydrogen sulfide by chemical reaction embrittles the material causing failure to take place within a short time, even in a matter of hours. C) UNIFORM CORROSION The surface of the metal is attacked in a fairly uniform manner, with occasional pitting. The destruction by hydrogen occurs when the partial pressure of H2S in the gas is higher than 0.01 ATM. Below this value, the effect declines sharply and below 0,001 ATM. there is no danger. H2S stress corrosion occurs in steels having a hardness higher than Rc. 22 (237 Brinell). In cases where high residual stress is present, it is possible for H2S stress corrosion to occur at hardness less than Rc. 22. Rough handling of equipment may cause dents etc. which could have a local hardness of over Rc. 22 even if the base material is under Rc. 22. These dents have often been the cause of failures and consequently careful handling of e.g. tubing with tubing tongs is of vital importance. For combating sour corrosion the use of an inhibitor may be risky, as the smallest flaw may lead directly to a crack/destruction. Selection of suitable materials is the best defense, be it a costly one, against this type of corrosion. ACCEPTABLE AND NON-ACCEPTABLE MATERIALS FOR H2S SERVICE A broad outline of these materials is as follows: Acceptable: § § § § § §
API grade J.55, K.55, and L.80; C.75 material preferably type 2 with a maximum hardness of Rc. 22. Low-alloy steels with a maximum hardness of Rc. 22. 300 series stainless steel in annealed condition. Maximum hardness Rc 22. K-Monel, hot rolled and ages hardened. Maximum hardness Rc. 35. Inconel and Inconel X, maximum hardness Rc. 35. Hard facing with stellites, Colmonoy and Tungsten carbide. Base material, maximum hardness Rc. 22. 9% Cr. - 1% Mo. steels quenched and tempered with a maximum hardness of Rc. 22.
9 - 22
Safety procedures § §
Carpenter A-286 steel with a maximum hardness of Rc. 35. Hastelloy B and Hastelloy C.
Not Acceptable: §
Steels with a nickel content of more than 1%.
§
Series 400 Stainless Steel.
§
Precipitation hardened steels.
§
Cold worked steels (below 1000oF).
§
Copper, copper alloys.
§
Free machining steels (containing sulfur and lead).
§
High strength steels.
1.4 LOW TEMPERATURE SERVICE For selection of materials and fabrication requirements not only the aspect of corrosion but also the design temperature of production test equipment, including piping and accessories, has to be taken into account. Notably during a production test of a gas or gas/condensate well the operating temperature can become low due to gas expansion and consequent temperature drop. As ambient temperature may be low as well, the operating temperature may fall to minus 15°F. For this reason, the design temperature of production test equipment has been set at minus 25°F. For arctic conditions exists a design temperature of minus 50°F. Materials, piping and accessories used, have to be suitable for this temperature at the specified operating pressures of the production test equipment. As this equipment is normally rented from Service Companies, the Oil Companies demands that adequate proof be handed to them by the Service Company, concerning the acceptability of the test equipment.
10 - 22
Safety procedures
1.4.1 MATERIAL AND FABRICATION STANDARDS The following materials and fabrication standards have been set in order to safeguard well testing operations: 1.
Vessels and piping shall be manufactured in accordance with ASME CODE VIII Division 1. NACE MR 01.75
2.
All vessel and piping welding shall be 100% X-rayed.
3.
All welding to be made under preheat condition of 212°F with low hydrogen electrodes (permanent-backing rings shall not be used).
4.
All welding are to be stress relieved, maximum hardness Rc.22 after stresses relieving. Inspector selected welds to be checked with a portable Vickers or Rockwell tester. (Stress relieving has been introduced in these requirements to ensure that fully ductile welds and heat-affected zones will be present. Unfavorable material conditions could be present in view of high carbon contents of many American standard materials. Preheating, low hydrogen electrodes and stress relieving are introduced to prevent specifying low carbon content materials, which is generally not available in the U.S.A.).
5.
Separators, including connections and piping, shall be designed for low temperature service. The design temperature to be minus 25°F, unless otherwise specified. (The design temperature was purposely set at minus 25°F as at this level impact testing is mandatory in accordance with the ASME VIII Division 1 CODE. Also, stress relieving is mandatory at design temperature below minus 20°F).
6.
For sour service, all accessories (valves etc.) have to comply with appropriate NACE specifications.
7.
Inspection reports from independent inspectors shall be made available to the Operating Company renting the production test equipment. The Group Operating Company should also be provided with relevant data sheets, material specifications and certification of chemical composition and physical properties including hardness and charpy impact value. Group Company Supervisors should scrutinize this data and make sure that the following pertinent information concerning rented equipment is available prior to production testing: •
Evidence that materials used in fabrication of production test equipment, where applicable, is suitable for MINUS 25°F.
•
Proof that welding has been 100% x-rayed and is accepted by an independence inspector.
•
Proof on stress relieving of welds and hardness check by an independent inspector.
Production test equipment is to be rejected if points b) or c) do not conform to requirements.
11 - 22
Safety procedures If materials are used that are not suitable, where applicable, for low temperature services then the equipment could be de-rated temporarily and should be replaced as soon as possible because the capacity is then probably not in accordance with the terms of the contract. Such de-rating should be: for operating temperatures between 32°F and 60°F to maximum 70% of allowed working pressures, and for operating temperatures below 32°F to maximum 50% of the allowed working pressure. Should standard surface equipment/materials downstream of the Xmas tree master valve be in use by a Group Company and early detection would indicate the presence of H2S, production testing is not to continue and the well must be killed.
12 - 22
Safety procedures
1.5 SAFETY - H2S 1.5.1
Sour Wells - Preface Hydrogen sulphide gas is one of the most vicious and deadly hazards in the Oil Industry and corrosion effects. Some precautions must be taken during the production test.
•
All equipment shall be manufactured to withstand sour effects (SI PM SPECIFICATIONS).
•
All personnel must be thoroughly familiar with H2S.
•
Warning signs, H2S detectors, H2S continuous monitors, escape sets, wind socks, and must be included in the package test.
•
If necessary a male nurse who is specialized in artificial respiration should be present during the test program.
1.5.2 Protective Equipment When working on an H2S well or a well suspected to produce H2S, the personnel must wear the following equipment either provided by the customer or by Geoservices. •
One pocket size personnel detector per technician working at any place in the operation rig up, plus two spare sets. These detectors must be equipped with a visual and sound alarm.
"THE TRIGGER UNIT MUST BE SET UP AT 10 PPM OF H2S CONCENTRATION" •
One escape mask per technician working in any places of the operation rig up, plus two spare sets. These escape masks must be of a filtering cartridge type.
•
One Self Contained Breathing Apparatus (SCBA) per technician working in any place of the operation rig up, plus two spare SCBA'S. These SCBA's are to be of a positive pressure type.
•
Two sniffer glasses tube type measuring apparatuses with sufficient supply of graduated tubes of various ranges.
•
A wind sock/or wind streamers.
•
A reanimation kit:
•
Each crew conducting operations involving H2S should have at least one kit on site. Special and efficient training must be given before starting the job.
13 - 22
Safety procedures
14 - 22
Safety procedures
1.5.3
H2s Service Equipment Definition GAS SYSTEM ONLY §
Below 65 psia of total pressure: no H2S requirements
§
Above 65 psia - pressure (psia) x H2S content (PPM) < 50000
OIL + GAS SYSTEM The "50000" rule applies except if: §
Total pressure is below 265 psia AND
§
Partial pressure of gas is below 10 psia AND
§
Percentage H2S in the gas is below 15%.
In this zone, no H2S requirements. Generally, the "50000" rule applies everywhere upstream of the tanks, and this giving very low H2S contents (50 PPM at 1000 psi). It can be said that as soon as the presence of H2S is suspected, everything upstream of the tank should be H2S proof. Practically only H2S rated equipment is to be used down the WT line. BASIC RULES: §
Any equipment, which cannot be positively identified as H2S proof, must be considered as non-H2S proof.
§
Any equipment on which any welding operation has been performed outside of a properly equipped and qualified shop is not H2S rated any more.
§
Any installation, on which one component has been tampered with, is not H2S rated any more.
§
Any equipment on which modifications have been made should have the H2S identification removed.
§
Any piping having threaded WECO connections is certainly not H2S proof. All such H2 S equipments are welded together.
15 - 22
Safety procedures
1.5.4
Testing - H2s - D O ' S A N D D O N T ' S PERSONNEL: §
Never rely on smell for detection
§
Never return to the contaminated area unless wearing a SCBA
§
Never use escape mask while working
§
Regularly monitor concentration using DRAEGER sniffer tubes
§
Use SCBA when controlled leakage is expected
§
Wears escape mask around the neck - ready for use and escape
EQUIPMENT: §
Never supply pilot circuits with separator gas
§
Never supply heaters with separator gas
§
Oil flow metering using gauge tank is prohibited
§
Feed pilot circuit with compressed air or N2
§
Use diesel-fired heaters
§
Use surge tank with gas outlet connected to low- pressure flare
1.6 SAFETY - MERCURY 1.6.1
Hazards § Mercury vapours max concentration 0.1 mg/m3 (0.8ppm) and is poisonous at very low concentrations. §
Vapour is produced at ambient temperatures in significant concentrations
§
Absorption in human body: a) b) c) d) e)
1.6.2
Inhaling Skin, especially wounds and contaminated clothes Swallowing Long retention time transport / reaction with certain metals Accumulates in kidneys, digestive tract and nervous system
Recommendations The following are the main recommendations to be taken into account when handling, working with mercury §
Storage
§
Ventilation
§
Protective clothing
16 - 22
Safety procedures §
Handling or contamination / spills (Handling of mercury must be done in open and ventilated areas.)
§
Monitoring vapour level in atmosphere
Caution: - Do not eat, drink or smoke when working with mercury. - Leisure/casual clothes must not be used as working clothes. - Working clothes will include headwear (disposable cap) and special shoes. - Working clothes should be of a "closed type". - Handling must be done with "disposable type" gloves and breathing apparatus of disposable mask according to time of exposure. - Before leaving the laboratory, the employee must brush his teeth, wash hands, take a shower and change clothes. - Special containers must be used to store contaminated working clothes, and they will be heated to 70°C for at least 24 hours. - After each work session, laboratory and/or equipment will be cleaned and decontaminated according to work done.Never try to adjust the position of the proximity switches on an installed sensor while the drum is in motion.
1.7 HEAT RADIATION LIMITS 330 BTU/hr/sqft 440 BTU/hr/sqft 1 300 BTU/hr/sqft 1 500 BTU/hr/sqft
2 000 BTU/hr/sqft 3 000 BTU/hr/sqft 4 000 BTU/hr/sqft 5 300 BTU/hr/sqft
sunbathing radiation max harmless exposure to bare skin heats a piece of wood to 500°F max exposure of person wearing working clothes and intermittently sheltered or sprayed with water (after API-RP521) pain threshold reached after 8 s exposure of bare skin, blisters after 20 s max for steel structure piece of wood reaches 800°F and ignites blisters after 5 s
PRECAUTIONS Heat radiation patterns (radburn) PREVENTIONS • • •
Inject water into flame Use water screens 85 ft booms
17 - 22
Safety procedures
1.8 NOISE EXPOSURE (hours) 8 4 2 1 1/2 1/4
MAXIMUM SOUND LEVEL dB(A) 85 88 91 94 97 100
EXAMPLES: •
Off-shore accommodation
45 DBA
•
Off-shore control room
60 DBA
•
Separator 4 000 BOPD/GOR 300
62 DBA
At 100 ft from 6" gas flare: •
10 MM SCFD (350 psi sep. pressure)
96 DBA
•
35 MM SCFD (850 psi sep. pressure)
107 DBA
1.9 EROSION EROSION due to the presence of solids and combined with high fluid velocity represents a major testing hazard, particularly in the case of gas Well Testing: • • •
Unconsolidated sands Salt particles Post sand frac testing
Erosion occurs in elbows and zones or turbulence such as flanges. If erosion is expected: • • • • • •
Monitor frequently pipe wall thickness with an Ultrasonic Thickness Detector (Krautkramer DM2) Reduce fluid velocity Monitor solids production Maintain pipe routing as straight as possible Replace elbows by large radius ones Use higher-grade (thickness) piping.
18 - 22
Safety procedures
1.10 GUIDELINE ATTACHMENT DIMENSIONS Cable diameter
Number of U.Clamp
A
B
C
D
E
F
G
H
J
K
M
Work Load
5/8"
55 mm 2 3/16
90 mm 3 1/2
80 mm 3 5/32
76 mm 3"
35 mm 1 3/8
32 mm 1 1/4
114 mm 4 1/2
95 mm 3 3/4
51 mm 2"
14 mm 9/16
100mm 4"
3
12000 kg
1"
75 mm 2 1/8
115mm 4 1/2
95 mm 3 3/4
90 mm 3 1/2
41 mm 1 5/8
38 mm 1 1/2
146mm 5 3/4
127mm 5"
60 mm 2 3/8
18 mm 3/4
150mm 6"
4
140000
kg
19 - 22
Safety procedures
20 - 22
Safety procedures
1.11 SOME SAFETY RULES FOR THE "OIL PATCH" - 50 DO'S AND DON'T Following is a list of 50 recommendations and rules pertaining to SAFETY in the Field. The various points listed should be discussed and emphasized during SAFETY MEETINGS to all your Personnel. It is your duty and responsibility to check that these rules have been understood and are adhered to. 1.11.1 GENERAL 1. Always wear your safety equipment i.e. boots, hard hat, overall, gloves, goggles (no nylon clothing). 2. Do not drive without your safety belt on. 3. Do not drive recklessly. 4. Before removing a gauge or a plug from a vessel or pipe, make sure that there is not pressure left inside. 5. Never hit vessels or pipes under pressure. 6. When working above water, wear your life jacket. 7. Prior leaving the Base, make sure your radio sets are working, spare tire(s), water supply. 8. Make sure that you know the location of the fire extinguishers and that they are full and you know how to operate them. 9. Make yourself sure that everybody in your crew knows what his duties are going to be. 10. Ensure yourself that your working stations are clean and not littered. 11. Should night work be envisaged, take appropriate steps to ensure proper lighting. 12. Remember that a tired Operator is a potential danger to the rest of the crew. 13. Do not jump from platforms: use the stairs and ladders. 14. For each kind of particular work, use the appropriate tools. 15. Never do a welding job on or close by a vessel having contained hydrocarbons without making sure it has completely degassed (steam cleaning is one of the best ways to degas). 16. Before lifting a piece of equipment with slings, make sure the cables are in good shape and the clamps and shackles well tightened. 1.11.2 WIRELINE 17. Always make sure that the pressure has been bled down to zero before attempting to unscrew a quick union. 18. Never run-in a well with the winch engine stopped. 19. Do not climb or let somebody climb the lubricator whenever it is under pressure. 20. Never attempt to pull a plug before the pressures across it have been equalized. 21. When rigging up or down a lubricator, never stay below it. 22. Blowout preventer should always be tested before each job. 23. When running in for the first time always check the weight frequently. 24. It is recommended practice to run a gauge cutter (or sinker bars only) prior to running anything else in the hole. 25. When working in H2S wells, inhibit the wire (Kontol, Norust). 26. When coming out of the hole, use the winch relief valve. 27. Always write down the length of the different components you are running in the hole. 28. When cutting wire at the surface (rig down) make sure that neither end can "fly". 29. Always anchor the winch to the platform or deck it is installed on. 30. Always work in sight of each other. 21 - 22
Safety procedures 31. Before attempting a fishing job, check that your lubricator is long enough to handle both lost string and fishing string. 32. When running a wireline job, always have a clear view of the stuffing box. 33. Keep track of the number of hours the wire has worked. Change it before it is too late. Check frequently for defects or corrosion. Between each job, cut and remove at least 10' of wire. Don't leave the cut wire on the wellsite 1.11.3 WELL TESTING 34. Standing rule when testing wells containing H2S: NO GAS (no matter how small the amount) SHOULD BE RELEASED TO THE ATMOSPHERE UNLESS IT IS BURNED ON THE SPOT. 35. Do always use compressed air or nitrogen to pilot a separator working with H2Srich effluents. 36. Do not supply a heater with H2S loaded gas - use diesel oil. 37. Have each member of the well testing crew show that he knows how to operate the safety apparatuses. 38. Whenever changing orifices or sampling on a separator metering H2S effluents, it is mandatory to breath air coming from compressed air bottles. 39. Always open up a well slowly using the upper master valve. 40. Whenever possible, use a surface safety valve remote-controlled (pilots). 41. Surface safety valve should always be installed upstream of the choke box. 42. Do not use steel sledgehammers to tighten connections - brass is a must. 43. Wear a safety harness when working on the burners. 44. On a floater, use enough chicksans to allow the compensating of maximum heave. 45. Never allow a flame or naked light inside the safety perimeters. 46. Always pressure tests your installation prior to well opening. 47. When two or more people are called on to work at the same time on the same installation, keep within sight of each other. 48. Each crew working on isolated locations (onshore) should take along a first aid kit. 49. When designing a well testing set up, make sure the equipment planned can safely withstand and handle the maximum well head pressure. 50. Every member of the well testing crew must know how to shut in a well in case of emergency.
22 - 22
Pipes and fittings
SECTION 3 PIPES AND FITTINGS
1-1
Pipes and fittings
1.1 HOSES AND PIPING The various elements of the Well Testing set up are linked together through different pipes and hoses, which are selected according to: •
Service pressure
•
Flow rate
•
Relative movement and layout of WT equipment.
The highest expected pressure at a particular point of the Well Test set dictates SERVICE PRESSURE of pipes and flow lines up. This will vary for as high as 15000 psi between FLOWHEAD and CHOKE MANIFOLD for A HIGH PRESSURE WELL TEST to 2500 psi between SEPARATOR and BURNERS. FLOW RATE is taken into account to determine pipe size. Pipe diameter is usually 2" or 3" upstream of the choke and 3" downstream. 4" piping is sometimes used downstream of the separator for HIGH RATE GAS TESTS. Piping is refereed to by its NOMINAL size actual ID can be considerably smaller of heavier pipe grades. Piping routes should be kept as straight as possible to decrease pressure losses, erosion and cost. However to accommodate relative movement of WT elements and WT equipment layout, a typical set of piping consists of a mixture of RIGID (STRAIGHT LENGTHS and ELBOWS) and ARTICULATED (CHICKSANS) piping or FLEXIBLE HOSES. On HIGH PRESSURE TESTS, FLEXIBLE HOSES are normally preferred to CHICKSANS as they prove to be more reliable and relatively maintenance free. Piping elements and hoses are connected together through "WECO" wing unions. These unions are designated by their nominal size and FIGURE NBR (e.g. 3" 1002) in Geoservices the first two digits refer to the test pressure the last two digits refer to the sealing method.
2-2
Pipes and fittings
WELL TEST PIPE
PIPING USED IN WELL TEST RIG UP IS COLOUR CODED ACCORDING TO PRESSURE RATING AND SERVICE. Note: All H2S pipe must have welded unions.
602 PIPE, 3000 psi WP, H2S
H2S
1002 PIPE, 5000 psi WP, H2S
H2S
1502 PIPE, 10000 psi WP, H2S
H2S
3-3
Pipes and fittings
1.2 WING UNIONS
DEFINITION Fittings used to join lengths of pipe to permit easy opening of a line. Weco Wing Unions are identified by “Figure number” SIZES 1" through 12" RATED PRESSURES 1,000 psi through 30,000 psi. APPLICATIONS For suction and discharge lines carrying liquids, vapours, gas or semi-solids. In Geoservices typical Wing Unions used are:
Union Fig 200General-Service manifolds and lines. Maximum pressure : 2000 Psi Possible diameters (in inch): - 1 - 1.25 - 1.5 - 2 - 2.5 - 3 - 4 Possible assembly : - BSP Cylindrical - NPT Threads - Welded
Union Fig. 602 is used on Geoservices separator and choke manifold. Maximum pressure: 6000 Psi Possible diameters (in inch): - 1 - 1.25 - 1.5 - 2 - 2.5 - 3 - 4 Possible assembly : - BSP Cylindrical - NPT Threads - Welded
4-4
Pipes and fittings
Union Fig. 1002 is used on Geoservices heater, steam heat exchanger and choke manifold. Maximum pressure : 10000 Psi Possible diameters (in inch): - 1 - 1.25 - 1.5 - 2 - 2.5 - 3 - 4 - 5 - 6 Possible assembly : - Integral Tubing Seal - NPT Threads - Welded
Union Fig. 1502 is used on Geoservices flowhead heater and choke manifold. Maximum pressure : 15000 Psi Possible diameters (in inch): - 1 - 1.5 - 2 - 2.5 - 3 - 4 Possible assembly : - Integral Stainless Steel Overlaid Face - Integral Tubing Seal NPT Threads - Welded SERVICE ADVANTAGES Weco Unions make up fast and seal perfectly. They withstand tougher service in a greater variety of installations than any other union. MAKE UP Weco Unions require no special tools or wrenches. Wing nut can be made up seal-tight with an ordinary hammer.
5-5
Pipes and fittings
INTERCHANGE ABILITY Parts of the same size and pressure rating are interchangeable so there is no difficulty matching and mating male and female subs that are frequently made up and broken out. This is a decided advantage on rig piping and service company operations such as cementing, acidification, fracture job etc. IDENTIFICATION Distinctive colors identify Weco Unions according to pressure rating. SEALING Fig. 402, 602, 1002 and 1502 Unions have a resilient seal ring, in addition to the ball and cone seat. ORDERING Weco Unions may be ordered by Figure number and/or pressure rating (see table below). Nominal Pipe size must always be specified. The designations, Male Sub and Female Sub refer to seating surfaces, NOT threads (See illustration). The Female Sub has conical seating surface and Acme threads for wing nut. The Male Sub has ball seating surface but NO Acme threads. When ordering parts, it is important to specify correct sub to avoid errors and delays. The Male Sub is sometimes referred to as plain sub, and Female Sub as threaded sub.
Note: carefully check all unions before proceeding to connection and correspondence between manufacturers.
6-6
Pipes and fittings
Caution: Not all the WECO unions are certified H2S.
Note: Generally WECO subs are welded and cannot be unscrewed, but it might happen, when replacing leaking or damaged parts or to make a female-female or male-male sub, WECO unions are removed. Caution: Care should be taken that pairs with different pressure ratings are not mixed. Even so, if you refer to the figure below and Table 1: 2 WECO fig. 602 and 1002 have the same thread - 3 1/16" Stub ACME with 3 threads per inch. The OD of the thread of the female sub lies between 3.812" and 3.796" for both figures. A 2" WECO Fig. 1502 has a 4 1/8" Stub ACME with 3 threads per inch. The ID of the thread of the nut lies between 3.792" and 3.808". Hence it is possible to screw a 2" WECO Fig. 1502 nut on a 2" WECO Fig. 602 or 1002 female sub, but the maximum thread overlap is only 0.010". This is not sufficient to hold high pressure. A 2" WECO Fig. 1502 nut fits over a 2" WEA 2" WECO Fig. 1502 nut fits over a 2" WECO Fig. 602 or 1002 male sub, but the shoulder has only an overlap of 0.088" (Distance B-C = 3.437 - 3.349 = 0.088"). The same can happen with a 3" WECO Fig. 1502 nut installed on a 3" WECO 602 or 1002 male sub. The overlap is then 0.232", which is smaller than the overlap of a correct connection i.e. 0.588" for WECO Fig. 602 and 1002 and 0.357" for a WECO union Fig. 1502.
Note: The 3" WECO unions Fig. 602, 1002 and 1502 all have different number of thread per inch. It is therefore not possible to mix and screw them together.
7-7
Pipes and fittings
1.2.1
Main Features Of Original Weco Union
WROUGHT NUT: with three lugs, in order to resist to the impacts and guarantee a long playing. The nut longlife guarantees the safety of the screwing up and the sealing, for years of assemblies and disassemblies.
FEMALE SUB: threaded sub (ACME or ISO). Material selected according to specifications. Quality steel: Standardized, hardened, tempered. Carbon steel, low carbon, inox, etc... European and American standards. To weld or thread.
Threaded ACME: corresponding to FMC Energy Systems standards, as well as American and European standards (trapezoïdal modified). Absolute guaranty of interconnection (between same figures).
Threaded ISO: in accordance with European standards : in general application to chemistry. Absolute guaranty of interconnection (between same figures).
MALE SUB : sub which holds the nut. Material selected according to specifications : steel, carbon, low carbon, Inox, etc...To weld or thread.
THE SEAL : it is chosen according to the product conveyed, it acts as primary seal and protects the spheronical seat at metal / metal range, against abrasion and corrosion. A special shoulder guarantees its holding on the range. Seal qualities : Buna, Viton, Teflon, etc... depending on the application.
8-8
Pipes and fittings
1.3 CONNECTION MANIFOLD
LINE
BETWEEN
FLOWHEAD
AND
CHOKE
To allow for relative movement of the flowhead to the drill floor the line connecting to the choke manifold must be flexible. A flexible line is necessary when testing on a floating rig, but it will also allow picking up and slacking off the flowhead to set the packer or to operate the MFE. The main options for flexible lines are: § CHIKSAN Swivel § COFLEXIP Hose 1.3.1
The Chicksan Swivel
The CHIKSAN swivel joints have established a long track record of successful applications whenever all-metal flexible flow lines are required instead of rubber hose. Their main advantages are: § Smooth flow radii permit minimum restriction § Two or three rows of ball bearings handle moment, thrust and radial loads § Dynamic seal packing units are elastomer for temperatures to 225°F; polyresin for temperatures to 450°F § Grease retainer ring keeps ball race clean § 360° rotation in one, two or three planes.
9-9
Pipes and fittings Standard chicksan swivel joints used in Geoservices are of the "TRI-RACE"" type 10.000/15.000 psi WP/TP and 3" nominal size. Other sizes can be found in the field, particularly the 2" sizes 10.000/15.000 psi WP/TP that is lighter and easier to handle. Widest selection in the oil-field Chicksan swivel joints come in 3/8 to 12 inch sizes and can handle pressures to 20,000 psi. Sour gas models are limited to 15,000 psi. Eight chicksan styles or configurations are available from stock. These styles can be combined in an unlimited variety of ways to suit practically any installation. End connections are threaded, integral Weco wing unions, beveled for welding or flanged. Sour gas swivel joints have Weco wing union end connections. Pressure tight seals protect bearings from line fluid Chiksan swivel joints come standard equipped with nitrile packing and bonded brass anti-extrusion ring. 6 to 12 inch sizes have stainless steel anti-extrusion ring. The antiextrusion ring serves as a retainer and bearing to reduce friction between the resilient packing material and the packing chamber as the joint is turned. These dynamic seal packing units protect ball races and bearings from line fluid through the stated pressure range, including vacuum or suction service to 225°F. Most Longsweep models have a secondary O-ring seal, which prevents minor leakage past the packing from contacting the bearings. These Longsweep swivel joints also have a leak-detection port between the packing and O-ring seal. If leakage past the packing should occur, it is forced through the leak-detection port, signaling the need for packing replacement. Bearings key to rotation, strength To assure long, dependable operation, chicksan ball bearings are matched to loading and service conditions. Although the size, type and number of bearings vary, chicksan low-pressure, high-pressure and extra high-pressure swivel joints all have two rows of bearings in each swivel and flame-hardened ball races. The majority of chicksan Longsweep swivel joints have three rows of bearings in each swivel for improved load capacities. All Longsweep swivel joints for standard service have carburized and hardened ball races. Smooth, round bore minimizes flow restrictions Chiksan swivel joints have smooth round bores to minimize turbulence and keep pressure drop low. Longsweep swivel joints have extra long radius elbows for even better flow characteristics and reduced chance of washout when handling abrasives at extremely high pressures. Simple maintenance Only occasional light greasing with a small hand-held grease gun is required to keep chicksan swivel joints on the job. If packing, bearings or ball plugs should need replacing because of leakage, field repair kits are available. Easy to follow instructions come with each repair kit. CHICKSAN LOW PRESSURE SWIVEL JOINTS 175 psi (12 bar) to 1,000 psi (70 bar) cold working pressure; 3/8 to 12 inch sizes. Recommended service Transfer lines, temporary flow lines, discharge lines, auxiliary flow lines, water lines and other general-service oil-field applications. CHIKSAN STYLES AND COMPONENT PARTS Chiksan swivel joints are available from stock in eight basic styles or configurations. These styles permit 360 degree rotation and movement in one, two or three planes. They can be combined in an unlimited variety of ways to suit practically any installation. Note: Although chicksan swivel joints can be rotated while under fluid pressure, they are not recommended for services requiring continuous rotary motion. All chicksan swivel joints are assembled using two or more standard pieces. Component piece numbers are shown here with the various chicksan swivel joint styles.
10 - 10
Pipes and fittings TECHNICAL CIRCULAR WORKING PRESSURE OF 3" 10000 CHKSANS AND WECO UNIONS FOR SOUR GAS SERVICE We would draw the attention of users of the above equipment to the fact that some confusion may arise from the way that the working and test pressures are marked on the following materials: §
3" chicksans 10000 H2S Tri Race
§
3" Weco unions 10000 H2S (Fig. 1502 Special)
§
3" straight connections 10000 H2S
Nuts for 3" Weco unions, heat treated for H2S service (22 Rc max) 10000 psi CWP (cold Working Pressure i.e. - 20° F to 200° F service) and manufactured by FMC and Best Industries, are labeled as follows:
To conclude it is necessary to explain to users and customers that the material is made for 10000 psi working pressure in a temperature range from -20° F to 200° F and 15000 psi test pressure. The confusion comes from incorrect marking on the union nuts. In future after agreement from FMC, we suggest grinding out the word "TEST" and stamping "CWP" instead. Note: For standard service equipment (non H2S proof) further confusion may arise between test and working pressures when reading the 1976/77 Composite Catalogue on FMC products, which gives for a Fig. 1502 Weco "15000 psi TEST" and then "Recommended for 15000 psi NSCWP (NON SHOCK COLD WORKING PRESSURE) air, oil, water or gas. 10000 psi WP at 350°F»! !
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Pipes and fittings
1.3.2 COFLEXIP During a drill stem test your test line has to stand up to a lot of aggression from the fluids - mingled with sand and sour gas - which may come rushing through it at great velocity under high pressure. This is when a Coflexip test line can be your best friend. It's a hose - but then again it isn't. It's a steel pipe that flexes. Coflex is the preferred test line solution among petroleum engineers and service contractors who know all about routing rigid pipes and have experience of leaking swivel joints and the effects of live crude on rubber. A Coflexip test line is one continuous, flexible route from your flow head to your choke manifold. It gives you the strength of a rigid steel pipe with added bonuses: greater resistance to abrasion, corrosion and shock from pressure surges. It won't "whip" or "kick" like an ordinary hose can. There are no elbows, intermediate joints or swivels to deteriorate and cause a leak in your system, because there are only two couplings to connect up - one at each end. The end couplings that complete the Coflexip unit undergo Ni-Kanigen anti-corrosion treatment. "Maintenance" is minimal - you simply flush out with water after use! and change the WECO seal.! These properties stem from the unique qualities built into the Coflexip structure. It is designed to resist abrasion and corrosion from all types of hydrocarbons, H2S and CO2. The concept of separate armor layers with independent functions makes for maximum stability during pressure surges. As an example of performances the 15,000 psi WP 3" ID drill stem test line has a tensile strength in excess of 170 tons! And the range includes working pressures up to 20,000 psi. § Greater Strength, Stability and Reliability § Higher Performances and Durability § Easier, Faster Installation and Adaptability § No Maintenance § Three Year Limited Warranty § Available in any length § Supplied complete with any type of standard oil-field connection of your choice § Improved cost efficiency When your choke and kill lines are the only things standing between you and a blowout, you know how important their strength and reliability are. If you're using rigid steel with swivel joints or reinforced rubber hose, they're the weak link in the system. Strength Coflexip's flexible steel choke and kill lines offer the strength of rigid steel, and resistance to shock from high pressure surges. A continuous, interlocking spiral of ZSECTION steel forms the flexible steel pipe (some are designed to work at pressure of up to 20,000 psi). A seamless thermo-plastic sheath lines the internal pressure barrier and resists abrasion and chemical attack. Cross-wound tensile armor pre-stresses each line for maximum stability during pressure surges. Flush ID connectors are attached in a way that maintains the integrity of the line. Because Coflexip is manufactured in continuous lengths, there are no joints or discontinuities to weaken a Coflexip line. Safety Because Coflexip is flexible, there is no need for failure-prone swivels and intermediate connections that can mean danger when you use rigid steel pipe. Coflexip is also less subject to attack, erosion or aging from well fluids, including aromatics. A Coflexip line is a single, integral unit. If Coflexip is damaged, it does not shear and whip, like a hose. Low Maintenance
12 - 12
Pipes and fittings Because it has no seals or intermediate connections; Coflexip requires little or no maintenance. And unlike rubber hose, Coflexip does not deteriorate significantly with time. Testing Coflexip documents the strength of its product. For your security, every line is tested at rated test pressure for a full 24 hours! Special tests are available upon request a limited warranty up to three years. § Only two end couplings to connect § Can be supplied with any standard end coupling § No maintenance. No seals to be replaced § No corrosion. End couplings are Ni-Kanigen treated. All Coflexip choke lines are suitable for H2S service § External protection. Stainless steel outerwrap provides good fire resistance (20 to 30 minutes at 800°C before leaking, and without ever bursting) § Further insurance of superior quality and reliability: all Coflexip drilling and service lines are pressures tested for 24 hours before leaving the plant § Reliability: Proven on over 400 mobile offshore rig MAIN CHARACTERISTICS (subject to change without notice) FLEXIBLE PIPES OD
MAIN BUILT IN COUPLINGS
Maximu Weight Nominal m Test in Diameter Working Pressure empty Pressure
inches inches psi
psi
3.9
2"
5000
5.3
3"
kg/m
Minimum Recommended air Bending radius radius in service for storage (approximate) API INTEGRAL FLANGE
lb.ft
inches cm
feet
meter
10000 23
15
23
59
3
1.1
5000
10000 37
25
34
87
4.5
1.4
5.8
3 1/2" 5000
10000 42
28
37
95
4.7
1.4
4.1
2"
16.5
26
68
3.4
1.0
5
2 1/2" 10000 15000 39
26
32
82
4.7
1.4
5.4
3"
10000 15000 42
28
33
83
5
1.4
6.6
4"
10000 15000 59
40
40
102
6
1.6
5
2 1/2" 15000 22500 39
26
32
82
4.7
1.4
5.8
3"
15000 22500 56
38
38
96
5
1.4
5.6
2 1/2" 20000 30000 56
37
33
84
5
1.4
10000 15000 24
INTEGRAL CLAMP HUB CONNECTION
ID
API 6B 21/16" - 5000 21/16" for R or RX 24 5000 API 6B 31/8" - 5000 31/8" for R or RX 35 5000 API 6B 41/16" - 5000 41/16" for R or RX 39 5000 API 16BX 21/16" - 21/16" 10000 10000 for BX 152 API 16BX 29/16" - 29/16" 10000 10000 for BX 153 API 16BX 31/16" - 31/8" 10000 10000 for BX 154 API 16BX 41/16" - 41/16" 10000 10000 for BX 155 API 16BX 29/16" - 29/16" 15000 15000 for BX 153 API 16BX 31/16" - 3" 15000 150000 for BX 154 API 16BX 29/16" - 21/16" 20000 20000 for BX 153
seal ring
cla mp n°
BX 152 1 BX 154 4 BX 155 5 BX 152 2
BX 153 4
BX 154 5
BX 155 6
BX 153 3
BX 154 6
BX 153 6
13 - 13
Pipes and fittings FLEXIBLE TEST HOSES
14 - 14
Pipes and fittings
LAYER 1 (inner)
DESCRIPTION Internal plastic sheath
2 3 4
Z-shaped wire (zeta) Flat steel reinforcing wire Intermediate plastic sheath
5
Double cross wound tensile armours External thermoplastic sheath Stainless steel outer wrap
6 7
PURPOSE To make the hose internally leak off To resist internal pressure To increase "zeta" properties To reduce friction between layers 3 & 5 To resist axial loads To make the hose externally proof To protect the hose against external damage
15 - 15
Pipes and fittings
MECHANICAL BEHAVIOUR OF FLEXIBLE LINE By design, a COFLEXIP flexible line is extremely resistant to: Internal pressure § Dimensional changes under pressure are very limited; typical values are: § Relative elongation at design pressure 0.15 to 0.25 % § Relative outer diameter change at design pressure < 0.25 % The line is extremely stable under pressure. In particular, if bent it will not tend to straighten under pressure. No significant twist would occur. It will not pulsate or whip during high flow rate circulation. Tensile strength Resistance to pulling forces ranges from about 5O,OOO daN for a 2" ID to more than 100,000 daN for a 3" lD (50 to 100 tons or 100,000 to 200.000 Ibs). Crushing The crushing resistance of COFLEXIP flexible pipes is similar to that of an API rigid pipe of the same design pressure. Bending The line is resistant to bending; including frequent or continuous flexions with the imperative condition that the minimum-bending radius is not exceeded. In COFLEXIP's documents, the minimum-bending radius is abbreviated as MBR. The minimum-bending radius is an extremely important characteristic of a flexible steel line. As a rule of thumb, the minimum-bending radius is roughly equal to: MBR =12 x ID (ID: inner diameter of the line). Example: lD = 3" MBR @ 36". i.e. 3 ft. For specific DRAG CHAIN applications. the MBR for installed use is 1.1 x the storage MBR, as defined on the relevant data sheet. The accurate value of the MBR is part of the technical specification of the flexible line.
FAILURE MODES OF COFLEXIP FLEXIBLE LINES COFLEXIP flexible steel lines are extremely reliable due to: § The design of the product; § The use of the highest standards applicable; § The COFLEXIP quality assurance system. However, misuse might damage the line. and it is useful to identify the four mains failure modes. Bending If the minimum-bending radius is exceeded, the zeta layer may open; in which case, the inner tube is not properly supported and perforation will occur under pressure. Over-bending generally occurs due to mis-handling during installation. Particular attention must be paid at this time to the first few feet of flexible pipe immediately behind each termination. an optional bend stiffener is available on request to improve the pipes resistance to such over bending.
16 - 16
Pipes and fittings Figure 6 shows how over bending may be caused. Whether or not the line be under internal pressure. Aging of the inner liner The mechanical properties of the inner liner can be affected by aging. This phenomenon causes the degradation of the long molecules of thermoplastic and may be due to: § Long exposure to high temperature, exceeding the maximum rated temperature § Use of incompatible chemical products through the line. The degradation of the material could make it brittle, and the tube may break when bent with or without internal pressure. leading to a leakage. Corrosion of the armour wires. If the Outer thermoplastic sheath is damaged corrosion of the steel armor wires will occur. This will progressively reduce the thickness of the wires, causing a progressive decrease of the burst pressure. This failure mode may cause the line to burst. Collapse of the inner liner. If damaged, the outer sheath may not be leak proof. For subsea lines the external hydrostatic pressure will be applied on to the inner liner, which may collapse. GENERAL GUIDELINES Storage. §
Storage in general does not require specific precautions regarding environment or duration of storage. § According to its length, the best ways to store a line are either: 1. In a straight line (up to 20 ft long); 2. Coiled to its MBR, attached to a wooden pallet or crate: 3. Installed in a DRAG CHAIN prior to hook-up and start of operations. COFLEXIP Flexible lines are shipped with protection on the connectors. A similar protection should be reinstalled when the line is disconnected. It may consist of a metallic blind flange that fits the connection - which is preferable or of a good wooden protection. This protection must ensure that: § The inner bore of the line is closed to avoid accidental intrusion of any foreign material: § The connector, especially the seal area. is properly protected against impacts, etc.. If stored below minimum rated temperature ensure that no handling is done before the line is brought back to minimum rated temperature. The inner bore of a COFLEXIP line should be thoroughly flushed with fresh water prior to long-term storage.
17 - 17
Pipes and fittings
HANDLING The line must never be bent below the minimum bend radius, as this may damage it. As a rule of thumb, the minimum bend radius is equal to: MBR = 12 X lD The accurate value of the MBR of the line is part of the technical characteristics of the COFLEXIP structure and can be obtained from the nearest COFLEXIP office. The minimum bend radius (MBR) must be respected at all times, whether the line is under pressure or not. User should avoid bending the flexible just behind the end fitting. As a rule of thumb, a straight length of about 2 to 3 feet ( 0.8 - 1.0 M) should be used as a safety distance (See section - FAILURE MODES OF COFLEXIP FLEXIBLE LINES). The use of wire ropes or chains may damage the anti-corrosion treatment of the end fitting. It so required use a shackle connected through the eye of the lifting collar. Never use wire ropes or chains directly against the stainless steel outer wrap. If force, needs to be applied to the body of the flexible line itself, use nylon slings. Moving flexible line on the ground § Do not attach slings directly to the end fitting - use the lifting collar instead. § Always connect slings to both lifting eyes in order to have the pulling force in a straight line with the main axis of the line. § Prevent abrasion of the flexible line against the ground; use wooden supports or planks. § To lift the line, a forklift may be used provided that slings are installed to prevent sharp edge contact (see COFLEXIP Handling Guide). Installation of a flexible line to a connector requires: 1. Supporting the weight of both the end-fitting and the line: 2. Correct alignment of the end fitting. To achieve this: § The best way is to support the weight of the line through the use of the lifting collar § Then, control the alignment with a non-metallic rope or sling attached about 3 feet (1 meter) behind the end fitting. § Never does the reverse I.e.: Support the weight behind the end fitting; § Align the line from the end-fitting attachment. WELDING A flexible steel line is a mixed construction of steels and thermoplastics. It must be recognized that through heat diffusion, which occurs during any welding process, the Thermoplastic layers may suffer irreversible damage leading to an unsafe line. When used, welding processes are only completed during the original manufacturing process of the line at a stage where the operation cannot affect the other components. Consequently, any field welding repair of a flexible line, involving either the end fitting (including the stainless steel ring groove) or the stainless steel outer carcass, will render the line unsafe and unusable. Such lines must withdrawn from service and stamped "NOTREUSABLE".
18 - 18
Pipes and fittings
19 - 19
Pipes and fittings
1.4 GYROLOK Gyrolok is a trade name for a high-pressure pipe fitting for small diameter pipe; typically 1/2" or 1/4". The thing that makes Gyrolok (Also "Swagelok") different to other small pipe unions is that no flaring/crimping tools are necessary. Typical applications for testing are instrument and pressure lines on separator, piping for Texsteam pump, etc... ASSEMBLY INSTRUCTIONS 1. Firmly insert the tubing 2. Finger tightens the nut. Now simply tighten the nut 1¼ turns. REASSEMBLY INSTRUCTIONS Gyrolok fittings may be assembled and disassembled repeatedly. The following instructions should be carried out to reassemble a fitting. 1. Insert the tubing end with the previously set ferrules into the fitting body and tighten the nut to a hand-tight condition. 2. With a wrench, tighten the nut until a sharp rise in torque is felt, then simply snug with wrench. TUBE SELECTION Specific recommendations to applicable ASTM standards. The tubing selected whether metallic or non-metallic, should be compatible with the process fluid, temperature, and application. The wall thickness selection should be based on the operating pressure, temperature and shock conditions. Fully annealed tubing is recommended. Stainless steel tubing having a hardness of less than Rockwell B90 should be used with Gyrolok fittings. Nylon and Teflon ferrules are available for use with glass tubing. TUBE PREPARATION Tubing ends should be cut relatively square and burrs removed. Where practical, the use of tubing cutter is recommended.
20 - 20
Pipes and fittings ASSEMBLED FITTING AND TUBE
1. 2. 3. 4. 5. 6. 7. 8. 9.
Ease of assembly - Low assembly torque Unique "Roll-in" locking action by rear ferrule. Not just sliding angles No tube rotation on make-up No torque transmitted to tubing Controlled ferrule drive Minimum tubing I.D. reduction Solid "Metal to Metal Make Up" leaving no voids Tubing "Butt Seal" provides a "Series Seal" Full face contact and support among all components after make-up and subsequent re-makes 10. Four point support for vibration control 11. Cannot be Over tightened - "Cannot self-destruct" 12. Unique sizing angle prevents sticking.
21 - 21
Pipes and fittings
HOKE VALVES WITH GYROLOK TUBE FITTINGS
Gyrolok flareless tube fittings are used exclusively on Hoke valves for quick and easy installation to tubing. Gyrolok ended valves are specially machined so that the fittings are an integral part of the valve body to prevent leakage and provide low torque installation and thanks to Gyrolok's controlled ferrule drive, the valve body end connections are protected from damage.
22 - 22
Pipes and fittings HANDS ASSEMBLED GYROLOK FITTING
§ § § § § § § § § § §
All components made from same type material High-pressure applications High temperature and bake-out applications Cryogenic applications Vibration resistant Use on metal, plastic and glass tubing - thin and heavy wall Excellent make and re-make life Complete interchangeability in the field Seal pressures that will burst tubing Threads of 316 S/S nuts silver plated - no galling Angle between ferrules before make-up
23 - 23
Pipes and fittings ASSEMBLED GYROLOK FITTING AND TUBE
1. 2. 3. 4. 5. 6. 7. 8. 9.
Unique "Roll-in" locking action by rear ferrule. Not just sliding angles. No tube rotation on make-up. No torque transmitted to tubing. Controlled gripping action. Minimum tubing I.D. reduction Solid "Metal to Metal Make-up" leaving no voids. Tubing "Butt Seal" provides a "Series Seal" Full face contact and support among all components after make-up and subsequent re-makes Four point support for vibration control Cannot be over tightened - "Cannot self-destruct"
24 - 24
Pipes and fittings
1.5
THREADS
The aim of the threads is to enable the linking of two parts together like tubings - valves, etc. by means of screws or bolts for the flanges. Threads are cylindrical or taper parts on which a helicoidally groove has been machined. The diameter is the outside diameter of the male thread (which is the diameter of the screw). 1.5.1 Characteristics To perform the main functions of the threads - sealing - mechanical linking - we have several types of threads. A thread is characterized by: SHAPE Cylindrical (mechanical linking) Taper thread (utilized in the oil industry - good tightening - good tightness. PROFILE S.I. SQUARE TRAPEZOIDAL ROUND
Triangular - The most utilized - easy to machine - secures a good tensile strength. Rapid tightening - good line up. Better tensile strength. Difficult to machine but excellent for tensile strength.
PITCH STANDARD FINE HIGH
Correspond to the standard of tensile strength, tightness, tightening - line up. Better tightness and good tensile strength. Perform an easy and rapid tightening.
25 - 25
Pipes and fittings
26 - 26
Pipes and fittings
1.5.2
Cylindrical Threads ISO THREAD Two faces parallel Profile at 60°. Truncation for the male part is equal H/8 at the crest ad H/6 at the base. The female part has a truncation equal to H/4. TRAPEZOIDAL THREAD They are used for their great resistance and are very easy to assemble. The profile is an isosceles trapezium with 30° angle for the non-parallel side. WHITWORTH Used in England for screws - bolts etc. the base section is an isosceles triangle with an angle of 55° at the top. The truncation is H/6 at the top and at the bottom. The angles are round. The different whitworth threads are: § British standard whitworth BSW § British standard fine BSW § Gas threads § British standard pipe fastening BSPF NATIONAL PIPE STRAIGHT This is the Brigs cylindrical thread. § NPSI intermediate § NPSF fuel-oil § NPSC coupling § NPSH hose coupling § NPSM mechanical § NPSL locknut The profile is triangular at 60°. The crests and bases are truncated the truncation is function of the pitch. § At crest : 0.033 p § At base : 0.033 p § Height at thread : 0.866 p SUCKER ROD THREAD Used principally in pumping well and for wireline tools. API standardizes them. The profile is equilateral triangle crests and bases truncated to H/8. H is equal to 0.86603 p. Pitch: 10 threads per inch.
1.5.3
Tapered Threads The taper is commonly 6.25%. TAPERED GAS THREADS They have the WHITWORTH profile. The taper is 6.25%; it can be used with 2 tapered threads or 1 tapered gas thread and 1 cylindrical gas thread. BRIGS OR NATIONAL PIPE TAPER Only the manufacturing tolerances are different in case, of the NPTF truncation control at the base and crest is such that it ensures a high-pressure seal by metalto-metal contact without lubricant or gasket. API THREAD Profile is triangular at 60°. Crests and bases are truncated.
27 - 27
Pipes and fittings An LP thread can always replace an NPT thread but it will be dearer.
1.6 PIPES 1.6.1 Purpose They are designed to allow a fluid to flow and have to withstand internal yield pressure, tensile stress, and bursting strength, collapse strength well defined. They may also have to resist to buckling stress. 1.6.2 Characteristics Pipes (tubing, casings etc.) are widely used in the petroleum industry not only for the completion of the well, but also during well testing, to connect manifolds, separators, heaters to make flare line and so on. Then it is important to know the characteristics of the pipes. OD I.D. Nominal size Drift Grade of Material Collapse resistance Internal yield pressure Joint yield strength
28 - 28
Outside diameter (thousands of inch) Internal diameter (thousands of inch) External diameter (in inches) Maximum diameter that you can run into the pipe (thousands of inch) Generally a letter and a number (varies according to the components etc.) PSI PSI in LBS
Pipes and fittings
1.7 FLANGES 1.7.1 Purpose They are used to connect pipe sections or valves, assuring the tightness with ring or flat gasket. They are assembled with bolts. They are characterized by their working pressure (WP) and their nominal diameter. 1.7.2
Characteristics Nominal diameter: diameter of the tube on which the flange is Diameter connected Type WN Welding neck - lap joint SN Screwed neck - blind Ring Gasket Type = R - RX - BX - (see dimensions of manufacturer book Flat Gasket Made of plastic, textile, material etc. the bolts provide the tightening. The ring gasket is utilized especially on H.P. gas circuit for it provides a better tightness.
1.7.3 API Series API St 6 for pressures less than 5000 psi. API St 6 Bx for pressure equal or above 5000 psi. The series are: • API 720 - 960 - 2000 - 3000 - 5000 - 10000 - 15000. The denomination of the series for the API corresponds to the WP This means that the maxi WP for API 2000 will be 2000 psi at 37.8°C. WORKING PRESSURE The following table gives the maximum WP with different temperatures for the principal series used. Temperature MAXI WP IN PSI °F 100 150 200 250 300 350 400
°C 37 66 93 121 149 177 204
API 2000 2000 1964 1928 1892 1856 1820 1784
API 3000 3000 2964 2892 2838 2784 2730 2676
API 5000 5000 4910 4820 4730 4640 4550 4460
29 - 29
Pipes and fittings
TEST PRESSURE The test pressure is given in the following table. API SERIES WORKING PRESSURE 6B 6B 6B 6B 6 BX 6 BX
960 2.000 3.000 5.000 10.000 15.000
960 2.000 3.000 5.000 10.000 15.000
TEST PRESSURE NOMINAL DIAMETER < 14" > 16" 1450 4.000 6.000
3.000 4.500 10000 15000 22500
1.7.4 ASA Series The series are: ASA 150 - 300 - 400 - 600 - 900 - 1500 - 2500 WORKING PRESSURE Working pressure varies in function of temperature and steel used. Except for the serial ISO. the maxi WP is equal to series x 2.4 it is expressed in PSI at a temperature of 850°F for carbon steel and 950°F for carbon molybdenum. The following Table gives the WP for the different ASA series from -20° to 100°F. SERIES MAXI WORKING PRESSURE ASA
150 300 400 600 900 1500 2500
275 720 960 1440 2160 3600 6000
TEST PRESSURE: Is equal to 1.5 times the WP at 100°F to the nearest 25 psi for carbon steel, carbon molybdenum and stainless steel. 2 kinds of gasket can be used with ASA flanges: 1. toric joint 2. flat joint In case of flat joint the maxi WP is obtained by x 2 the series instead of 2.4 for the toric joint. Example: serie 400 at 100°F § Flat joint: 400 x 2 = 800 psi § Toric joint: 400 x 2.4 = 960 psi
30 - 30
Pipes and fittings
1.7.5 • •
Utilization Of Api And Asa Flanges API FLANGES ASA FLANGES
generally on well heads. generally kept for surface installations except for some taps fitting existing only with API flanges. The threaded fittings are defined by API standard.
SUMMARY TABLE Standard
Series psi
API Φ < 14"
2000 3000 5000 2000 3000 5000 150 300 400 600 900 1500 2500
API Φ> 16"
ASA
1.7.6
Maxi WP (100°F) kg/cm² 2000 140.6 3000 210.9 5000 351.5 2000 140.6 3000 210.9 5000 351.5 275 19.3 120 50.6 960 67.5 1440 101.2 2160 151.8 3600 253.1 6000 421.8
bar 137.9 206.8 344.7 137.9 206.8 344.7 18.96 49.65 66.2 99.3 148.9 248.2 413.7
Maxi Test Pressure kg/cm² 4000 281.2 6000 421.8 10000 703.8 3000 210.9 4500 316.3 425 29.9 1100 77.3 1450 101.9 2175 152.9 3250 228.5 5400 379.6 9000 632.7
psi
bar 275.8 413.7 689.5 206.8 310.2 29.3 75.8 100. 150. 224. 392.3 620.5
Tightening Of Flanges Put the joint (1) Ring Joint RJ § Lubricate the ring joint § put the ring joint into the groove of one flange § fit the bolts (2) Flat Gasket RF § fit the bolts of the lower part of flanges § lubricate and put into place the gasket § fit on the rest of bolts. To tighten the flanges (keep the parallelism of the faces of the flanges) § to screw the bolts until the approach of tightening § tighten the bolts in respect f the following order N/2 - 1 § (N is the total number of bolts)
By example : Tightening of 2 flanges with 8 bolts. 8 Tighten 1 bolt then 1 + ( − 1) = (4 ) Tighten the number 4 bolt 2 Then it is without taking into account the number 1 the third bolt after it that we have to tighten.
With the formula we will have: 4+( 7+( 10 + ( 13 + ( 16 + ( 19 + (
8 2 8 2 8 2 8 2 8 2 8 2
− 1) =
(7 )
we tighten the number 7 and so on
− 1) = 10 − 8 = 2 − 1) = 13 − 8 = 5 − 1) = 16 − 8 = 8 − 1 ) = 19 − 16 = 3 − 1 ) = 11 − 16 = 6
So we have the following order: 1-4-7-2-5-8-3-6
31 - 31
Pipes and fittings ASA AND API SERIES FLANGES - VALVES - COUPLINGS WORKING AND TEST PRESSURES PRESSURE kg/cm²
PRESSURE kg/cm²
ASA Series
Test
Working
API Series
Test
Working
150
30
20
300
75
50
400
105
70
600
150
100
2000/4000
280
140
900
230
150
3000/6000
420
210
1500
380
250
5000/10000
700
350
2500
630
420
10000/15000
1050
700
ASA x .17 = WP kg/cm2 API x .07 = WP kg/cm2 W.P x 1.5 = T.P. kg/cm2 W.P x 2 = T.P. kg/cm2 Generally, the materials utilized for surface equipment are defined by ASA STANDARDS and the materials used for well heads are defined by API STANDARDS. For Flanges and valves, the dimensional correspondence is as follows: API 2000/4000 : ASA 600 API 3000/6000 : ASA 900 API 5000/10000 : ASA 1500 API 10000/15000 : ASA 2500 The threaded couplings are defined by API standards.
32 - 32
Pipes and fittings
1.8 NPT FITTINGS FOR OIL AND GAS SERVICE Experience shows that equipment, even manufactured by well-known manufacturers, is often out of tolerances or specifications. This is especially true for NPT fitting. The following recommendations are intended to serve as simple guide-lines and checking procedures to avoid accidents or failures and to comply with API and National Association of Corrosion Engineers standards (NACE MR-01-75 last edition 1978 for H2S). 1.8.1
Use Only Stamped Fittings
Note: Hydraulic fittings not stamped or stamped "1.5 K", "3 K", "5 K", "T5K" etc. are to be used in hydraulic piping exclusively. DO NOT USE THEM FOR OIL SERVICE Most of them are made of free-machining steels that are NOT ACCEPTABLE FOR H2S SERVICE. In addition, their safety factor is generally lower than the standard for oil service. Note: 316 L stamped fittings are suitable for H2S, provided the threads are cut (not rolled) and hardness is < 22 HRC. This is quite difficult even not possible to check in the Field, but consultation of Manufacturer's catalogue may help. 1.8.2 Check Inner Hole Dimensions For 6000 lbs. series A 105 the center hole shall not exceed the following dimensions: Thread 1/4 1/2 3/4 Nominal Center 5.5 mm 6.5 mm 11 mm or or or Hole 7/32" 1/4" 7/16" Larger inside diameters generally indicates "hydraulic" fittings. 1.8.3 Check The Threads NPT threads (especially female threads) must be machined starting from a cone-shaped material or a cylindrical hole drilled with a twist drill, the diameter of which is normalized. Many manufacturers start with larger cylinder-shaped materials from obvious price cut reasons. This practice is detrimental to the efficiency of the seal and the mechanical resistance of the coupling since a few threads only has the normalized shape and is engaged together. Refer to the following sketch. It is therefore essential to check visually the "internals" of female threads and the "original" OD of the male threads. In the range 1/16 to 3/4" there must be at least 7" "good" threads perfectly cut and not "over-flattened". In the above range, the maximum average flat is 5/1000", i.e. 1/10 mm. This is easily recognizable with naked eyes. Check also that the threads are not crushed, bent, broken and do not present traces of galling. Table 1 gives information for easy field checks, which do not require any sophisticated control equipment. 1.8.4 Check The Assembly a) After having fitted Teflon tape (3 layers - not more) on the male thread, hand tightening must be possible over at least 4 threads that is 4 turns after engagement. b) Wrench tightening
33 - 33
Pipes and fittings c) Normal wrench tightening is 3 extra turns after hand tightening; thus a total of 7 turns is needed for the make up. d) Vanish threads that are threads due to chamfer on die must be left outside the female part. Table 1 gives all relevant information. Note: Do not use NPT fittings larger than ½" nominal for 10000 psi service. Make sure also when plugging a npt hole to use plain plugs This is essential for 3/4" threads. A special 4130 3/4" NPT plug has been manufactured and is available under M 819 253. This plain plug is stamped "10000 WP - H2S". This plug must be installed on all apparatus considered in § 5. IN CASE OF LEAKS, bleed pressure to zero, wrench retightens the fitting. Repressurize. If leak does persist, bleed off again pressure to zero. Caution: If retightening is still possible, this indicates permanent deformation of one of te assembling element. Dubious parts must immediately be junked and replaced by new parts. A critical visual check is normally sufficient to detect deformed elements. Remember the old motto "leak before burst"!
34 - 34
Valves
SECTION 4 VALVES
1-1
Valves Valves are external command opening and closing devices, which control the flow of the fluid. They are manufactured according to specifications laid down by API and the ANSI API Standards cover valves used in the well and on the wellhead while ANSI specifications cover valves used in surface installations. There are many different types of valves which are used according to criteria, which dictates their use, e.g. pressure, temperature amount of sealing ability required, gas or oil service etc. 1.
NEEDLE VALVES
2.
GATE VALVES
3.
PLUG VALVES
4.
BALL VALVES
5.
BUTTERFLY
1.1 NEEDLE VALVES
They have a small passage section and are used as block valves for instruments and gauges, as purge valves, throttling small volume of air, gas or fluids, reducing pressure pulsation’s in instrument lines. Because of the small passage section the valves are easily blocked and also can be subject to flow cutting when using abrasive fluids. Needle valves are built to reduce the flow of liquids, but are also very often used as purge valves. They are subject to erosion. Their general characteristics are: • Small passage diameter • Passage direction: the pressure must be exerted on the weakest section of the needle • Compressible seal packing on the control stem. This packing is often composed of tallow braid, Teflon or fiber rubber discs • Small size
2-2
Valves REMARKS Often these valve seats cannot be interchanged so the valves have to be replaced as soon as the seal is insufficient, despite the needle grinding on its seat. The main manufactures are: -
SAPAG
-
OCT
-
KEROTEST
-
ROCKWELL
These valves can be straight or at right-hand angles. Their threaded ends are F x F or F x M. Their working pressures vary from 960 to 10,000 in ¼, 3/8", ½ and 1" dimensions to 3,600 psi in 1¼, 1" and 1 ½ and 2" dimensions.
3-3
Valves
NEEDLE VALVES Diameter: 1/4" - 3/8" - 1/2" Size:
4-4
1/4" - 3/8" - 1/2"
Valves
1.2 GATE VALVES Gate valves are manufactured in a wide variety of temperature and pressure ratings. They are suitable for most on-off non-vibrating hydrocarbon service (vibration may cause the gate to move up and down). They have good torque characteristics but usually require many turns of the hand wheel to open or close them. The type of seal affected by the valve depends on the manufacturer. FMC, MALBRANQUE, VETCO, CAMERON TYPE F) and W.K.M. use a metal to metal seal as the primary seal where as other manufacturers use more complex but no less effective pressurized grease injection systems e.g. McEVOY. They can be used as automatic shutdown valves by reversing the action of the gate and fitting a push-pull actuator, pneumatically or hydraulically controlled. a) McEVOY b) W.K.M. c) FMC d) CAMERON e) VETCO f) MALBRANQUE-SEREG
-
Gate perfectly line up in open position. Full-bore feature minimizes pressure drop, turbulence and reduces erosion.
-
Secondary tightness provided by sealing compound, replaced at each closing position by sealant injection on the gate.
-
Double tightness provided by two independent floating disks.
-
No risk of mechanical jamming by calculated expansion of the shell.
-
Stem tightness by back seat.
-
Stem packing replaceable under line pressure.
-
Stem bearing replaceable under line pressure.
-
Low operating torque provided by: §
Balanced stem depending on (nominal pressure and diameter)
§
Special single ring stem packing
§
Stem needle bearings
§
Seat lubrication
5-5
Valves -
Long life provided by: §
Seat lubrication by automatic sealant injection
§
Body valve filled with grease to prevent oxidation by hydrates and foreign matters.
-
No stress corrosion for internal parts, i.e. there is no mechanical stress for the valve while in opened or closed position. Thus no embrittlement.
-
Single ring stem packing avoiding condensation and electro-chemical corrosion.
-
High security features: §
Bolted bonnet with stainless ring, metal to metal seating
§
Secondary metal to metal sealing at the rear of seats
§
Drop forged bonnet, seats, gate, disks, stem.
-
Special fire safe compound injection enable in case of major emergency or fire.
-
Reversible design - bi-directional sealing capability allows installation of the valve either direction.
6-6
Valves
MODEL B GATE VALVE
7-7
Valves
1.2.1 Gate Valve Model B − Quick clip to fix hand wheel −
High resistance pin (coupling box/stem coupling)
−
Wiper protects stem and bearings against corrosion and moistures
−
Stem bearing with needle bearing takes the load and reduces significantly the torque. Needle bearings are self-lubricated to provide easy operation and long life.
−
Setting screw for bearing cap lock
−
Stem packing is replaceable under pressure when valve is backseated
−
Bleeder screw allows to release the pressure trapped between back seat and packing
−
Stem is surfaced hardened and ground. Smooth considerably reduce friction with packing
−
Special studded bonnet providing excellent security for extreme high pressure
−
Integral stem back seat
−
Double balls body grease fitting for long product life by sealant compound injection
−
Bleeder screw allows to release the pressure of body
−
Stainless steel bonnet gasket autoclave type providing excellent security for extreme high pressure
−
Stainless stem thread is hardened reducing torque
−
Floated stem nut
−
Special seal ring for extreme high pressure
−
Floated seats sealing by integral metal to metal contact no front seal is necessary rear ring seals maintain seats against gate m a perfect contact allowing its self cleaning action
−
Grinded and hardened surfaces of seals and gate provide a long life and decrease torque stainless treatment is provided in standard trim
−
Extended wear plate design guides the gate during its movement improving seating between gate and seals and avoiding penetration of dirt into body space.
−
Reversible design - bi-directional sealing capability allows installation of the valve either direction.
−
Gate perfectly line up in open position. Full-bore feature minimizes pressure drop, turbulence and reduces erosion.
−
Optimal valve design allows maximum medium flow with minimum turbulence.
−
Double tightness provided by two independent floating seats
−
No penetration of dirt into body space
−
No risk of mechanical jamming by calculated expansion of the shell
−
No stress corrosion for internal parts I.E. there is no mechanical stress for the valve while in opened or close position. Thus no embrittlement.
−
Single ring stem packing avoiding condensation and elctro-chemical corrosion.
8-8
Valves −
Low operating torque provided by: • Non rising stem • Special single ring stem packing • Stem needle bearings • Gate and seats with hard faced SS/minimum friction coefficient
−
Long life provided by: • Body valve filled with grease to prevent oxidation by hydrates and foreign matters • Metal to metal seating seat by gate hard faced SS contact.
−
High security features: • Bolted bonnet with stainless ring, metal to metal seating • Secondary metal to metal sealing at the rear side of the seats • Drop forged bonnet, seats, gate, and stem • Stem tightness by back seat • Special solid block gate/seat design for extreme WP
−
Easy assembly and disassembly operations with standard tools • Easy maintenance of wears parts • Stem packing replaceable under line pressure • Stem bearing replaceable under line pressure • Gate and seats without special tool
1.2.2 1.
CAMERON Gate Valve FLEX SEAL
The valve body is composed of two parts, which bolt together, the outside ends having flanged or threaded connections. The seats are metal rings with rubber inserts. The gate and operating stem are one piece and the stem has a left-hand thread cut into it. The stem has a square section, which lines up in the bonnet. Rotating the handwheel causes the gate to rise up and down. 2.
TYPE F
The control and seal assembly is bolted on to the top of the valve body which itself has two flanged end connections for the line pipe. A bonnet cap, containing the needle bearings and a control stem square head on to which the handle fits, is screwed on to the upper flange. Two pins are located in the stem and the rotational movement of the wheel is transmitted through these pins to the stem. These pins are designed to shear if excessive force is used to open or close the valve so that the stem head does not get twisted. The main seal is a flat-toothed metal ring. It can rotate inside the seat body. The gate has a dog at the base of each side. Every time the valve is opened fully, the dog engages one of the teeth on the ring and rotates it slightly. This is to ensure even wear on the seat due to the more severe wear when the valve is in the almost closed position.
9-9
Valves The assembly is lubricated through a plug in the topside of the valve. This energizes the packing and reduces friction between the gate and seat. Another grease nipple is located on the bonnet cap to lubricate the needle bearings. Dismantling (Always make sure the valve is in the open position, and the line pressure bled off). -
Unbolt and remove the top flange and assembly
-
Unscrew the gate then remove the seats
-
Remove the handwheel and remove the retainer bonnet cap
-
Remove the top bearing, the stem to adapter pin and bottom bearing
-
Unscrew the bottom adapter, which compresses the packing against the stem.
Assembling -
Assemble the valve in the reverse order to dismantling.
10 - 10
Valves
CAMERON GATE VALVE • The gate and seat assembly is
• With alternate stem packing,
easily and quickly replaceable
standard gate valves can be rated
without special tools.
for 350° service.
• The one piece gate construction
• The stem pin protects the stem and
helps prevent line sediment from
other internal parts from failure by
entering the body cavity and also
shearing if a high overload torque is
prevents pressure locks when the
accidentally applied to the hand
upstream pressure is reduce to zero.
wheel.
• Two thrust bearings with high-load
• The grease injection port permits
capacity absorb the opening or
lubrication of the gate and seal
closing loads of the gate, reducing
assembly and is used to vent
the turning effort to a minimum.
trapped body pressure after stem
• The threaded packing retainer allows the replacement of the
back seating. • It is not necessary to apply
bearings or the stem pin while the
excessive force when closing the
valve is under pressure by holding
valve. The hand wheel should be
the stem packing inside the stuffing
backed off ¼ turn after the valve is
box.
fully closed.
• The shoulder on the stem can be seated against the bonnet flange to seal off the stuffing box, permitting the replacement of the stem packing while the valve is under pressure.
11 - 11
Valves
CAMERON GATE VALVE
12 - 12
Valves
1.3 PLUG VALVES Manufactured in a wide variety of sizes and pressure ratings. Usually a quarter turns of the stem opens or closes the valve. The seal is either metalto-metal or metal to a softer sealing material (Teflon, Nylon, etc.). A high torque is usually required to open plug valves with a differential pressure across them e.g. 3" HALLIBURTON LO TORC. They are not suitable for throttling applications as the sealing surface is exposed in the slightly open position. a)
AUDCO ROCKWELL PLUG VALVES
b)
HALLIBURTON LO TORC
1.3.1 1.
AUDCO ROCKWELL STANDARD
Comprised of a body with flanged or threaded ends and a top flange. The conical seat is a part of the body. 'The conical plug sits in the body with the cone summit downwards. Lubrication is done by means of grease sticks introduced into a reservoir in the operating stem, the grease travelling through slots in the plug to the sealing face. The seal around the control stem is packing compressed by a gland. 2.
HYPER SEAL
Similar to standard valve but the flange for the plug is on the bottom therefore the cone summit of the plug faces upwards. The control stem seal is a fme well Iubricated thread. Dismantling −
For Standard and Hyper Seal type, unbolt the flange and take out the plug.
Assembling −
With the Hyper Seal type, the plug is pressed down into the seat once the stem has been completely
1.3.2 HALLIBURTON LOW TORQUE The body is made of alloyed AISI 4140 and treated steel. Plug is stainless steel. Seats are100-70steel. A Buna "O" ring sits in a groove on the outside of the seats. This ensures a seal between the valve body and the seat. The plug to seat seal is metal to metal with gas or corrosive fluids; Teflon ones replaces the Buna «O» rings. Other "O' rings and plug stem packing are used to seal the adjusting nut and both ends of the stem. Dismantling −
Unscrew the Allen screws on top and the ball and seats pull out.
Assembling −
The seats and ball can only be replaced when they form a perfect cylinder. The seat "O" rings are susceptible to pinching when the seats are replaced. The bearings should be greased.
13 - 13
Valves
HALLIBURTON LOW TORQUE
1. 2. 3. 4. 5. 6. 7. 8. 9.
14 - 14
Valve body Plug or Core Valve inserts End connections Adjusting nut O-Ring seals Plug seals Lubrication system Valve operation
Valves
1.4 BALL VALVES Available in both floating design and trunnion mounted. The floating design offers good sealing capabilities but a high operating torque. The trunnion design offers a low operating torque but not as good a seal. The soft sealing material on the seat limits the temperature at which the valves can be used; usually the temperature range is 10 - 180°F. Ball Valves are not suitable for throttling applications because in the partially open position the ball seat is exposed to the well fluid.
THE CAMERON BALL VALVE
1.4.1 CAMERON Ball Valve The body is composed of two hemispheres welded together and enclosed within are the seats and the ball. The seats are similar to the gate valve (CAMERON) type F whereby a dog rotates the seats by engaging a set of teeth on the seat. The seats have a Teflon seal. The valve is not designed to be lubricated but if it is to be left on site, replace the lateral plugs with grease nipples and inject grease into the seal cavity. 1.4.2 HARTMANN Ball Valve The seats in the valve have two sealing surfaces, the outside seal being larger than the inside, with the result that the seat is pushed against the ball when the valve is closed. The ball is set in the body with two sets of ball or needle bearings, one on each
15 - 15
Valves stem according to the diameter and pressure, therefore when the valve is closed the seats are not squashed. The plastic seals have a very low coefficient of friction with stainless steel and thus the operation of the valve is smooth. Lubrication: only the bearings are lubricated before assembly. 1.4.3 CIPEG/MAPEGAZ Valve Teflon sealing ¼ turn ball valve, used on LP applications, separators, pumps, tanks etc. (2000 psi working pressure) Common sizes used 2" and 3" on oil lines, gas lines and inlet manifold of separator. Some dump lines are in 1". Body is bolted between two flanges sealed by "O" rings. Relatively easy to dismantle IF NOT TOO CORRODED. Theoretically can be removed from line without dismantling ASA flanges from line. In practice, because of line movement, it is easier to maintain if removed completely from line. Teflon seal easily damaged if the valve is closed on debris. Competitively priced. Valve should always be in left open position during storage.
16 - 16
Valves
CIPEG BALL VALVE
17 - 17
Valves
MAPEGAZ BALL VALVE
18 - 18
Valves
GACHOT BALL VALVE
Low pressure ¼ turn valve used on separators, tanks as sample points, gauge valves, etc. (2000 psi working pressure) Normally 1/2" or 1/4" NPT. Virtually no maintenance possible, i.e. they are simply replaced when leaking.
19 - 19
Valves
BUTTERFLY VALVE
Very low-pressure valve: 100 psi Application: only used on gauge tanks where the only pressure is the head of oil in the tank. Normal size used 3". The seal can be change quite easily, thought the valve has to come out of the line.
20 - 20
Flow control
SECTION 5 FLOW CONTROL
1-1
Flow control
1 CHOKE MANIFOLD 1.1 THE CHOKE A CHOKE is a device used for a number of reasons but principally to control the flow rate Although chokes are often used downhole as safety devices for the purpose of controlling the formation of hydrate, we will focus on the surface choke that is commonly used while testing and during production. During Production the choke is located in the flow line where the fluid leaves the wellhead. During a test a special piece of equipment is used, the CHOKE MANIFOLD, which houses the choke bean itself, and increases the flexibility of the system when many different choke sizes have to be selected over a short period of time. The surface choke is used for the following main reasons: − − − − −
To reduce the pressure and improve the safety To set a certain flowing rate according to the test sequence (testing) or to the selected production flowing rate. To prevent sand entry from the formation limiting the flow rate and hence the speed of the produced fluid leaving the formation) To produce the well and the reservoir at the most efficient rate (production wells) To prevent water and gas coning.
The surface choke is also used to ensure that pressure fluctuations downstream from the wellhead DO NOT AFFECT the performance of the well. To achieve this condition, flow through the choke must be in CRITICAL FLOW. This is obtained when the flow velocity is critical. For dry gas this means that the pressure drop across the choke is sufficient to ensure that the fluid reaches sonic velocity; that velocity will be maintained within very close limits and hence the volumetric flow rate through the choke will not change with a drop of the downstream pressure. For multi-phase fluids the physical interpretation of the critical flow is much more complex, however the principle is the same. As a rule a thumb the critical flow condition is reached when the upstream pressure is approximately twice the downstream pressure. The concept of critical flow is a basic one in well testing: flowing through the test equipment must always be performed under critical flow conditions, basically to ensure that any variation of the pressure downstream the choke (below the maximum value admitted to insure critical flow conditions) due either to a variation of the flowing path (switching of valves, flowing to the gauge tank, etc.) or a change of the separator pressure, will not affect the flowing rate. There are two main types of chokes: a) Positive or fixed choke b) Adjustable choke.
2-2
Flow control
1.1.1 Positive Choke Consists of a bean with a calibrated orifice of known diameter. This is screwed into a choke box. Care must be taken that a good seal is made when inserting the bean. All chokes are made of special heat-treated steel to ensure long-life. In some instances, however, chokes with ceramic linings are used to make them even more resistant to wear e.g. on gas wells with appreciable sand production and hydrate formation limitation.
3-3
Flow control
4-4
Flow control Choke Bean Conversion Chart
NOTE: Choke beans can be supplied in various styles for different services (e.g. alloy steel for normal use and tungsten carbide or ceramic construction for severe or erosive service). IN 1/64TH INCHES 2/64 4/64 6/64 8/64 10/64 12/64 14/64 16/64 18/64 20/64 22/64 24/64 26/64 28/64 30/64 32/64 34/64 36/64 38/64 40/64 42/64 44/64 46/64 48/64 50/64 52/64 54/64 56/64 58/64 60/64 62/64 64/64 68/64 72/64 76/64 80/64 84/64 88/64 92/64 96/64 104/64 112/64 120/64
EQUIVALENT IN METRIC MM 0.7938 1.5875 2.3812 3.1750 3.9688 4.7625 5.5562 6.3500 7.1438 7.9375 8.7312 9.5250 10.3188 11.1125 11.9063 12.700 13.4937 14.2875 15.0812 15.8750 16.6688 17.4625 18.2562 19.0500 19.8438 20.6375 21.4313 22.2250 23.0188 23.8125 24.6063 25.4000 26.9875 28.5750 30.1625 31.7500 33.3375 34.9250 36.5125 38.1000 41.2750 44.4500 47.6250
EQUIVALENT IN 1/8TH INCHES
1/8"
¼"
3/8"
½"
¾"
1"
1 ½"
5-5
Flow control
1.1.2 Adjustable Choke It can be one of two types.
A.
A.
Willis choke
B.
Thormhill Carver, O.C.T., Cameron Shaffer, Malbranque. WILLIS CHOKE is an adjustable choke with two discs; each with two holes drilled in them.
When both the holes line up, full flow through the choke occurs. When one disc is turned relative to the other, the hole-size gets smaller until the point where the holes do not line up and there is no flow. This decrease in hole-size is calibrated and read off in 64ths of an inch.
B. NEEDLE VALVE types. Made by a variety of manufactures but which is basically the same. It consists of a needle valve with a conical plug seating against a tapered seat.
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ADJUSTABLE CHOKE
7-7
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1.1.3 INDICATOR SLEEVE ADJUSTMENT After any change of packing, bean,bean-"O"ring,stem tip, indicator sleeve must be readjusted. 1) Untighten the lock screw in order to free the indicator sleeve. 2) Unscrew the two setscrews to free up the indicator sleeve. 3) Bring the tip in contact with the bean; do not over tighten. 4) Locate the indicator sleeve so that the "O" of the indicator sleeve is just in the middle of the window. 5) Lock the two setscrews. The thread of the operating stem must be greased periodically by means of the grease injector.
8-8
Flow control
Figure A
9-9
Flow control
1.2 PRINCIPLES OF OPERATION OF A CHOKE MANIFOLD In most cases the oil company representative will know what size of choke he wants the well to flow. Insertion of this size of choke before the flow starts is a major advantage. Clean up of the well will almost always take place through the adjustable choke, beaning up slowly until the desired choke size is reached then switching over to the positive choke. Refer to Fig. A E.g.
Flowing through ½" fixed choke.
Valves A and C are open Valves B and D are closed Operator wants to bean up to ¾" positive choke size. 1.
Set adjustable choke to 32/64'
2.
Open Valve D
3.
Close valve A and open valve B at the same time
4.
Close valve C
5.
Increase choke slowly to 48/64 on adjustable choke
6.
Open needle valve E and bleed pressure from fixed choke side
7.
Open fixed choke side and change choke bean to 48/64' fixed
8.
Close needle valve E, open valve C
9.
Open valve A and close valve B at the same time
10.
Close valve D
11.
Bleed of pressure from adjustable choke side with needle valve F.
When changing chokes, set the adjustable choke at the new choke size and switch the flow to the adjustable one. This should be done by two operators, one to close the valve and the other to open the other valve at the same time. Depressurize the fixed choke side and change the choke. Reverse the flow back to the fixes choke side. Commonly the following devices are connected to the upstream side of the manifold; or on the data header: −
A Bourdon Tube Manometer, for a fast visual indication of the upstream pressure
−
A Dead Weight Tester, to accurately measure the well head pressure
10 - 10
Flow control
−
A Pressure Recorder, to keep track of the well head pressure behavior during the test.
A fourth ½" NPT hole usually has a THERMOWELL installed in it so that a temperature recorder can use. The THERMOWELL is inserted deep into the flow and thus allows more accurate measurement the flowing temperature. Due to more and more parameters to be measured we now always use a data header in front of the choke manifold. Of the downstream holes generally only two are used, to connect a thermowell and a Bourdon manometer. Accurate measuring and recording of the choke downstream pressure is generally not required. Furthermore, during the test the pressure downstream of the choke equals closely the separator pressure, which is monitored on a separate chart at the separator. The two CHOKE BOXES also have ½" NPT connections to allow 'bleeding off of pressure before removal of the WING NUT when it is necessary to change a CHOKE BEAN. These bleeds off are connected upstream the choke bean, and are also used to collect fluid samples. Also, at the very beginning of the test, in case of a liquid cushion not filling the string fully, a hose plunged in a water bucket can be used, to check if a weak blow exists.
11 - 11
Flow control
1.3 SAFETY Choke Manifolds are safety devices. As such they must be maintained and operated by trained and competent personnel. Do not allow anyone that is not competent, to modify or service the Choke Manifold. Choke manifolds are the primary method of reducing wellhead pressure to allowable pressures for downstream equipment. As such trained personnel who are aware of the operation and the consequences of their actions must only use them. The opening and closing of the choke can make large pressure differences to: − Downhole pressure − Wellhead pressure − Separator or surge tank pressure − Burner Pressure As such, good communications must be maintained with operating company personnel to avoid over or under pressuring equipment not directly related to your individual operation. When operating with a needle type adjustable choke, be aware that the choke may vibrate open or closed, always lock the choke stem when you have set the choke size to the required setting. Never use the adjustable choke as a valve. Never flow the well through the manifold when chokes are not installed. Adjustable chokes should only be used for a short duration, as they are prone to erosion and washout. Check frequently for " wash and wear " on the adjustable choke, and suspect that fixed choke beans have been washed out, if gradually higher flow rates are measured. Remove measuring instruments before hammering on the wing unions. Never forget to bleed of the pressure from the choke side that has to be opened for choke changes. Use a sand trap when sand or salt production is expected in gas wells. Firmly anchor the choke manifold to the rig structure or other solid base Small choke sizes, especially on adjustable needle type chokes, may become plugged with well debris. Look for unexplained pressure increases or decreases in flow rate. Rapidly increasing and decreasing the choke size on an adjustable choke may clear some plugs. ("Rocking the choke") When a plug is cleared, be aware of downstream choke pressure and ensure downstream equipment is not over pressured.
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1.4 CHOKE MANIFOLD TECHNICAL DATA Diagram of the Geoservices Choke Manifold Parts.
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1.4.1 5 K Manifold. Item. 1 2 3 4 5 6 7 8 9 10
Qt. 1 1 2 5 1 1 2 1 1 1
Description Inlet Flange 3 1/8" 5000 psi - WECO 602 Female Inlet cross 3 1/8" 5000 psi - 4 way Spacer 3 1/8" 5000 psi Gate valve 3 1/8" 5000 psi model B Adjustable choke 3 1/8" 5000 psi Positive choke 3 1/8" 5000 psi Elbow 3 1/8" 5000 psi Outlets cross 3 1/8" 5000 psi - 4 way. Outlet Flange 3 1/8" 5000 psi - WECO 602 Male Skid + 2 tool boxes + lifting lugs
Size Working Pressure Working Temperature Dimensions
14 - 14
1.4.1.1 Technical Data (5 Kpsi Manifold) Dia. 3.1/8" Upstream Choke 345 bars (5 Kpsi) Downstream Choke 345 bars (5 Kpsi) - 20°C to + 121°C Length Width Height Weight
2.325 mm 1.675 mm 0.790 mm 2080 kg
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1.4.2 10 K Manifold 1
1
Inlet Flange 3 1/16" 10000 psi - WECO 602 Fem.
2
1
Inlet cross 3 1/16" 10000 psi - 4 way
3
2
Spacer 3 1/16" 10000 psi
4
5
Gate valve 3 1/16" 10000 psi model B
5
1
Adjustable choke 3 1/16" 10000 psi
6
1
Positive choke 3 1/16" 10000 psi
7
2
Elbow 3 1/16" 10000 psi
8
1
Outlets cross 3 1/16" 10000 psi - 4 way.
9
1
Outlet Flange 3 1/16" 10000 psi- WECO 602 Male
10
1
Skid + 2 tool boxes + lifting lugs
1.4.2.1 Technical Data (10 Kpsi Manifold) Size Working Pressure
Upstream Choke Downstream Choke
Dia. 3.1/16" 690 bars (10 Kpsi) 690 bars (10 Kpsi) - 20°C to +121 °C
Length Width Height Weight
2.750 mm 1.825 mm 0.835 mm 2630 kg
Working Temperature Dimensions
15 - 15
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1.4.3 Special Features − − − − − − − − − −
One positive choke and one adjustable choke providing a flexible way of adjusting the pressure on the test line Sampling points on choke boxes in line with flow direction Fire safe valve design Seat/gate valve sealing by metal to metal hard faced seating Positive sealing shut off from both sides on each valve Low operating torque provided by non-rising stem and minimum friction coefficient between gates and seats Reduced valve and choke maintenance requirements Extended set of fixed choke beans By pass valve Data header upstream
1.4.4 Connections Data Header
Connection Weco
5 Kpsi manifold 3"Fig. 602 Female 3"Fig. 602 Male
Inlet Outlet
Weco Weco
3" Fig. 602 Female 3"Fig. 602 Male
10 Kpsi manifold 3" Fig. 1502 Female3"Fig. 1502 Male 3" Fig. 1502 Female 3"Fig. 1502 Male
1.4.5 Operation of the Geoservices Choke Manifold - Ensure that the manifold is anchored to the deck/ground and grounded electrically. - In offshore floating configuration, ensure that there is enough chicksan or Coflexip between flow head and manifold to allow for heave/tide compensation. - Always zero the calibration barrel of adjustable choke. - Inspect choke tip for wear. - Make a list of the fixed chokes available. - With pressure upstream, never open the upstream valves against a completely closed adjustable choke. The adjustable choke should always be slightly open to prevent pressure locks. -Never leave gate valves in anything except the completely open or completely closed positions. -When changing chokes, always change between chokes of the same size, and then use the adjustable choke to in- or decrease the choke size, slowly. -Rig up sample lines on both choke boxes. -Always use needle valves to mount pressure gauges.
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Flow control
1.5 PRESSURE TESTING Refer to diagram on page 10. Ensure that all unnecessary personnel are kept well away. Mark out area with striped tape. Offshore, arrange public address announcements and obtain a work permit if necessary. 1. Plug the low-pressure outlet of manifold with pressure testing adapter. This adapter should be fitted with a bleed off valve. Rig a pressure gauge and a bleed off needle valve, to the inlet of the manifold. 2. Open all valves, circulate water to fill up manifold. 3. Close valves V1, V2 and V5. 4. Ensure that a fixed choke is in place. 5. Open adjustable choke, ensure that valves V3 and V4 are open. 6. Apply pressure at inlet of manifold with a small volume high-pressure pump such as a Texsteam. Do not exceed maximum working pressure of the manifold. 7. Hold pressure for 5 minutes. Check for leaks. If all air has been evacuated, there should be no appreciable drop in pressure. If leaks are detected bleed off all pressure before attempting any remedial measures. 8. Bleed off pressure. Open valves V1 and V2, close valves V3 and V4. 9. Apply pressure to inlet side of manifold. Do not exceed the maximum working pressure of the manifold. Ensure bleed valve on testing sub, which is mounted on outlet side of manifold, is open. 10. Hold pressure for 5 minutes. Observe for leaks. 11. Bleed off pressure. Close bleed valve on testing sub. Open valves V3 and V4 and V5. 12. Apply pressure to the inlet for a body test. 13. Hold pressure for 5 minutes. Observe for leaks. 14. Bleed off pressure and rig down testing sub.
1.5.1 Pressure testing layout INLET
V1
V2
V5
V3
V4 OUTLET
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1.6 CHOKE PERFORMANCE RELATIONSHIPS It is important to understand the pressure versus flow rate performance of the choke at critical flow rates. Good correlations for single-phase flow of either gas or liquid through a choke are available but they are not applicable to the multi-phase flow situation we normally encounter in our wells. The performance correlation’s for multi-phase flow through chokes are derived empirically and apply only at critical flow rates. The theoretical equation describing the relationship between upstream pressures, gas or liquid ratios, bean size, and flow rates at critical velocities in field units is as follows: Pwhf =
600 R 5 q S2
where : R q S Pwhf
= = = =
GLR flow rate choke size WHP, well flowing
Mcf/bbl BOPD 64th of an inch psia
From the nature of this equation, we see that for a given orifice size ad GLR, the well head pressure plots as a straight-line function of the flow rate q. A typical plot is shown here. Note that as the orifice size increases or the GLR decreases, the line shifts downward.
Gilbert while checking for choke erosion in a field in California, further refined the theoretical formula to yield more accurate pressure rmeasurements: 435R 0.546 q Pwhf = S 1.89
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1.7 DATA HEADERS The data header is an assembly used for sampling of well bore production parameters. It is usually mounted in the production flow path upstream of the surface choke manifold. The data header is designed with ports to provide access for measuring certain parameters of flow as it leaves the well head. The access ports may be used for temperature probes, pressure gauges, chemical injection, sand probes, als sensors, dead weight tester, Foxboro. An illustration of a data header appears below.
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1.8 CHRISTMAS TREE FLOW CONTROL HEAD The surface test tree is installed on top of the tubing and consists of an assembly of valves designed to allow control of the well. Most surface test trees used today consist of four valves fitted to a cross of 4 ways flow fitting, a hydraulic actuator (or pneumatic) and a heavy-duty swivel. The master valve, swab valve and kill valve are all direct action valves, whereas the flow line valve where fitted with an actuator is reverse action. An actuator is usually fitted to the flow line valve so that it may be shut in quickly in an emergency. The kill valve side is tied into the Halliburton, Dowell or mud pumps to allow The well to be killed by pumping downs the tubing. The swab valve is used when a wire line operation has to be conducted. It allows you to insert and remove wire line tools from the while it is flowing or shut in at the choke manifold. The swivel is incorporated so that the tubing string may be rotated to set a packer, open a reversed circulating sub etc. Some swivels can turn with the full tubing weight on them; others can only turn where the tubing weight is taken on the slips. The hydraulic safety valve is a valve, which opens when pressure is applied to the actuator. This pressure is normally in the region of 2000 - 3000 PSI. If a condition occurs which necessitates shutting the well quickly, such as a downstream pressure line rupture, the pressure is bled off the actuator and the valve closes. A pilot system can also be introduced on to the hydraulic pneumatic) actuator whereas a well can be shut in during an emergency from a safe, area e.g. Helideck, separator unit etc.
20 - 20
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21 - 21
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1.8.1 SAFETY Flow heads are safety devices. As such they must be maintained and operated by trained and competent personnel. Do not allow any unauthorized people to modify or service the flow head. Operation of the flow head often requires personnel to perform acrobatic maneuvers far above the rig floor. This need not be dangerous if certain guidelines are implemented and followed. When being lifted up to the flow head by "tugger", make sure that the winch has been certified for man lifting. Wear a proper sit harness. Make sure that the winch operator is competent and understands your commands. Do not indulge in any horseplay or make unnecessary swinging maneuvers that can lead to accidents. Flow heads are heavy, and the transport and installation onto the rig floor can be hazardous. Use corrects lifting slings and shackles. Attach the slings to the proper lifting eyes. When lifting the flow head do not stand under it. If the flow head is being lifted up the veedoor, do not stand on the catwalk. Do not stand in a place where you might be trapped if the flow head swings your way. Be aware of safety hazards for yourself and others. When servicing the flow head, and especially the hydraulic/pneumatic actuators, be aware that there are strong springs contained in them. Use only the correct tools, and above all do not attempt to service the flow head without prior training.
1.8.2 Equipment Safety The flow head must be of sufficient capacity to withstand the maximum expected wellhead SHUTIN pressure. The operation of the flow head requires hydraulic and pneumatic lines: make sure that they are arranged as neatly as possible, Do not allow them to crowd the rig floor where they could become damaged or cause an accident. Mark them clearly and make them visible when lines cross access points. When opening manually operated valves, always open them slowly. Be aware of the amount of turns required to fully open and shut the valve. Count the turns as you open and shut valves; this will give an indication as to whether there is something caught across the valve body or if the valve has a failure. Difficulty in opening valves is often due to pressure locking; equalize pressures across valves if possible, or bleed off internal valve pressure with the proper tool. Do not use cheater bars. Do not jam valves in the closed position; the valves on the FIowhead seal when closed and backed off 1/4 turns. When installing the flow head, always ensure a stick-up above the rig floor adequate to compensate for the tide and for vessel heave. Have enough Coflexip hose available for the same reason. Check operation of automatic actuator prior to job. The automatic valve should close smoothly and quickly when the control pressure is bled off.
22 - 22
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1.9 Flowhead details 1.9.1 Technical Data (5K psi) Nominal size Working pressure Drift Working temperature Dimensions
Maximum pull
Dia. 3.1/8" 345 bars (5000 psi) 79,3 mm - 29 Deg C to 121 Deg C Height - lying down Length - stand-alone. Width Weight Atmospheric pressure Under 345 bars 5000 psi
1.185 mm 2.935 mm 1.240 mm 1820 kg 136000 kg 118000kg
1.9.2 Technical Data (10 K psi) Nominal size Working pressure Drift Working temperature
Dia. 3.1/16" 690 bars (10000 psi) 77,8 mm 29°C to 121 Deg C
Dimensions
Height- lying down Length - stand alone Width Weight Atmospheric pressure Under 690 bars 10000 psi)
Maximum pull
1.095 mm 3.870 mm 1.240 mm 2230 kg 222000 kg 136000 kg
1.9.3 Special Features − − − − − − −
Fire safe valve design Seat / gate sealing by metal to metal hard faced seating Low operating torque provided by non-rising stem and minimum friction between gate and seats Rotation locking device above and below the swivel Fast response hydraulic fail safe shutdown actuator on flow valve Reduced valve and swivel maintenance requirements Weco connections to choke and kill lines
coefficient
23 - 23
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1.9.4 Connections 1.9.4.1 10 K Flowhead To Lifting Sub To Kill Line To Flow Line To Test string
Weco Weco
6 1/2" - 4 ACME - 10 K Flowhead 3" 1502 Female 3" fig. 1502 Male 6 1/2"ACME 3 ½ IF
1.9.4.2 5K Flowhead To Lifting Sub To Kill Line To Flow Line To Test string
24 - 24
Weco Weco
4 1/2" - 4 ACME - 10 K Flowhead 3" 602 Female 3" fig. 602 Male 4 1/2"ACME 3 ½ IF
Flow control
1.10 SAFETY VALVE ACTUATORS 1.10.1
General
The Surface Safety Valve (SSV) Actuator is designed to be installed on a reverse-acting gate valve remote control pressure is applied to the actuator cylinder to hold the SSV in the "down-open" position Emergency shut down (E.S.D.) pilots, when sensing line pressure fluctuations, exhaust the actuator cylinder pressure. The line pressure working against the actuator stem area along with spring compression moves the valve gate to the "up-closed' position. The SSV actuator is equipped with a spring that is loaded with sufficient compression for the SSV to be considered normally closed.
1.10.2
Design Principle
The SSV and actuator are designed to be used as a lower master valve, wing valve, or at certain intervals. a pipeline. The SSV has a visual indication as to position. In the "up-closed" position, the actuator extends ¼" plus the stroke dimension above the top of the cylinder. In the "down-open" position, that actuator stem extends ¼" above the top of the actuator cylinder. After the SSV is installed in a flow line, pipeline or well head, control pressure from the control system applied to the actuator cylinder above the piston. When enough pressure is applied to the actuator cylinder to overcome line pressure friction and spring force, the piston, stem, and gate move down to open the gate valve. The SSV may be maintained in a "down-pen" position by control pressure, by being locked open with the locking cap or fusible locking cap made up at the top of the cylinder, or by the use of a jack assembly (The fusible locking cap and the opening jack assembly are available accessories.)
GATE VALVE WITH HYDRAULIC ACTUATOR
25 - 25
Flow control
1.11 Installation of the Geoservices Flowhead. Before installation of the Flowhead perform routine maintenance according to the procedures laid down in the maintenance manual. Pressure test the Flowhead according to the pressure test procedure laid down in this manual. Install thread protectors or caps on all inlets and outlet lines. Lift Flowhead out of basket and place on catwalk below veedoor. Fit the necessary pup joint onto Flowhead. Make up as tight as possible with chain tongs. If Coflexip hoses are being used they can be, at your discretion or according to rig procedures, connected to the Flowhead while the flow head is on the Catwalk. If Coflexip are made up to the flowhead, on the Catwalk, full attention must be given to adequate support and correct lifting procedures, when lifting the Flowhead onto the rig floor. If chicksans are to be used, ensure that they are supported by tugger lines throughout job. Do not have weight of flowline "hanging"on chicksan elbow. Lift the Flowhead onto the rig floor by using the lifting eyes provided on the flowhead. Do NOT lift the Flowhead by wrapping slings around the Kill and Flow lines, as this will place undue strain on the flanged connections. They were not designed for this purpose. As soon as is feasible, install the rig elevators on top of the Flowhead Fit the pneumatic line to the actuator, ensuring that the hose is supported, and not placing a strain on the connector. Pressure up actuator and remove transportation cap from actuator. Fit bleed off valve on top cap. (This should not be left in place during transportation) Fit hand wheels, ensuring that the locking pins are in place. Lift the flowhead and lower pup joint into mouse hole. Torque up all ACME connections to 4000 Ft-lbs minimum. Torque up pup joint according to pipe connection. Lift flowhead and install onto clients tubing. Torque up connection accordingly. Ensure that swivel is operating correctly when turning tubing. Ensure that no Flowhead connections are backing off as tubing joint is tightened. If lock subs on ACME threads have been installed, this should be impossible. Pneumatically open flow line valves and verify closure time. Operate all panic buttons, ensuring each time that the actuated flowline valve closes. With no pressure in flow line this should be of the order of 8 - 10 seconds. Verify position of all valves in preparation for pressure test. On floating rigs ensure that flowhead stick up is sufficient for expected heave and tide. Three to four meters above rig floor is normal. Operation of the valves in this case will mean the use of the riding belt. Ensure that the air tugger being used is certified for man riding. (I.e. it is not used for any other purpose.). Ensure the tugger operator can see you at all times. Ask one of the Geoservices crew to ensure that the tugger operator is not distracted at any time during the operation. If the heave is bad, rig up a heave compensated tugger line. Be very careful not to trap your feet/hands in the nooks and crannies of the flow head while manoeuvring. On fixed/land rigs, stick up should be just sufficient to make valve operations simple.
26 - 26
Flow control
1.12 Operation of the Geoservices Flowhead Never pressure the equipment beyond its pressure rating, even during pressure tests on well site. When operating the valves, count the number of turns. Never leave a gate valve in a midway position. Always back off 1/4 turn when the valve is completely open or closed. Tightening the valve handle in no way assists sealing, on the contrary it is likely to damage the valve stem. If the valve handle is hard to turn, do not force it; check that there is no trapped pressure in the body by use of the bleeder screws. It should not be necessary to use a pipe wrench. Once the well pressure is applied to the flowhead, ensure that the pneumatic pressure to the flow line shut down valve is sufficient to maintain the valve open.
− − − − − − − −
V1 V2 V3 V4 V5 V6 V7 V8
The Master Valve The Swab Valve The Kill Line Valve The Flow Line Valve Needle valve for top pressure test adapter Needle valve for Kill line pressure test adapter Needle valve for Flow line pressure test adapter Needle valve for bottom pressure test adapter
1.13 ESD Panel and Hi- Lo pilots. 1.13.1
Function
The system is designed as a surveillance/operating system that actions a pneumatic actuator/gate valve. The gate valve is a reverse action type. If the air pressure goes off the spring in the pneumatic actuator will bring the piston back to it's rest position and moves the valve gate to it's closed position. It is a fail-safe system; failure of air supply will close the gate valve
1.13.2 1. 2. 3. 4.
Preparation and arming Adjust the regulators 1 and 3 to the zero position. Close the valve 9 Adjust the regulator 2 to the required pressure. Adjust the regulator 3 to 2,5 bars pressure. 27 - 27
Flow control
5. Manually engage the master pilot 10 and secure it with the block pin. 6. Open slowly the valve 9. Once the surveying press is acting on the high/low sensors the pneumatic pressure of 2,5 bar will start acting on the piston of the master pilot 10, the block pin will disengage automatically and the system is operational.
1.13.3
Hi - Lo sensors description
The system shuts down, gate valve closes if: − The surveyed press. is higher than the preset press. on the Hi sensor. − Or the surveyed press. drops below the preset press. on the Lo sensor. This will cut the command press. of 2,5 bars to the master pilot. The equalized press. that was acting on the piston of the master pilot is disturbed. The master pilot valve will be pushed by a spring to it rest position and open a bypass the press. from the actuator will be bled off. The gate valve will close. The accidentally opening of the gate valve is not possible without first executing the described preparation and arming procedure
1.13.4
Panel
All instruments as showed in the table below are mounted in a panel with the following dimensions; 600 x 520 x 230 mm
1
Regulator from air supply Pressure gauge, indicates 10 bars press. on actuator Regulator to master pilot Pressure gauge, should indicate 2,5 bars Hi press. sensor
2
3 4 5
28 - 28
6
Lo press. sensor
7
Manifold
8
Plug to port for calibration purposes Valve to surveying press. Master pilot
9 10
Flow control
29 - 29
Pressure and temperature
SECTION 6 PRESSURE AND TEMPERATURE MEASUREMENTS: BOURDON TUBE GAUGES (INCLUDING FOXBORO)
1-1
Pressure and temperature
1.1 PHYSICS AND BEHAVIOUR OF FLUIDS 1.1.1 Pressure The force exerted over a unit area (e.g., pascals, pounds per square inch).
Pr essure =
Force Surface Area
There are relative and absolute pressure scales: Relative “gauge” Pressure above atmospheric pressure
Relative “vacuum” Pressure below atmospheric pressure
Absolute Pressure above perfect vacuum
The relative scales arose because many pressure-measuring instruments actually measure the pressure difference between the system of interest and the atmosphere. The complication is that atmospheric pressure varies. The formula that identifies the different pressures is: P=Pg+Po P=absolute pressure, Pg=gauge pressure, Po=atmospheric pressure. Atmospheric Pressure The pressure exerted by the atmosphere A barometer is used to record it and the average Atmospheric Pressure at sea level is: 1 Atm or
= 14.7 psi =
29.92 In. Hg = 760 mm. HG
2- 2
1.033 Kg/cm2 =
1.014 bar
=
=
1.14 bar
101357 pascals
Pressure and temperature Gauge Pressure The gauge pressure is the difference between the system and the atmospheric pressure. Pressure is registered in Lbs per Sq. Inches (Lbs/inch2) or psig and in Kg/cm2 In small pressure system Inches of Water are used where 1 psig or
= 27.7 Inches of water
1Kg/cm²
= 10 m of water.
Vacuum Pressure Vacuum pressure is measured relative to ambient atmospheric pressure (pressure less than the atmospheric pressure). It is referred to as pounds per square inch (vacuum) or psiv Absolute Pressure This is the sum of both the Atmospheric and Gauge Pressures. The unit commonly used is the psia. Absolute pressure is used in the calculations of all gas Laws. Some calculations: Given 100 psig in a pressure system, Atmospheric Pressure being 14.7 psi, then Absolute Pressure will be: 100 psig + 14.7 psi
=
114.7 psia
If a system is under vacuum, that is, the pressure is less than Atmospheric Pressure. Say the Vacuum is 2 psiv, then Absolute Pressure will be: 14.7 psi – 2 psiv
=
12.7 psia
Note : It is more common, and more accurate, however, to express the Vacuum in Inches of Mercury (or mm of Hg in metric system). Hence, 14.7 psi Atmospheric Pressure at sea level will be equal to 29.92 Inches Hg. Thus: 2 Inches of Hg
=
1 Pound per Square Inch (approximately)
Other Terms of Pressure It is important to understand the relationship between pressure and head. Head is the pressure exerted by a column of fluid. To relate pressure and head, you must know the height of a column of fluid, the fluid’s density, and the gravitational acceleration: Pressure expressed in terms of height is called head.
3-3
Pressure and temperature Understanding the relationship between pressure and head is important not only in calculating the pressure exerted by a column of fluid, but also in analyzing pump and compressor performance. Consider the force (or weight) exerted by this column of fluid:
F = ma = mg P0
A
m = V? = Ah? F = Ah?g
Density ?
h
P
Now apply the definition of pressure:
FFluid =
F Ahρg = = hρ g A A
The pressure at the bottom of the column is the sum of the pressure at the top of the fluid and the pressure exerted by the fluid:
P = P0 + PFluid = P0 + hρg Head is measured in feet of water and is primarily used in the transmission of Fluids. Each Foot of Head Each psig of Pressure
= 0.43 psig = 2.3 Feet Head of Water
Various Pressure Equivalents Lbs/Sq.In.
1 14.7 .036 .49
4- 4
Inches of water at 40°F (4.4°C) 27.6 406.8 1 13.6
Inches of Hg
Feet Head
Bar
2.03 29.30 .07 1
2.3 33.8 .082 1.127
0.069 1.014 0.0025 0.0346
Pressure and temperature
1.1.2
Temperature Temperature (symbolized T) is an expression of heat energy. In thermodynamics the temperature is a measure of the kinetic energy in molecules or atoms of a substance. The greater this energy, the faster the particles are moving, and the higher the reading an instrument will render.
1.1.2.1 Principle temperature scales Relative Fahrenheit Scale (°F) Pure water at one atmosphere (the average sea-level pressure) freezes at +32 degrees Fahrenheit (F); pure water at one atmosphere boils at +212 degrees F. Absolute zero is -459.67 degrees F. One Fahrenheit degree increment is 5/9 (0.55555) times the size of a Kelvin or centigrade degree. Celsius Scale (°C) In the centigrade or Celsius temperature scale, the freezing point of pure water at one atmosphere is assigned the value zero; the boiling point is +100 C. Onedegree increments in the centigrade scale are the same size as those in the Kelvin scale. Absolute Rankine Scale (°R) The degree increments in this temperature scheme are the same size as those of the Fahrenheit scale, but 0 R corresponds to absolute zero or 0 K. Degrees Rankine can be obtained from degrees Kelvin by multiplying the Kelvin temperature by 1.8. Degrees Fahrenheit are obtained from Rankine readings by subtracting 459.67 Kelvin Scale (°K) One kelvin is formally defined as 1/273.16 (3.6609 x 10-3) of the thermodynamic temperature of the triple point of pure water (H2O). A temperature of 0 K represents absolute zero, the absence of all heat. Conversions To convert from one Scale to another the following equations are used:
9 °C + 32 5 5 °C = (° F − 32 ) 9 ° R = ° F + 459 . 69 ° K = °C + 273 . 15 °F =
5-5
Pressure and temperature
Comparison of temperatures scales Boiling point of water è
212°
672°
100°
373°
Melting point of ice
è
32°
492°
0°
273°
Absolute zero of temperature
è
460°
0°
273°
0°
fahrenheit
rankine
Centigrade
Kelvin
Types of Thermometers The most common type of thermometer is the mercury type, which involves the expansion and contraction of a column of mercury. −
Range of the mercury thermometer is from -39°F to 600° F.
−
If the tube above mercury level is filled with Nitrogen under pressure, then the Thermometer may be used up to 1000°F.
−
For below -39°F, Alcohol may be used.
1.1.2.2 Keywords Critical Temperature The critical temperature is the temperature above which it is no longer possible to liquefy the substance in question by increasing the pressure. Bubble Point Is the temperature where the gas begins to escape from a liquid mixture at a fixed pressure. Dew Point The dew point is the temperature to which the air must be cooled at constant pressure in order for it become saturated, i.e., the relative humidity becomes 100%. Gas Dew point is very important in connection with Hydrates Formation. Critical Point Is the temperature where the liquid and the gaseous phases of the hydrocarbons are indentical and can coexist. Note: T and P may be said to work in similar directions. Lowering the T of a gas, may have the same end result as lowering P. Increasing the T may have the same effects as increasing gas P.
6- 6
Pressure and temperature
1.1.3
VOLUME Gas and liquid Hydrocarbons occupy a certain space. the space of the container they are enclosed in is their volume. For measuring purposes, a standard Cubic Foot is used by the gas industry: under atmospheric pressure (14.7 psi) and at 60°F temperature.
Molar Volume The molar volume is the volume occupied by one mole of ideal gas at STP. Its value is: 22.414 L mol -1 379 Cubic Feet mol -1 To calculate the moles of a certain gas at STP the formula is:
Volume = Mole MolarVolume Some calculations: Consider a volume of 2500 Cu.ft of Propane at STP. This Volume in moles is:
2500 = 6. 6moles 379
Critical Values of some natural gas constituents
Gas
Methane Ethane Propane Butane Nitrogen Carbon dioxide Hydrogen Hydrogen sulfide Dry Air
Critical pressure p.s.i.a.
673 717 617 551 492 1071 188 1306 547
Critical Temperature °F
-116.5 90.0 204.0 306.0 -233.0 88.0 -400.0 213.0 -221.0
Critical Volume ft3/lb mol
1.59 2.29 3.12 4.14 1.44 1.53 1.04 1.33
7-7
Pressure and temperature
1.1.4
WEIGHT The quality of being heavy; that property of bodies by which they tend toward the centre of the earth; the effect of gravitational force, especially when expressed in certain units or standards, as pounds, grams, etc. Weight differs from gravity in being the effect of gravity, or the downward pressure of a body under the influence of gravity; hence, it constitutes a measure of the force of gravity, and being the resultant of all the forces exerted by gravity upon the different particles of the body, it is proportional to the quantity of matter in the body. The terms atomic weight, molecular weight are all related to weight of the substance. The molecular weight is the weight of one mole of the molecules, and the atomic weight is the weight of one mole of the atoms
The Atomic Weight The quantity of an element whose weight in grams is numerically equal to the atomic weight of the element is called Atomic Weight. Example: Atomic Weight of Sulphur is : Atomic Weight of Carbon is : Atomic Weight of Oxygen is : Atomic Weight of Hydrogen is :
32 12 16 1
Atomic weight is measured in units of atomic mass units (amu) when referring to single atoms, or in grams/mole when referring to moles of an element. The atomic weight of an element is equal to the number of protons plus the number of neutrons. Molecular Weight The molecular weight of a compound is the sum of the atomic weights of the atoms in the molecules that form these compounds. Molecular weight (also called "molar mass" or "gram formula mass") is measured in units of grams/mole when referring to moles of an element. The molecular weight of a compound is found by adding the atomic weights of all of the atoms in the element. Example
Molecular Weight of Methane CH4 is 12 + (4 x 1) = 16
Example
Molecular weight of a gas mixture.
Gas Methane Ethane Propane Isobutane N-butane
Vol.% CH4 C2H6 C3H8 C4H10 C4H10
Mol.%
50.0 25.0 10.0 5.0 10.0
50.0 25.0 10.0 5.0 10.0
100.0
100.0
Mol.Weight 12+(1+4) (12x2)+(1x6) (12x3)+(1x8) (12x4)+10 (12x4)+10
= 16 = 30 = 44 = 58 = 58
Average mol.Weight 16 x 0.5 30 x 0.25 44 x 0.1 58 x 0.05 53 x 0.1
= 8.0 = 7.5 = 4.4 = 2.9 = 5.8
28.6
Average molecular weight = 28.6 Lbs which is the weight of 379 cuft of the gas mixture.
8- 8
Pressure and temperature
1.1.5
DENSITY, SPECIFIC GRAVITY, API GRAVITY
1.1.5.1 Density Density is a measure of how much mass is contained in a given unit volume (density = mass/volume). Density is expressed in kg/m3, Lbs per Ft3 or Lbs per Gallon.
Density =
Mass of the substance Volume
Some relative densities Water Air
= =
1000 g/litre or 62.4 Lbs/cuft 1.293 g/l or 0.076 Lbs/cuft
Some calculations: If the density of air is 0.076 Lbs/cuft, what volume will 6 Lbs of air occupy?
V =
M 6 = = 78.95 ft 3 d 0.076
Some calculations: What is the density of Methane at 60°F and 14.7 psia if its molecular weight is 16? It is known that a gas with a molecular weight 16 at standard conditions is occupying a volume of 379 cuft. Therefore:
d=
M 16 = = 0.04 Lbs/ft 3 V 379
Note: Density should never be confused with or used as the specific gravity of a substance.
9-9
Pressure and temperature
1.1.5.2 Specific Gravity Specific Gravity is the ratio of the density of the substance to a. Density of water (for solids & liquids) b. Density of air (for gases) Specific gravity is not expressed in units, as it is purely a ratio. Find the specific gravity of methane if the density of air is 0.076 Lb/cuft under similar conditions.
d of CH4 0. 04 Lb / ft 3 SG = = = 0. 55 d of air 0. 076 Lb / ft 3 The SG of natural gas varies according to its constituents. When the gas composition is known the SG of the mixture can be easily found. Some calculations: A gas flows into the pipeline with a composition of 75% methane, 22% ethane and 3% nitrogen. What is its SG? SG of mixture = (0.55 x 0.75)+(1.05 x 0.22)+(0.971 x 0.03) = 0.672 Densities and SG of Natural Gas Constituents
Gas
Density lb/ft3 60°F : 14.7 psia
Specific gravity Air = 0.076 Lb/ft3 60°F : 14.7 psia
Methane
CH4
0.042
0.553
Ethane Propane N-butane Carbon dioxide Nitrogen Oxygen Hydrogen sulphide
C2H6 C3H8 C4H10 CO2 N2 O2 H2S
0.079 0.116 0.153 0.116 0.073 0.084 0.089
1.039 1.526 2.013 1.526 0.960 1.105 1.171
0.076
1.000
Air (dry)
10- 10
Pressure and temperature
1.1.5.3 API Gravity The American Petroleum Institute (A.P.I.) scale of Specific Gravity is used in the Oil and Gas Industry to classify the spoecifc weight of crude oil at a base temperature of 60° F. The API gravity is found by using the formula:
°API gravity =
141.5 − 131.5 SG at 60°F
As the specific gravity increases the °API gravity decreases. In this system fresh water has been arbitrarily designated as having an °API Gravity of 10. −
If the liquid is less dense than water, °API > 10.
−
If the liquid is denser than water, °API < 10.
Typical Oil API Gravities:
1.1.6
−
Heavy oil40 °API
−
Condensates
~40 - 60 °API
VISCOSITY Viscosity is a measure of a fluid's resistance to flow. It describes the internal friction of a moving fluid. A fluid with large viscosity resists motion because its molecular makeup gives it a lot of internal friction. A fluid with low viscosity flows easily because its molecular makeup results in very little friction when it is in motion. With increase of T: a)
Gas Viscosity increases
b)
Liquid Viscosity decreases
The Viscosity of gases does not vary significantly with changes of pressure. The unit of kinematic viscosity is the stoke, expressed in square centimeters per second. The more customary unit is the centistoke (cSt) — one one-hundredth of a stoke. Kinematic Viscosity 1 centiStoke (cSt) = 10-2 Stoke (St) = 1 millimetre squared per second (mm2/s). Dynamic (absolute) Viscosity 1 milliPascal second (mPa.s) = 10-3 Pascal second (Pa.s) = 10-2 Poise (P) = 1 centipoise (cP). One (1) cP is the Viscosity of water at 68.4°F. Relationships Dynamic Viscosity = Kinematic Viscosity x Density (at the same temperature) or cP = cSt x fluid density
11 - 11
Pressure and temperature Change in Viscosity and Gravity of Crude Oil due to dissolved gas Viscosity - Centipoise
Gravity - °API
4.5
57
4.0
54 Viscosity
E D
3.5 3.0 2.5 2.0 1.5
51 48 45 42 39
Gravity
1.0
36
.5
33
0
30 100
200
300
400
500
DISSOLVED GAS - CU.ft per BBL
1.1.7 HEAT The form of energy that flows between two samples of matter due to their difference in temperature. Usually denoted by 'Q'. The British thermal unit (Btu) is a nonmetric unit of heat, used in the United States and, to a certain extent, the UK. The SI unit is the joule (J), which is used by most other countries. 1 Btu is defined by the amount of heat required to raise the temperature of one pound of water from 63°F to 64°F. It is often used to describe the heat value of fuels and heating and cooling system capacities. 1 Btu is approximately equivalent to: − 252.0 calories, − 778 ft·lb, − 1,055 joules
12- 12
Pressure and temperature
1.2 HYDROSTATIC PRESSURE Hydrostatic pressure is the pressure due to the unit weight and vertical height of a static column of fluid. The diameter and the shape of the fluid column have no effect.
Hydrostatic pressure calculation in metric units:
Ph = (Ld ) / 10 where: Ph = hydrostatic pressure (kg/cm2) d = mud weight (g/cc) L = vertical depth (meters) Hydrostatic pressure in API units:
Ph = 0.0519dL where: Ph = hydrostatic pressure (psi) d = mud weight (ppg, pounds per gallon) L = vertical depth (feet) The number 0.0519 is a conversion factor used to obtain pressure in oil industry imperial units, as follows: 1.
There are 7.48 gallons in 1.0 ft3, and 144 inches2 in 1.0 ft2
2.
Mud weight in ppg x 7.48 gal/ft3 x 1/144 ft2/in2 = psi/ft
3.
Thus, 7.48/144 = 0.0519 (psi/ft/lb/gal)
Hydrostatic pressure having different density units: −
When the density is expressed in API gravity the formula of the pressure gradient becomes:
1squarefoot lb psi = × cubicfoot 144squareinches foot
13 - 13
Pressure and temperature
Ph =
d × feet = psi 144
Where d = pounds per cubic foot −
When the density is expressed in pounds per cubic foot the formula of the pressure gradient becomes:
0.433 × 141.5 psi = 0 API + 131.5 foot Ph =
0
61.317 × feet = psi API + 131.5
Where °API is the API gravity of the substance Pascal's Law states that the pressure at any point in a static fluid is the same in all directions. The fluid transmits any applied pressure, undiminished by distance, throughout the fluid.
Fluid Column
H
According to Pascal's Law, the hydrostatic pressure ('H') is exerted in all directions at a given depth in the fluid column.
The hydrostatic pressure gradient is the variation of hydrostatic pressure per unit of height. This value describes the pressure development in a liquid, expressed in pressure units per depth (meters or feet):
Kgf/cm2/m or PSI/ft Well site personnel often report the hydrostatic pressure gradient as a volumetric mass (g/cc or ppg), to enable easy comparison of pressure to mud weight. Metric units:
14- 14
Pressure and temperature
HPG =
Ph Pv = L 10
where: = Hydrostatic pressure gradient in kg/cm2/m Ph = Hydrostatic pressure in kgf /cm2 Pv = Volumetric mass in g/cc L = True vertical Depth in meters
HPG
HG =
Ph x 10 = Pv L
where: = Hydrostatic gradient in g/cc
HG
API units:
HPG =
Ph = 0.052 Pv L
where: HPG = Hydrostatic pressure gradient in psi/ft Ph = Hydrostatic pressure in psi Pv = Volumetric mass in ppg L = Depth in feet
HG =
Ph x 19.237 = Pv L
where: HG
= Hydrostatic gradient in ppg
15 - 15
Pressure and temperature
1.2.1
Pressure of a liquid in a well The pressure at a given depth in a static liquid is a result the weight of the liquid acting on a unit area at that depth plus any pressure acting on the surface of the liquid.
P = Patm + Pliquid Some calculations: A container is filled with a liquid and gas under pressure, what is the gauge pressure in psi at the bottom of this container. Gas pressure = 125 psi Density Liquid = 50 lbs/CuFt = 6.68 ppg
Pg = Patm + Pliquid = 125 + (6.68 × 15 × 0.0519) = 130.20 psig Knowing that P=Pg+Po: P=130.20 psig + 14.7 psi = 147.90 psia 1.2.2
Pressure in Vessels containing immiscible Fluids Three Fluids, oil, water and mercury are Oil mixed together in a tube Ho .O Let us find the pressure at the bottom of Water this tube Hw .w SG oil = 0.850 Mercury SG water =1 Hm .m SG mercury =13.6
The Pressure at "0" is
The Pressure at "W" is
The Pressure at "M" is
H 0 × 0.85 × 62.4 144 H W × 1 × 62.4 PW = PO + 144 H × 13.6 × 62.4 PM = PW + M 144 H × 0.85 × 62.4 H W × 1 × 62.4 H M × 13.6 × 62 PM = O + + 144 144 144 PO =
Pressure at the bottom of the tube is equal to the sum of the pressure of each liquid. Some calculations: What is the pressure at the bottom of a well 6000 feet deep which contains 3500 ft of mud of SG = 1.6 and 2500 ft of cement of SG = 1.9?
16- 16
Pressure and temperature
BHP = Pmud + Pcement =
1.2.3
3500 × 1.6 × 62.4 2500 × 1.9 × 62.4 = 4485 psig + 144 144
Communicating Vessels When two vessels are connected together and filled with the same liquid, the free face levels are identical and horizontal, whatever the shape of the vessel. The pressure is the same at all points at the same depth from the surface. Then : PA = PB = PC The "U" Tube
H
The two arms are filled to the same height whatever the position of the tube. Some calculations: Use of "U" tube to measure the pressure of a gas The "U" tube used should be filled with a suitable liquid at the pressure to be measured. SG of alcohol : SG of mercury : (II)
0.700 13.6 (I)
P (to be measured) h/2 h/2
O
Pressure to be measured is applied to one of the arms. The other hand remains free.
H II H
I
Level in arm I descend and rises in arm II.
M
At a point M, the pressure will be: PM =
P=
2- 17
(H II
H II × d H I × d = +P 144 144
− H I )× d 144
Pressure and temperature
Measure gas flow rate Let us consider the following drawing
H
HB
A
The Calibrated orifice in the gas line create a differential pressure according to the flow rate crossing it
M Q
PB
PA
At the point M of the tube we will have P + (H × d ) = P + (H × d A A B B
1.2.4
P − P = d (H − H ) A B B A
Well Holes And Reservoirs A well is a vertical column of height H in communication with the producing reservoir and filled with a fluid of density d. Let us examine some cases.
1.2.4.1 Well shut in at the surface WHP
The pressure at the Bottom Hole is the same everywhere and equal to the static pressure of the reservoir. H
H ×d P = WHP + G 144
WHP = Well Head Pressure P
G
3 - 18
Pressure and temperature
1.2.4.2 Flowing Well If WHP >0, the well will flow when the well head valve is opened When the well flows, the bottom hole pressure drops from PG to the value PF, because of pressure drop necessary to overcome the friction of the fluid in the producing reservoir. We will also have a pressure drop •P in the tubing during production. We can write following equations: H ×d WHP = P − ∆P − F 144 H ×d PF = WHP + ∆P + 144
The well will be flowing as long as P − P 〉 0 or G F
H ×d P − WHP + ∆P + 〉 0 G 144
After a certain period of production, the value of PG will decrease and consequently the value of the flow rate. The density may also increase because of: − − −
Water production increases Less gas in the oil. Production will stop when: H ×d P = G 144
1.2.4.3 Non Flowing Well In such case: H×d P 〉 G 144
Liquid level does not reach the surface
Some calculations: The pressure in the well 7500 ft deep is 2200 PSI and SG of oil is 0.825. Is the well flowing? If not at what depth is the liquid level? Hd Well is flowing if P 〉 G 144 In our case
Hd 7500 × 0.825 × 62.4 = = 2681 psi 144 144
2200psi > 2681psi Well is not flowing
Liquid will rise at a depth of : 2200 =
Hd 144
4- 19
→H =
2200 × 144 = 6154 ft Sg × 62.4
Liquid level is at a depth of: 7500 - 6154 = 1346 ft
Pressure and temperature
1.2.4.4 Maintenance Operations on Wells During workover operations (changing the tubing), the well must be neutralised (killed). This consists of injection into the tubing a fluid with such density that this following condition is obtained. Hd P > G 144
Therefore
P × 144 d = G H
Some calculations: a)
A well 8500 ft deep has a BHP of 5400 PSI and a SG of oil : 0.825. 1. What is the well head pressure? 2. What will be the density of the mud to be used to kill the well? 1)
Well Head Pressure
H ×d 8500 × 0.825 × 62.4 WHP = P − = 5400 − = 5400 − 3039 = 2361 psig G 144 144
2)
Density of Mud
5400 > d=
b)
Hd 144
5400 × 144 = 92 Lbs/CuFt 8500
SG =
92 = 1.47 62.4
During well completion, we replace mud of SG: 1.6 by oil of SG: 0.850. What will be the maximum pressure variation reached at the wellhead? The tubing shoe is set at 7000 ft deep.
mud
The well was full of mud and WHP=0 The pressure at the tubing shoe is :
oil H
P = M
7000 x1.6 x 62.4 = 4853 psi 144
When oil is pumped into the well, the mud is displacing and escaped through the annular. The WHP increases as the pumping continues. When all mud in the tubing has been replaced by oil: P = O
7000 × 0.850 × 62.4 = 5878 psig 144
Therefore WHP is 4853 - 2578 = 2275 psig
5 - 20
Pressure and temperature How to choose range of pressure element - Amerada A well is 11500 feet deep and contains oil of SG =0.820. The WHP is 1400 psi. We would like to run in the hole an Amerada to record the BHP. What Amerada range do you suggest to carry out this operation knowing that 1) The accuracy of the lower and upper 15% range of the gauge is to reliable 2) Normally gauges are in multiple of 1000 psi. *
The bottom hole pressure is BHP = 1400 +
11500 × 0.820 × 62.4 = 1400 + 4086 = 5486 psi 144
To avoid the 15% upper range of the gauge we would therefore choose a pressure element with range: 0 - 7000 psi 1.2.5
Artificial Drives When a well stops being a flowing well, the producing reservoir still contains large quantities of oil. To help to produce those hydrocarbons we use artificial drive methods. 1.
Gas Lift Method
This method consists of mixing gas with the effluent to lower its density. The mixing takes place in the well low enough to reduce as much as possible the weight of the column of oil. Gas is injected in the well through valve fitted in the tubing. Some calculations: In a gas lift well, gas is injected in the well at a pressure of 1200 PSI. After a certain time of gas injection, the effluent density of the well is reduced to 51 Lb/cuft. 1) At what depth should we set the injection valve so that the gas can enter the tubing? 2) What will be the BHP of the well at 5200 feet deep after the installation is fully running? 3) What conclusion can you make knowing that the formation pressure is 1700 PSI?
6- 21
Pressure and temperature Gas + Oil
Gas Injection
h1 h2 H
Injection Valves
1)
When starting the well gas displaces the oil in the tubing. The gas will start to enter the tubing when the Hydrostatic Pressure of the column is overcome. The maximum height of this column will be:
1200 =
H × 51 144
H=
1200 × 144 = 3388 feet 51
The valve must be set at a depth of 3388 ft 2)
When the well is in operation, the gas injection will have reduced the density of the oil to 40.5 Lb/cuft. Pressure in front of the valve will be:
Pa =
3388 × 40.5 = 953 psi 144
The pressure difference: 1200 - 953 = 247 PSI will allow the gas injected to enter the tubing through the valve. Under the valve the density of the effluent is still 51 Lb/cuft and exerts a pressure of:
Pb =
(5200 − 3388) × 51 = 642 psi 144
The BHP will therefore be: Pa + Pb = 953 + 642 = 1595 psi 3)
Since the formation pressure is 1700 psi the well will begin to flow.
Note: Increase of production can be obtained by increasing the quantity of gas injected, resulting in lowering the density of oil. Another valve can be set lower down than the one already in place. This second valve can only be in operation when the well has been started up and gas through the first valve has already reduced the oil column pressure.
7 - 22
Pressure and temperature 2
Pumping Method
A bottom hole pump enables the height of the column of oil to be reduced so that the well can produce again. Let us consider a well of depth H where a pump is set at depth h1, which will lift the oil from depth h2 to the surface. Oil
h2
h1 = Pump level
h1
h2 = Fluid level
H
H = Well depth
Bottom hole pressure will be:
BHP =
(H − h2 )× d 144
Since this value will be lower than the formation pressure, the well will flow. Some calculations: A well 9200 feet deep has a bottom hole pressure of 3100 psi and filled with oil of SG = 0.950. 1) 2) 3)
Will the well flow? If not what is the fluid level? At what depth must the pump be placed - knowing that it must always be immersed under 600 ft of fluid so that when the well is producing the bottom hole pressure is 1000 psi.
1) The hydrostatic pressure of a column of 9200 ft is:
P=
9200 x0.950 x62.4 = 3787 psi 144
This pressure is greater than the formation pressure Therefore: well is not flowing 2) With a BHP of 3100 psi, the oil column in the well cannot be higher than
H=
144 × P 144 × 3100 = = 7530 ft d 0.950 × 62.4
h2 = 1670 ft
The liquid level h2 is therefore at 9200 – 7530 = 1670 ft 3) When the pressure is 1000 psi a the bottom of the well, the height of the oil column is:
H=
8- 23
144 × P 144 × 1000 = = 2429 ft (from the bottom) d 0.950 × 62.4
Pressure and temperature Then the depth is 9200 –2429 = 6771 ft. The pump will be installed at a depth of h1 =6771+600=7371ft
9 - 24
Pressure and temperature
10- 25
Pressure and temperature
1.3 BASIC CRITERIA OF A GOOD UNDERSTANDING OF METROLOGY Buzzwords: − − − − − − 1.3.1
ACCURACY RESOLUTION REPEATABILITY STABILITY HYSTERESIS TRANSIENT RESPONSE
Accuracy It is the overall performance of any instrument. Furthermore it is the difference between the measured value of pressures and the absolute true value generated by a reference standard (D.W.T.). Expressed in: % of F.R.O (Full Range Output) or % of reading.
11 - 26
Pressure and temperature
1.3.2
Resolution The smallest pressure variation that will result in a measurable change in transducer (meter) output. Expressed in:% of F.R.O. or absolute value. OUTPUT
Resolution
Pressure Increase
1.3.3
Repeatability Dispersion of the measurements when a gauge is repeatedly subjected to the same pressure with all others conditions remaining constant. Expressed in: % of F.R.O. or absolute value.
12- 27
Pressure and temperature
1.3.4
Stability The ability of a transducer to retain its performance (mainly accuracy) throughout its specified operating and storage life. DRIFT is the result of lack of STABILITY Expressed in: % of F.R.O. versus time or absolute values versus time.
1.3.5
Stability becomes crucially important in interference testing.Hysteresis Pressure difference at a given level between an increasing an a decreasing pressure excursion. Expressed in: maximum value.
1.3.6
Transient Response It represents the disturbances generated by a quick variation ot the main environmental parameters. For a pressure gauge, the two major inputs are pressure and temperature. Discrepancies are quantified by subjecting the instrument to pressure or temperature steps. Is expressed in maximum deviation according to specified input stimulation.
13 - 28
Pressure and temperature
1.4 TYPES OF PRESSURE GAUGES USED IN GEOSERVICES Four main types of gauges are to be considered: 1.
BOURDON MANOMETER
2.
FOXBORO RECORDER
3.
BARTON RECORDER
4.
AMERADA PRESSURE DOWN HOLE RECORDER
They all have a sensing element, a bourdon tube. 1.4.1
BOURDON TUBE The Bourdon Tube is the measuring device used in many gauges. The free end of the Tube is connected to a variable length linkage. This is connected to a pivoted arm, at one end of which is a toothed arc and the other end a variable length linkage. The toothed arc of the pivot arm engages a gear wheel with a pin on which is attached the pointer. A.
C SHAPE The sensing element of a Bourdon Tube is a curve. There are two main forms: A - C shape B - The Helicoidal Form. The C Shape is very common in pressure gauges. The Helicoidal form is found in instruments such as the BARTON, MECI FOXBORO and AMERADA.
B.
HELICOIDAL FORM When pressure is applied to the Bourdon Tube, it tends to straighten out and the relative pressure is measured by the displacement of the free end. After the pressure has been withdrawn, the Bourdon Tube returns to its original point because of its elasticity.
14- 29
Pressure and temperature
1.5 AMERADA PRESSURE DOWN HOLE RECORDER While in the first three pressure gauges the displacement of the bourdon is transmitted to the index or to the pen on the scale through a system of links, in the Amerada the stylus is directly connected to the Bourdon, thus to reduce to the minimum the moving parts in a tool, which has to satisfy very special operational requirements. As a result in the Amerada it is not possible to correct the errors through mechanical adjustments, and the output values cannot be read directly on the chart. It is, therefore, necessary to draw the actual calibration curve of the gauge and after having interpolated it (using the least square method) with a straight line, to refer to this line to read the values of the pressure. The process of tracing the calibration curve and calculating the interpolation straight line is known as the "CALIBRATION OF AMERADA PRESSURE GAUGE". The temperature affects the Bourdon response; the calibration should be performed at a temperature as close as possible to the bottom hole temperature at which the gauge will work.
For the other gauges considered (Manometer, Foxboro and Barton recorders) it always exists a linkage system between Bourdon tube and index. This system can itself introduce errors, but allows also for their corrections through adjusting screws that are slightly modifying the lengths of the links. In particular the linkage system can introduce a "linearity error" which should not be confused with that of the sensing element and that can be called "linearity misalignment". Unlike that of the sensing element, this error can be corrected through linkages adjustments.
15 - 30
Pressure and temperature
1.6 BOURDON MANOMETER Following is considered the linkage system of a Bourdon Manometer, which with few small variations is also valid for the other instruments.
Fig. 1
16- 31
Pressure and temperature
1.6.1
Linearity error of the linkages
Fig. 2 Ideally equal variations of the variable (here the displacement) produce equal increases in the indication over the full range (definition of LINEARITY). In reality as illustrated in Fig. 2 the angle a is smaller than the angle ß due to the different lengths of the arcs A2A1 and A2A3. So when it is 50% we read on the scale a value less than 50%. This error can be reduced by having the angle between link "a" and needle equal to 90° when the pressure applied is 50% of the full scale. To adjust the linearity we have then to apply 50% of the f.s. pressure and adjust the length of link to have a right angle. This is always the first adjustment to perform when calibrating a Bourdon Tube gauge.
17 - 32
Pressure and temperature
1.6.2
Zero offset error adjustment
Fig. 3 Even if this adjustment corresponds to a shift of the scale, as shown in Fig. 3. The zero adjustment is performed rotating the index needle around its pin, because the scale is fixed in the instrument.
18- 33
Pressure and temperature
1.6.3
Angularity error adjustment The Angularity of the gauge is its ability to indicate correctly when the value of the measurement is at 0% and 100% of its range.
Fig.4 To adjust the angularity we act on the length OA of the variable length linkage of the pivoted arm. OA is the distance between the pivot O and the attachment point A of the linkage. As it is shown in Fig. 4 the angularity is adjusted so as to half the error Ea present when the upper range pressure is applied.
19 - 34
Pressure and temperature In Fig.5 we can see how the dimension d of the pivoted arm can be varied.
Fig. 5
20- 35
Pressure and temperature
1.6.4
Calibration settings
Fig. 6 The calibration steps are the following: Replace main scale with a graduated disc allowing access to the regulating elements. 1.
Adjust linearity link to have the 90° angle when 50% of pressure is applied (Fig. 6)
2.
Adjust zero (Fig. 6)
3.
Adjust angularity. Apply 100% nominal pressure and check the reading. If it is too high, lengthen the variable angularity arm to have the error. If it is too
21 - 36
Pressure and temperature small, shorten it. Remove pressure and reset the zero. Repeat these two operations until the pressure gauge reads correctly for 0% and 100% of the nominal pressure.
1.6.5
4.
Check linearity. Apply 50% of the working pressure and check the reading. If it is too high, lengthen the variable arm between the Bourdon tube and the pivoted arm. If too small, reduce.
5.
Re-adjust angularity.
6.
Alternate steps 4 and 5 until the gauge reads correctly at 0%, 50% and 100% of its range.
Field operation − The pressure gauge should be selected to read the pressure in the middle third of the scale. − Always fit a pressure gauge with an isolation valve and, if possible, a purge valve. − The threads of the gauge and the valve or piping must be the same. − Do not screw the pressure gauge only its case, use a spanner on the hexagon neck. − Protect the gauge against vibration, shock, high temperatures, by the following methods:
1.6.5.1 High Temperatures Use a coil of stainless steel pipe to separate the gauge from he piping. e.g. Max temperature for bronze elastic chambers 150°F Max temperature for steel elastic chambers 400°F
1.6.5.2 Low Temperatures Coils deteriorate rapidly if the liquid inside freezes. Use a buffer pot with glycol (etc) inside.
1.6.5.3 Vibrations and Shock Isolate the gauge by using flex. Gauges must be removed when shocks are anticipated. e.g. changing the choke
1.6.5.4 Pressure Surges Pressure surges are to be avoided. Open the isolation valve to the gauge slowly or fit a pulsation dampener.
22- 37
Pressure and temperature
1.7 FOXBORO The Foxboro is a device that measures pressure and temperature at the well head (before the choke manifold) on a diagram. The pressure sensor is a bourdon tube typically 5000 and 10000 psi, the temperature sensor a fluid filled. The Foxboro is normally connected to the choke manifold to measure WHP and WHT. The pressure and temperature are recorded on a chart, which is driven by a clock. Therefore pressure and temperature are recorded versus time. IMPORTANT POINTS − − − − 1.7.1
Choose the bourdon tube range according to the expected maximum WHP. The clock has to be wound, and the chart changed every 24 hrs. Check, every now and again, that the chart is driving. Do not over wind the clock.
Description Two different pressure ranges and one temperature range are available on a Foxboro.
1.7.1.1 Pressure Elements A Bourdon Tube generally of helical shape transmits the pressure to a system of links, which relay the signal to a recording pen. Pen
Link Bourdon tube
Pressure
1.7.1.2 Temperature Element The temperature element consists of a bulb containing a volatile liquid in connection with a helical Bourdon tube. Increase in the well temperature changes the vapour pressure of the liquid and thus the pressure inside the Bourdon tube, causing rotation of the free end.
1.7.1.3 Time Scale The time scale is given by a clock, which guides a diagram. The clock and diagram can be of 24 hours or 7 days
23 - 38
Pressure and temperature 1.7.2
Installation at the well site Select a location, which is well illuminated, free from vibration, and free from big and rapid variations of temperature. During installation check the scale to which the Bourdon tube is connected. The following connections are to be used: Female NPT ¼" up to 2000 PSI Male NPT ½" over 2000 PSI Do not forget to take into account that: If fluid being measured has excessive pressure fluctuations or pulsations, a fluid damper should be installed. If fluid being measured is corrosive, viscous or has solids in suspension, pressure seals or purge should be used.
24- 39
Pressure and temperature
1.
BOURDON TUBE ADJ.
2.
ANGULARITY ADJ. SCREW
3.
LINK ADJ.
4.
LINEARITY ADJ.
5.
LINK ADJ.
6.
ZERO ADJ.
7.
RANGE ADJ.
8.
PEN ACTUATOR
9.
PEN CARRIER
10.
PEN
25 - 40
Pressure and temperature
1.7.3
Calibration a) To adjust path of arcing pen: Only one pen - the arcing pen- in a recorder traces a path that coincides exactly with the time arc on the chart. To adjust it: −
− −
Remove chart plate. Disconnect link from pen movement (note which hole link is in). Replace chart plate and chart itself. Move arcing pen across chart by hand. If path of pen requires adjustment, loosen left chart drive screw and hex nut at bottom of left column. Adjust eccentric hex shaft until path of pen is satisfactory. Tighten nut and screw, and reconnect link. Check calibration.
b)
Squaring up of linkage for complete calibration:
− −
Set pressure at middle of element range (see range on element nameplate). Obtain right angle a) by loosening the two screws on top of element and slipping drive lever on its shaft. Obtain right angle b) by adjusting length of link (See Barton notes for geometrical demonstration).
−
−
26- 41
Pressure and temperature
c)
To adjust angularity:
−
Adjust the zero (without applying pressure on the Bourdon tube. Purge if necessary). Apply 100% pressure on the Bourdon tube, correct the error by half with the angularity adjustment screws. Return to zero, readjust it if necessary and then apply 100% pressure. Repeat this operation until correct angularity is obtained.
− − −
27 - 42
Pressure and temperature
d)
To adjust linearity:
−
Set pressure at mid range. If the pen is not at midscale, proceed as follows: 1. adjust length of link to move pen five times the amount of error in the direction of the error. 2. then begin all the adjustment again (including the adjustment of angularity).
As soon as calibration is finished, lock all the adjustment screws with nail varnish, for example.
28- 43
Dead weight tester
SECTION 7 DEAD WEIGHT TESTER
1-1
Dead weight tester Pressure results from the application of a force, which is distributed over an area of surface, it is defined as a force or thrust exerted over a surface divided by its area.
P=
F A
BASIC PRINCIPLE
Practical applications of Pascal's principle are the hydraulic jack and the dead weight tester.
Consider the piston A with a surface area of 20 cm2 and piston B with a surface area of 1 cm2. To raise the piston A (i.e. to lift the 200 kg weight) a pressure P must he applied on to A to produce an upward force F greater than 200 kg. 2-2
Dead weight tester
Pr essure =
Force 200 Kg = = 10 Kg / cm 2 Area 20cm 2
A force of 10 kg applied on B will result in a pressure of 10 kg/cm² which will be transmitted through the fluid to the piston A. A weight slightly above 10 kg on B will therefore lift the 200 kg weight on A. In a DWT the piston A has been removed and the cylinder is then connected to either: −
a closed vessel where we can vary the pressure with a pump (i.e. Bourdon tube gauge),
−
or an external pressure source (i.e. well head).
The pressure on the system applied on the piston B is balanced by the pressure resulting from a known weight on this piston of known diameter. The weights and pistons are calibrated to give an accuracy of 1/10 of 1 % of the indicated pressure.
3-3
Dead weight tester
1.1 PORTABLE HIGH PRESSURE DEAD WEIGHT TESTER Dead-Weight Testers are a source of very accurate pressures and are used for calibration of other, less accurate, types of pressure measuring devices such as Bourdon Tube pressure gauges. The high accuracy is obtained by balancing the force exerted by the oil pressure on a piston of known area against weights of known mass. The weights and pistons are calibrated in sets to give an accuracy of 1/10 of 1% of the indicated pressure. The High Pressure Dead-Weight Tester sketch is shown on the following page. Before using the Tester the first time, the oil reservoir must be filled with oil through Filler Plug using the oil supplied. A good grade of SAE 20 oil is recommended. The Tester must be on a firm level base. (The Ac-Me Tripod forms a convenient field support.) After removing the carrying case cover, weight rods and weights, the gauge to be tested is connected to the gauge-connecting base using one of the adapters supplied. The correct numbers of weights to give the pressure desired are placed on the piston table and the oil pump operated until the piston floats, while spinning, between the two marks just below the table. The oil pump is a screw type with manually operated valves. When facing the Tester, with the oil pump to the right, the far valve is in the suction line, and the near valve in the discharge line. After the test is completed, the oil should be pumped back into the reservoir, the gauge removed from the Tester and the connection on the Tester plugged; after which the weights, weight rods and cover may be replaced, leaving the Tester ready for transportation. The Tester may be used as a Dead-Weight Gauge by using the reservoir adapter as a reservoir to prevent gas from blowing through the piston and cylinder. The adapter should be screwed into the gauge connector base, filled with oil, and connected to the gas pressure through suitable tubing and a valve. After the valve is opened and pressure is on the piston, weights are placed on the table until it floats, while spinning. The indicated pressure is then the total of all the weights on the table, pius the table, when balance is obtained. The entire Tester should be kept clean, as dirt and grit will cause rapid wear. The piston will naturally wear with use and will change size slightly, impairing the accuracy, at which time the Tester should be recalibrated. Excessive oil leakage usually indicates this condition. Since the piston and weights are matched sets, the entire Tester must be returned for the recalibration.
4-4
Dead weight tester
TYPICAL DEAD WEIGHT TESTER
5-5
Dead weight tester
1.1.1
Portable high pressure dead-weight tester replacement parts Part Number
Description
2-7 2-8 2-9 2 - 10 2 - 13
RESERVOIR CAP PUMP CYLINDER PISTON AND CYLINDER ASSEMBLY PUMP PLUNGER ASSEMBLY CARRYING CASE COVER
2 - 16 2 - 59 5 - 12 5 - 13 5 - 14
BASE UNIT ASSEMBLY BASE PLATE WEIGHT N° 1 WEIGHT N° 2 WEIGHT N° 5
5 - 15 5 - 16 5 - 17 5 - 18 5 - 20
WEIGHT N° lO WEIGHT N° 50 WEIGHT N° 100 WEIGHT N° 500 WEIGHT ROD
15 - 18 23 - 6 23 - 13 23 - 69 36 - 38
KNURLED NUT OIL PUMP CAP PUMP SCREW WITH HANDLE GAUGE CONNECTOR 10 FT LENGTH 1/8" STEEL TUBE W/FITTINGS
36 - 39 36 - 40 36 - 44 P - 62 P - 63
20 FT LENGTH 1/8" STEEL TUBE W/FIITINGS ADAPTER ¼" MALE X ¼" FEMALE RESERVOIR ADAPTER ½" "O" RING CYLINDER CYLINDER AND PUMP "O" RING
P - 180 P - 256 P - 291 P - 530 P - 531
HOSE ADAPTER BUSHING ¼" X ¼" VALVE 1/8" MALE POINTER DRIVER HAND JACK
P - 748 P - 760 P - 856 P - 857 P - 859
BACK-UP RING PUMP FILLER PLUG LEATHER HANDLE HANDLE LOOP "U" CUP PUMP
P - 972 P - 984 P - 1121
PIPE PLUG ¼" LEVEL, BULLSEYE SMALL WEIGHT STUD
6-6
Dead weight tester
7-7
Dead weight tester
1.1.2
Trouble shooting chart
TROUBLE A. Gas escapes past piston when instrument is used to determine unknown gas pressure
B. Gas "bubbles" or blows into oil of centre reservoir, when determining unknown gas pressure C. Not sensitive to small weight changes, when used to determine unknown gas pressure
PROBABLE CAUSE 1. Insufficient oil in 36 - 44 reservoir adapter. Valve, and draw oil into pump.
REMEDY 1. Shut off and "bleed" pressure from tester. Close discharge Close suction valve, open discharge valve and pump oil to th e 36 - 44 adapter until full.
2. Damaged ring.
2. Unscrew cap nut remove guide rod and piston. Use wrench to unscrew cylinder from adapter with pencil and replace P - 62 "O" ring.
cylinder
"O"
Damaged cylinder adapter "O" ring.
Disassemble as per 'A - 2'. After unscrewing cylinder adapter replace P - 63 "O" ring.
1. Overtightened cap nut.
1. Unscrew cap nut. Re-retighten only until "snug".
cylinder
2. Dirty oil.
3. Damaged Piston.
D. Pressure cannot be maintained, when calibrating another pressure gauge.
8-8
2. Remove oil. Wash clean with solvent and replace with clean oil. 3. Remove piston and cylinder as per '2-2'. Clean with solvent. If 'binding' is evedent replace with new 2-9 piston and cylinder assembly.
4. Cold weather makes standard oil too viscous.
4. Replace standard oil with P1484, low temperature 'pour' point oil.
1. Air is drawn into pump because of insufficient oil in centre reservoir.
1. Unscrew 2-7 cap and check oil level in reservoir. Add oil if necessary.
2. Damaged cylinder adapter "O" ring.
2. See "B" remedy.
Dead weight tester TROUBLE
E. Excessive Oil leakage at piston
F. Not sensitive and/or poor operation during hydrostatic (water) testing.
PROBABLE CAUSE 3. Leakage thru "suction" valve.
REMEDY 3. Close P-291 "Section" valve securely. If leakage persists, remove and examine valve stem. Replace valve if required.
1. Damaged ring.
1. Replace P-62 "O" ring as per 'A-2'.
cylinder
"O"
2. Oil too "ligh".
2. Check and remove fluid in reservoir if it is shock absorber or brake fluid. Replace with SAE 20 Oil.
3. "Worn" piston and cylinder assy.
3. Replace with new 2-9 piston and cylinder assy.
Water emulsifying tester oil.
Best - use P-1169 synthetic fluid instead of standard oil.
with
Satisfactory - use 2-71 oil water separator.
9-9
Separators and separation
SECTION 8 SEPARATORS AND SEPARATION
1-1
Separators and separation
1.1 SEPARATION PRINCIPLE Phase separation in a separator is based on gravity: -
oil is segregated from liquid
-
oil si segregated from water
Gravity separation only takes place when: -
fluids to be segregated are not solubre in each other
-
fluids have different densities
Separation speed is a direct function of realitive gravity
Gq 1 = = 0.05 G1 20
G1 = 0.75 Gq
95 % of separation takes place within a few seconds
Separation requires a few minutes
1.2 SEPARATOR 1.2.1.1 Role of separator For safety reasons, because the well head pressure is still not at atmospheric pressure (Eruptive well) and the temperature is still elevated, it is necessary to free the oil of both dissolved and free gas before putting it in storage tank (Atmospheric conditions). Therefore the separation occurs of the gas from free liquids such as crude oil, hydrocarbon condensate, water and entrained solids. So, the basic separator design must: 1. Control and dissipate the energy of the well stream as it enters the separator. 2. Ensure that the gas and liquid flow rates are low enough so that gravity segregation and vapor liquid equilibrium can occur. 3. Eliminate re-drive of the separated gas and liquid. 4. Provide an outlet for gases with suitable control to maintain preset operating pressure. 5. Provide outlet of liquids with suitable liquid level controls. 6. Provide clean out ports at points where solids may accumulate. 7. Provide relief for excessive pressures in case the gas or liquid should be plugged. 8. Provide equipment such as pressure gauges, thermometers, and liquid sight glass assemblies.
2-2
Separators and separation
1.2.1.2 Separator lay out The separator consists of cylindrical container designed to resist high pressure. It may be vertical or horizontal. The oil accumulates at the base of the container, while the gas, being less dense, occupies the space above it. So, the gas/oil separation is due to gravity. The gas outlet is fitted with a special valve to maintain a fixed backpressure. The oil outlet with a valve, controlled by a float, ensures that the level remains in the middle of the separator. Thus the oil remains in the separator for a certain period of time, depending on the affluent flow rate. Let's say the oil contained in the separator is 1 m3 and the separator is treating 60 m3/hour, so the oil will be replace every 1/60 hours for each minute. during this period, the oil is maintained at a constant pressure and bubbles of gas produced in the oil are raised into the gas space above the liquid level. Therefore, the oil leaving the separator is almost free of entrained gas; the amount remaining depends on pressure, temperature, viscosity, the nature of the oil, retention time etc. An equilibrium is established between the quantities of each of the components present in the liquid and gaseous phases. It is necessary for the oil to be kept in the separator for long enough. The time is generally known as the "RETENTION TIME" and depends on: a.
Nature of the oil (density and viscosity) 30 seconds for light oil 60 seconds for high density oil.
b.
The effluent flow rate
c.
The separator dimension and liquid level.
1.2.1.3 Type of separators Vertical Vertical is used on low to intermediate gas/oil ratio well streams. It can be fitted with a false cone bottom to handle sand production. (As an offshore platform where space is an important consideration). However, because the natural upward flow of gas in a vertical vessel opposes the falling droplets of liquid, a vertical separator is more expensive than horizontal units for the same capacity. An inlet diverter spread the inlet fluid against the vertical separator shell in a thin film and at the same time imparts a centrifugal motion to the fluid. This provides the desired momentum reduction and allows the gas to escape from the thin oil film. The gas rises to the top of the vessel and the liquid falls to the bottom. Some small particles will be swept upward with the rising gas stream and these particles are separated by a centrifugal baffle arrangement below the gas outlet connection. Horizontal The horizontal separator is less expensive than the vertical separator for equal capacities. It has a much greater gas /liquid interface area, consisting of a large, long baffled gas separation section which permits higher gas velocities. They are always used for high gas/oil ratio well and for foaming well streams. It is equipped 3-3
Separators and separation with a flow breaker (i.e. a series of steel plates designed to capture the oil particles), a horizontal baffle to prevent waves and finally a series of deflectors at the gas outlet. Three phase horizontal separators are used for well testing and from time to time where free water readily separates form the oil or condensate. They are identical to two-phase separators except for a water compartment and an extra level control and dump valve. A double-barrel horizontal separator has all the advantages of a normal horizontal separator plus a much higher liquid capacity. Incoming free liquid is 'immediately drained away from the upper section into the lower section. The upper part is filled with baffles and the gas flows straight through and at higher velocities. 1.2.1.4 Separator capacity Liquid capacity is function of: −
Retention time t=vo (usually 1 min)
−
Separator oil volume (liquid level)
Gas capacity is function of : −
Separator pressure
−
Gas liquid interface level
1.2.1.5 Working pressure and nominal pressure of a separator The separators used are characterized by their flow (gas + liquid) and by their nominal pressure printed on the manufacturers plate. The nominal pressure is the maximum pressure at which the separator can be used. Manufacturers provide models whose nominal pressure is between 40 and 3500 psi. A separator must never be operated above the nominal pressure. Moreover, this would not be possible as, in general, two safety devices are installed to avoid excess pressure. 1. A safety valve designed to open at 90W separator's nominal pressure. 2. A rupture disc designed to break at pressure equal to 1009 bar of the nominal pressure. To ensure that separators withstand their nominal pressure without any leaks or risk of rupturing, they are tested to a higher pressure. The test pressure is nominal pressure increased by 50 % (e.g. for 600 psi nominal pressure, the test pressure will be 900 psi). The regulations demand that a hydraulic test is carried out every 2 years.
4-4
Separators and separation
Diagram of separator
5-5
Separators and separation
1.2.1.6 Gas capacity The gas capacity of a separator depends on the speed of the gas as it passes through the separator and is proportional to the pressure and the gas passage section. For horizontal separators it is a function of : -
The height of the liquid
-
The separator diameter. SEPARATOR PRESSURE (psi)
DIMENSIONS
HEIGHT OF OIL
1200
18" 650000 23
12" 960000 34
8" 1100000 39
600
450000 16
680000 24 260000 9.2 205000 7.2
850000 30 400000 14 310000 11
36" x 10'
1200 24" x 10' 600
6"
450000 16 370000 13
1.2.1.7 Oil capacity The "Retention Time" is the time it takes a fluid particle to flow through the separator. This time depends on: a. The separator diameter b. The length and height of the separator. An increase in any of these parameters will increase the "Retention Time" if the retention time is kept constant and the separator capacity will be increased. Generally
-
SEPARATOR PRESSURE RETENTION TIME 0 - 600 pis 600 - 1100 psi 1100 psi
6-6
1 minute 50 seconds 30 seconds
Separators and separation
1.2.2
Verification And Utilisation of Separator During A Test Programme
1.2.2.1 General verifications Before any job, the verification of the separator and its accessories must be done. This verification consists of: -
Hydraulic test pressure
-
Check the working of Daniel orifice, Barton flow meter, pressure controller, level controller, safety valves and rupture discs, sight glasses plus all valves on separator.
1.2.2.2 Starting procedure Before starting a test program, ensure all equipment confirms with test program and rig up completely. After rig up is done, pressure tests the test package to conform to safety regulations. Prepare accessories for use, Ranarex meter, BS&W kits, gravitometers. Before starting up the separator the following things should be checked: -
Rotron/Floco isolated, by pass open.
-
Daniel Orifice up
-
It is assumed that the correct operation of ACV's has been checked.
-
Wizard valve set "just on the balance", valve closed.
-
Level troll valve set "just on the balance", valve closed.
-
This means that as soon as the flow goes into the separator, the wizard valve will begin to open. This means you cannot accidentally overpressure the separator. This is particularly important in high volume/pressure gas wells. Similarly the level troll valve will begin to open as soon as the level touches the float.
METHOD A The by-pass is open, inlet closed. (Which by-pass will depend on whether it is a gas or an oil well.) Slowly open the inlet, and close the by-pass. (SLOWLY!) As you do this, you should observe the wizard valve beginning to open. If it does not, STOP, close the inlet opens the by-pass again and checks the operation of the wizard. Except in low pressure/volume wells, you should have an assistant watching the level/pressure in the separator as you perform this task.
7-7
Separators and separation Gradually bring the separator pressure and level up to required levels. Remember that separator pressure should never be greater that 1/3 of WHP, or below a pressure that creates liquid carry over problems. Also if flowing directly to the burners, you will need sufficient pressure to attain efficient burning. In very lowpressure wells it may be necessary to flow to a tank first. The level chosen will depend upon the oil/gas capacity of the well. The client will often dictate the parameters. METHOD B This method has more application in high volume/GOR wells. Open the inlet to the separator, LEAVE THE BY-PASS OPEN, bring the pressure and level up, when the separator is running smoothly, slowly close the bypass. This method means that you reduce the risk of over-pressuring the separator. (Blow safety valves, rupture discs!) 1.2.2.3 Shut down procedure After the test program is completed: 1. Lift Daniel orifice and isolate Barton recorder. position.
Put liquid meter on by-pass
2. Open main by-pass, close inlet valve and gas main valve. 3. Drain separator through drainpipe by using pressure remaining in the separator. If necessary flush test package with diesel or water.
Note: Daniel Orifice should always be lifted if anything is done which upsets the balance of the separator, i.e. changing chokes, etc..
8-8
Separators and separation
9-9
Separators and separation
10 - 10
Separators and separation
1.3 SEPARATION PROBLEMS
PROBLEM
Liquid carry over
CAUSES
High flow rate High liquid level Low operating pressure
Wave action in separator
ACTION
Decrease flow rate Lower oil/gas interface Raise operating pressure or decrease flow rate Reduce sensitivity of oil level controller Increase pressure
Foaming Poor gas/oil separation.
High viscosity High separator pressure
Heat well effluent Increase retention time Reduce pressure
11 - 11
Separators and separation
1.4 SEPARATOR TROUBLE SHOOTING 1.4.1
Liquid carry over in outlet gas stream POSSIBLE CAUSE OF CARRY OVER
1. High inlet gas flow
2. High liquid level which reduces vapor space.
TROUBLE SHOOTING PROCEDURE
Check gas flow and reduce after consulting client representative.
Check liquid level. Clean glass. Lower level.
3. Coalescing plates or mist pad is plugged with waxes, paraffin’s, hydrates, debris on the separator and after the demist pad.
Check pressure and temperature for waxes, paraffins, and hydrates formation. Remove debris. Measure pressure drop across plates and pad, should be less than 2 psig. A DWT can be placed.
4. Wave action in liquid
Check baffles inside separator. Have they corroded away?
5. Low operating pressure
Check pressure and if necessary or possible raise or alternatively reduce flow rate.
6. Hunting - Wizard too sensitive 7. Slugging/Heading
12 - 12
Check proportional band, increase dismantle and check for obstructions.
or
Too large chokes size, check with client and reduce.
Separators and separation POSSIBLE CAUSE OF CARRY OVER
8. Float has not been attached to torque tube. 9. Float is totally immersed in liquid
flapper
or
remove
Check proportional band and increase. Check proportional band controller for obstruction.
12. The well is slugging; reaction time for the controller is too slow.
valve
of
A. Blocked sight glass - true level not been shown. B. Close manual outlet valve and observe level. C. Set level controller to half level. D. Put level controller into service.
11. Level-troll too sensitive.
control
Checks position inspection cover.
A. Blocked sight glass - true level not being shown B. Manually drain separator in order to actuate float. C. Put level controller into service.
10. Float is not in liquid phase.
13. Automatic properly.
TROUBLE SHOOTING PROCEDURE
is
not
14. Wave action causing float to move.
operating
Lower set point on liquid level controller. Reduce proportional band setting.
A. Check operation manually. B. Check valve action. Is it normally closed or normally open? C. Is the controller set-up correctly?
Check condition of baffle/weir.
13 - 13
Separators and separation POSSIBLE CAUSE OF CARRY OVER
TROUBLE SHOOTING PROCEDURE
15. Level controller shows no response.
A. Check torque tube movement by manually twisting. If no response then repair controller. If yes, then float has dropped off? Replace. Alternatively liquid level is above or below float. B. Check liquid level. C. Manually drain separator and observe for controller movement or ACV movement as level falls off one length of float. If no response then float has come off.
16. Float in oil/water interface is totally immersed in emulsion.
A. Check for emulsion by draining fluid from separator. B. Drain emulsions or introduce de-emulsifier at choke.
AII above-mentioned points should be been checked prior to the test. They will be covered during the procedure if it has been written out meticulously. 1.4.2
How to deal with oil foaming during separation
1.4.2.1 Foam formation It is always caused by the liberation of a large amount of micro-bubbles in the oil. This is due to: −
Either a localized pressure drop during the process
−
Or a delayed gas evolution, caused by the liberation of heavier gases (C; - C3 - CO2).
Factors that increase the foam volume are: −
High pressure drop
−
Pressure drop taking place at low pressure
−
High volume of evolved gas.
Presence of foam will prevent good separation, ruin gas and liquid metering and pumping. The most adverse factor is foam stability. Two factors help to decrease the stability: −
Slow separation process (multistage separation)
−
Lowering oil viscosity by heating.
1.4.2.2 How to fight oil foaming To fight oil foaming the use of chemical means is the most used. The molecules of antifoaming additives replace the natural tensio-active components adsorbed on interfacial films. It has been shown that:
14 - 14
Separators and separation −
Silicon additives are the most efficient ones (e.g. RHODORSTL 427, DOW CORNING 200)
Note: STRAIGHTENING VANES - Be aware that ½" NPT plug upstream holds straightening vanes in place. This plug should never be removed during normal operations.
15 - 15
Separators and separation
Note: SIGHTGLASS VALVES - If during a well test operation, the window of a liquid level breaks, there is a Ball Safety Valve automatically closing under the differential pressure existing between the inside of the Separator. In this case the normal reaction could be to close manually the isolating valve of the liquid level. Doing so, the internal pressure of the separator is redirected to atmosphere this until this valve rests on its seat, since it has a plunger pushing back the ball in the open position. So, if a liquid level window breaks, the safe solution for repair is to by-pass the separator before bleeding its pressure to zero, then to close the isolation valves of the liquid level and to proceed to window replacement. During repair, the separator must be restarted.
If this solution is not possible, either wait for the completion of the test or start repairing - but IN NO CASE, THE ISOLATING VALVES OF THE LIQUID LEVEL SHOULD BE CLOSED. This precludes that the Ball Safety Valve does its job perfectly.
16 - 16
Separators and separation
SIGHT GLASS VALVE
17 - 17
Separators and separation
1.5 Safety -
THE EQUIPMENT USED IN WELL TESTING OPERATES AT HIGH PRESSURES WITH INFLAMMABLE LIQUIDS.
-
IT IS ESSENTIAL THAT THIS EQUIPMENT BE HANDLED BY COMPETENT OPERATORS IN ACCORDANCE WITH STANDARD PRACTICE AND SAFETY REGULATIONS.
-
Check the validity of the official pressure test of the separator.
-
Check rupture disc rating.
-
Check calibration of safety valve has been performed within the last 3 months.
-
Ensure all members of the crew are competent in the operation of the separator.
-
IF H2S IS PRODUCED, IT IS FORBIDDEN TO USE SEPARATOR GAS TO SUPPLY THE PILOT CIRCUIT FOR THE INSTRUMENTATION.
-
This is because in normal operations, gas is vented from the flapper nozzle systems of the controllers.
-
If H2S is expected, or even suspected, breathing apparatus must be available and used, if concentrations of H2S are above minimal levels. See Geoservices safety manual for toxicity levels.
-
On H2S jobs, all vent lines (Daniel bleed down, sight glasses etc) should be piped to a safe area. Particular attention should be taken when sampling, operating shrinkage tester etc.
-
On H2S jobs operate the "buddy" system whereby no operator works on his own without supervision from another area.
-
All well testing equipment should be electrically grounded with an earth strap (minimum area 1 sq. cm). Offshore this should be welded or bolted to an unpainted part of the deck. Onshore earth stakes (minimum length 1 meter) should be used. Earth stakes should be kept damp.
18 - 18
Safety valves & Rupture disc
SECTION 9 SAFETY VALVES AND RUPTURE DISCS
1-1
Safety valves & Rupture disc
1.1 SAFETY VALVES 1.1.1 Role The role of the safety valve is to automatically reduce an overpressure in the separator by venting off a certain amount of gas. The safety valve is normally set at 90 % of Working Pressure of the Separator (e.g. a 1440 psi separator shall have the safety valve set at 1296 psi). 1.1.2 Description The valve consists of : −
the cone (3)
−
the perfectly ground flat closing disc. This is the top sealing face (4)
−
the guide which isolates the body and casing (8)
−
the Balan seal bellows which counteract the effect of hack pressure and isolates the safety valve internals i.e. spring, spring stop etc. from the vented fluid/gas (28)
−
the tapered disc carrier which diverts the force of the vented fluid away from the guide
−
the blow down ring which is used to make the disc rise more quickly after the set pressure has been reached (7)
−
a hand operated level to test the function of the valve. (Only on certain safety valves.)
2-2
Safety valves & Rupture disc
3-3
Safety valves & Rupture disc
1.1.3 Operation The valve opens violently when the upward force exerted on the seat face by the separator pressure overcomes the force exerted downwards by the spring.
F = P×S Where
F P S
= = =
force exerted by the spring Separator Pressure Area of the Valve Seat.
1.1.3.1 Safety Valve Operation (Series 2600 FARRIS SAFETY VALVE) This valve features a blow down spring. When the pressure in the nozzle exceeds the compressive force of the spring, the disc rises. For compressible fluids (air, gas, vapour) the full opening occurs at less than 3% above the adjustment pressure and the closure at less than 51% below it. For non-compressible fluids (Liquids) the use of the spring causes hammering. The spring is therefore inactivated by winding it right down. In this case the full opening occurs at 10% to 15% of the adjustment pressure. Setting the blow down ring The spring is adjusted according to the relief valve pressure setting. It is screwed into the nozzle and has around its perimeter a serrated edge which positions it in the nozzle. A set screw which makes contact with the serrated edge holds it in position. For liquids the spring is not required and so it is screwed right down.
Fig. 1 Setting for gases and Vapours For gases and vapours, the position of the ring depends on the pressure setting. Proceed as follows:
4-4
Safety valves & Rupture disc With the disc in position, put the ring in contact with the disc holder (Figure 2, Position 1). Referring to the following table, lower the ring by a number of teeth corresponding to the pressure setting (Figure 2, Position 2).
Fig. 2
5-5
Safety valves & Rupture disc 2600 SERIES P
=
net calibrated pressure in kg/cm²
D
=
number of teeth after contact made with the disc holder
Up to P
D
P
D
1 2,8 4,6 6 7,7 9,5 10,2 12,4 13,4
2 4 6 8 10 12 14 16 18
15,8 19 25,5 31,5 38,5 42 47,5 48 70
20 25 30 40 50 60 70 80 90
These specifications apply to all types of valve complete with a blow down ring and to any part.
6-6
Safety valves & Rupture disc
1.1.3.2 The pilot operated safety valves As already briefly described this type of valve does not use a spring or a weight to keep the disc closed but uses the pressure of the process fluid. In fact this valve confines a certain quantity of process fluid in a chamber called "DOME" above the disc called "PISTON". The production of the pressure of the process fluid in the area of the dome is generally 20 % higher than the piston seat. This generates a force sufficient to oppose the static force of the fluid. this configuration permits a much higher set pressure with larger orifices than could be obtained with conventional or balanced valves, because of the much larger spring forces required for these valves. HOW A PILOT OPERATED SAFETY VALVE FUNCTIONS
7-7
Safety valves & Rupture disc
As illustrated in Figure 3 a pilot operated safety valve consists of a main valve destined to relieve the processes fluid and a pilot valve destined to control the opening and closing of the main valve. The pilot controls the pressure in the dome above the piston. The piston is seated on the nozzle and directly in contact with the process pressure. From this fact, both opposing sides of the piston are pressurized at a same value. But because of the larger area (20 % ore) on the topside of the piston, the net force is greater than the static force of the process fluid on the bottom side of the piston. Once the set pressure is reached the pilot opens and depressurizes the dome of the main valve, causing it so relieve as there is no longer any force acting on the top of the piston. Once the pressure decreases, the pilot closes and re-establishes the pressure in the dome of the main valve, which will also close. As an example, the unbalance of the piston, as previously said is generally 1.211 but some manufacturers (mainly for the low pressure) have a range up to 3.0/1. Taking an average valve of 1.2/1 (most common) that means that the top area of the piston is 1.2 times the area of the bottom area. Taking also a pressure of 10 bar upstream of the piston and an area of 10 cm² that gives: − −
Upward force = 10 cm² x 10 bar = 100 daN. Downward force = 10 x 1.2 x 10 bar =120 daN.
The net force will be 120 – 100 = 20 daN By this example, it is shown that for the main value to open, the pilot must depressurize the dome by at the least a pressure equal to 20 % of the inlet pressure. When that occurs the forces in opposition are balanced and the valve is then on the threshold of opening.
8-8
Safety valves & Rupture disc
POP ACTION PILOT OPERATED VALVE (flowing type) Fig. 3
9-9
Safety valves & Rupture disc
Fig. 4
Fig. 5
The process pressure increasing, the piston will lift immediately, and the valve will remain open all the time the pressure remains constant. The pressure decreasing, 10 - 10
Safety valves & Rupture disc the pilot will close and re-pressurise the dome of the main valve at the same pressure as that of the inlet of the valve as shown on the curve of the figure 4. For a pilot operated valve, the full lift occurs at set pressure and is maintained until the reseat also occurs. As no further force must be overcome as in a springoperated valve, the full lift is achieved without overpressure. EFFECT OF A BACKPRESSURE ON A PILOT OPERATED SAFETY VALVE
The dome (pressure chamber) must be perfectly pressure sealed fro the downstream side of the valve. That is for minimizing the pressure drop, which could occur, and also to prevent an eventual backpressure from entering. Because of this fact the lift characteristics of the valve are not affected. Indeed this is only valid for a backpressure not exceeding the inlet pressure. The sealing is generally made by means of rings in elastomer or plastics, but if the backpressure is greater than the inlet pressure (process), then it will cause the main valve to open as shown in Fig. 5 and consequently the flow will go backwards. In fact the backpressure force acting on the unbalanced area of the piston (around the seat area) will produce an upward lifting force which will cause the piston to lift. Example as previously described: −
Inlet pressure 10 bar - nozzle area 10 cm²
−
Unbalanced downward force = i e. 20 % of 10 cm² = 2 x lO = 20
−
Unbalanced upward force = 2 x 14 = 28
−
Net force = 8
Such a condition might occur if the valve is fitted into a pressured header and process pressure at the valve inlet decreases below the inlet pressure (process shut down). To prevent this, the answer is to equip the valve with two check valves. It is the most commonly used system. One check valve is fitted on the pressure line connecting the main valve outlet to the dome above the piston. Another is located in the pressure sense line. This latter having for target to prevent the backflow from the outlet into the process side of the valve through the pilot. The first check valve allows the backpressure to pressurize the dome of the main valve. When the back- pressure exceeds the process pressure only the area beyond the noule area is subjected to the back- pressure force. The area within the nozzle diameter is subjected to the higher backpressure on the top side of the piston and thus produces a net downward force to keep the valve closed (preventing a back flow). Example with the previous valve: 11 - 11
Safety valves & Rupture disc
−
Downward force = 0 x 1.2 x 14 = 168 daN
−
Upward force: 1. Inlet pressure = 10 x 10 = 100 daN 2. Backpressure = 2 x 14 = 28 daN Total upward force 128 daN
Net downward force = 40 daN. The above described system applies for the flowing pilot that means the process fluid coming from the pressure sense line flows through the pilot to maintain it open till the pressure decreases. Another type of pilot exists now (and is more and more used). Which is called the “non flowing pilot” which as its name states, does not flow the process fluid. When the main valve relieves to oppose a backpressure, the non-flowing pilot needs to be equipped with a system called "back flow preventer". The back flow preventer is a shuttle check valve system, which is fitted between the top and the outlet of the main valve. When the back-pressure is greater than the inlet pressure (PS) and this last lower than the set pressure, the shuttle check transfers to the left blocking the back-pressure flow entering the pilot. The dome is then pressurized by back-pressure. When the inlet pressure exceeds the backpressure but is lower than the set pressure the shuttle transfers to the right allowing the pressurization of the dome by the inlet pressure. When the inlet pressure exceeds the set pressure the pilot opens, depressurizing the dome (PB): the main valve opens and the shuttle transfers to the right blocking the hack-pressure flow to the pilot and sending the dome pressure to the pilot vent. The function of the second check value is to prevent the backpressure from discharging through the pilot vent when the main valve is relieving a backpressure acting on the pilot could cause an erratic closure or blow down of the main valve. ALL HAS BEEN SAID ABOUT THE MAIN VALVE BUT WHAT ABOUT THE PILOT?
The pilot valve is in fact a small spring operated safety valve, which functions in the same way. The supply pressure is sensed either at the main valve inlet through a pressure pick-up or directly on the process system itself. The inlet pressure acts on the seat of a spindle, which is loaded by the spring adjusted at the set pressure value. The pressure is equal both in the pilot and the dome of the main valve. The spindle seals an orifice called pilot exhaust. Once the pressure increases to reach the set pressure then the spindle lifts and releases the pilot exhaust permitting the dome pressure to escape and the main valve to open as shown in the below figure.
12 - 12
Safety valves & Rupture disc
A blow down adjustment allows the pilot to close more or less quickly to adjust the re-pressurisation of the dome once the pressure decreases.
13 - 13
Safety valves & Rupture disc DIFFERENT TYPES OF PILOT
1.
The most commonly used is the non-flowing pop action type. This type of pilot is not only designed to have no fiow of the process fluid but also to open the main valve in a snap way at the set pressure to full lift and reclose at some pressure below set. As for a conventional valve, this difference is called blowdown.
2.
The flowing pop action type is more and more abandoned, although acting in the same way as the no-flow type. It obliges the process fluid to be recuperated and furthermore submits the internals to the corrosive action fo the fluid.
3.
The modulating action type (flowing or not). This type of pilot produces a main valve opening characteristic that is proportional to the relieving capacity required. In other words, the valve responds to the flow capacity generated by the increase of pressure. In fact is acts as a regulator. The pressure at which the valve opens and closes is the same. There is no blowdown on this type of valve.
SEAT TIGHTNESS OF THE PTLOT OPERATED SAFETY VALVE
Two different designs of seat are in opposition. a.
The metal-to-metal seats where both the nozzle and piston seats are metallic (as most of the conventional valves). which do not accept the least foreign particle without its tightness being affected obligation to have both seats perfectly lapped withstands the corrosive action and temperature of most fluids.
b.
The soft seat where the nozzle seat is metallic and the piston seat is made form elastomer or plastic. accepts more easily some foreign particles without affecting the tightness does not need a lapping and is very easy and quick to replace is more sensible to the corrosivity and the temperature of the fluid pressure special care must be taken when selecting the elastomer
All the above described valves: o
weighted pallet
o
spring operated
o
pilot operated
are manufactured by the Sebim Group and are going to be described more fully in following chapters. The next table will help you to select the appropriate valve with regards to the operating service considerations.
14 - 14
Safety valves & Rupture disc 1.1.4
ADVANTAGES AND DISADVANTAGES OF VALVE TYPES
ADVANTAGES
DISADVANTAGES WEIGHTED PALLET TYPE
Low cost Very low set pressure availahle (down to 0.5 ounce/in2)
Set pressure not readily adjustable Extremely long simmer High overpressure necessary for full lift (100W or more in some cases) Seat easily frozen closed at cryogenic temperatures
CONVENTIONAL METAL SEATED Lowest cost (in smaller sizes and lower pressures) Wide chemical compatibility High temperature compatibility
Seat leakage Long simmer or long blow down (adjustment of blow down ring effects simmer, set pressure and blow down Vulnerable to effects of back-pressure (set pressure and capacity)
BALANCED BELLOWS METAL SEATED Protected guiding Set pressure constant with backpressure Capacity reduced only with higher levels of back-pressure Good chemical and high temperature capabilities
Seat leakage Long simmer or long blow down Limited bellows life High initial and maintenance costs Limited back-pressure capability Vulnerable to effects of inlet pressure losses
CONVENTIONAL SOFT SEATED Good seat tightness before relieving Good reseat tightness after relieving Good cycle life
Temperature limited to elastomer used Chemically limited to elastomer used Vulnerable to el'fects of inlet pressure losses
Low maintenance cost SOFT SEATED, PILOT OPERATED - PISTON TYPE Smaller, lighter valves at higher pressure and/or with larger orifice sizes Good seat tightness before relieving Good reseat tightness after relieving Ease of setting and adjusting set pressure and blow down
Not recommended for polymerizing type services without pilot purge Limited chemical and high temperature compatibility due to soft goods Liquid service limitation (must have suitable pilot) Limited low pressure setting (about 15 psia) 15 - 15
Safety valves & Rupture disc Pop or modulating action available In-line maintenance Adaptable for remote pressure sensing Short blow down obtainable Set pressure can be field test while in service Remote unloading available Not effected back-pressure (when pilot discharges to atmosphere or is balanced)
16 - 16
Safety valves & Rupture disc
1.2 RUPTURE DISCS These are fine metal diaphragms, designed to rupture in case an excess pressure is accidentally caused in the separator. The rupture disc pressure is chosen to be 100 % of the nominal working pressure of separator. The discs (or diaphragms) can be directly tightened in a special union sub, or between two flanges, according to the size and assembly. There are discs as large as 6' in diameter and also smaller sizes wit rupture pressure of up to 6000 PSI. The discs are conceived to resist the pressure and the pressure must be exerted on the hollow side. The metals commonly used are : − nickel − stainless steel 18/8 The pressure is indicated on each rupture disc, on a strip of metal riveted to the disc.
17 - 17
Safety valves & Rupture disc
18 - 18
Safety valves & Rupture disc
19 - 19
Pneumatic control valves
SECTION 10 PNEUMATIC CONTROL VALVES
1-1
Pneumatic control valves
AUTOMATIC CONTROL VALVE TYPE "EASY-E"
2-2
Pneumatic control valves
1.1 AUTOMATIC CONTROL VALVE - SINGLE PORT 1.1.1 Role The automatic control valve is a final control element designed to regulate the rate of flow of fluid in a pipe by varying its cross-sectional area in response to a signal received from a controller.
1.1.2 Description The automatic control valve consists of two separate parts. 1.
TOP WORKS OR DIAPHRAGM ACTUATOR
2.
VALVE BODY
TOP WORKS OR DIAPHRAGM ACTUATOR Converts the pressure output of the controller into a mechanical motion strong enough to move the valve plug. Diaphragm actuator consists of: −
Diaphragm case
−
Diaphragm
−
Metal diaphragm plate connected to an actuator stem
−
Actuator spring
−
Spring seat
−
Spring adjuster
−
Stem connector
−
Travel indicator scale
−
Cast iron yoke which fractures under sudden shock, preventing damage to the valve stem
−
Yoke to body connection.
Diaphragm actuators used by GEOSERVICES operate in the range of 3 to 15 psi or 6 to 30 psi. The size of top works used depends on the size of the valve and the working pressure (6 to 30 psi on 1440 psi separator). Automatic control valves installed on GEOSERVICES are of the throttling type and used with the proportional mode of control. VALVE BODY It is in the valve body that physical control of the fluid is achieved by means of varying the cross-sectional area for flow available to the fluid. The valve body consists of: 3-3
Pneumatic control valves −
Body casting
−
Top flange with bonnet
−
Packing flange
−
Packing box or stuffing box
−
Stem
−
Valve plug
−
Seat ring
−
Cage
THROTTLING VALVE The control mechanisms used for automatic control of the proportional type are designed to produce a linear relationship between the change in controlled pressure, or level, and the force applied to the automatic control valve to affect control. They are also designed to produce a linear relationship between the rate of change of the process variable and the rate of change of the valve-positioning force. If these two relationships exist and there is also a linear relationship between the percentage of total valve movement and the percentage of total flow resulting from any change in valve position, the result will be a good control. Automatic control valves installed on GEOSERVICES separators use an equal percentage flow characteristic. SIZING OF CONTROL VALVE The importance of correctly sizing automatic control valves is essential. From an economic viewpoint, an undersized valve cannot do the job for which it is intended and must be replaced. A valve that is too large costs more initially. As for operation, an oversized valve provides poor control and can cause system instability. The most expensive, sensitive and accurate controller is of little value if the automatic control valve cannot correct the flow properly to maintain the desired set point within acceptable table limits. The basic theory of control valve sizing may be expressed - "The flow rate of the process fluid is mathematically converted to an equivalent flow rate of a reference fluid. Then a valve size is selected which is known by test to be capable of flowing that equivalent quantity of the reference fluid at the process pressure condition specified." For liquid flow, the reference fluid is water; for gas flow, the reference fluid is air at standard conditions of temperature and pressure. Manufacturers use a valve flow coefficient Cv to provide a comparatively simple method of sizing, which is applicable to a wide variety of valve constructions, valve sizes and field services. VALVE CHARACTERISTIC The valve flow coefficient or Valve Characteristic CV is the number of US gallons of water per minute which will pass through a given flow restriction with a pressure drop of 1 psi across the valve. For example, an automatic control valve which has a maximum flow coefficient CV of 15 has an effective port area in the width open position such as it passes 15 gallons per minute of water with a 1 psi pressure drop
4-4
Pneumatic control valves across the valve. Basically it is a capacity index, which enable rapidly and accurately to estimating the required valve size in any fluid system. Inherent flow characteristic is the basic flow characteristic that is built into a given valve and is only the parameter convenient for the manufacturers to publish. Deviations from these characteristics should be expected in actual service when changes in pressure drop and other conditions are encountered. The term given to the characteristic obtained in service is "installed flow characteristic". Many factors may affect this actual relationship between valve travel and flow, with the result that the difference between inherent and installed characteristic can become quite substantial and always must be considered in the complete analysis of any control system. Valve flow characteristics are produced in control valve from the physical design of the valve plug itself, or from shaped openings in cage in which the valve plug guides. A wide variety of valve-plug and cage constructions are available, many of which exhibit the same overall flow characteristic. Valve plugs for control valve bodies and cages for balanced single plug valve fall into one of the following categories: a)
Equal percentage (used in GEOSERVICE separators)
b)
Modified parabolic, linear
c)
Quick opening.
These terms apply basically to the flow characteristic obtained when a particular style of valve plug is installed. Valve plugs may be contoured, ported, or fluted to obtain the desired characteristic. EQUAL PERCENTAGE VALVE PLUGS A valve plug that has an equal percentage flow characteristic is one in which equal increments of travel will give equal percentage changes in existing flow. The change in flow is always proportional to the flow rate existing just before the change in valve plug position is made. When the valve plug is near its seat and the flow is small, the change in flow will be small; with a large flow, the change in flow will be large. Generally, valve plugs with an equal percentage flow characteristic are used on applications where a large percentage of the pressure drop is normally absorbed by the system itself, with only a relatively small percentage available at the control valve. Equal percentage valve plugs should also be considered for those applications where highly varying pressure drop conditions could be expected. GEOSERVICES separators are fitted with FISHER single ported automatic control valve designs ED and ES valve bodies. FISHER DIAPHRAGM ACTUATOR Visual inspection of the diaphragm actuator will determine whether it is a direct or reverse acting one. 5-5
Pneumatic control valves In the direct acting type, the loading pressure is applied to the upper case section, above the diaphragm. In the reverse acting type, the loading pressure is applied to the lower case section, below the diaphragm. 1.1.3
DIRECT ACTING TYPE 657 FISHER DIAPHRAGM ACTUATOR DESCRIPTION (see figure 1) The Fisher Type 657 is a direct acting, spring opposed diaphragm actuator that is used for the operation of automatic control valves. The opening closing or throttling of the valve plug in the body is accomplished by varying the automatic loading pressure on the diaphragm. This loading pressure is transmitted from an automatic controller which may be controlling pressure, liquid level, temperature or flow. A typical Type 657 actuator is shown in figure 1. In a direct acting diaphragm actuator, an increasing loading pressure causes the actuator stem to move downward, compressing the spring. When the diaphragm pressure is decreased, the spring moves the actuator stem upward. In the event of failure of the loading pressure or the operating medium pressure to the automatic controller, the actuator stem moves to the extreme upward position.
1.1.4
REVERSE ACTTNG TYPE 667 FISHER DIAPHRAGM ACTUATOR DESCRIPTION (see figure 2) The Fisher Type 667 is a reverse acting, spring opposed diaphragm actuator that is used for the operation of automatic control valves. The opening, closing or throttling of the valve plug in the body is accomplished by varying the pneumatic loading pressure on the diaphragm. A typical Type 667 actuator is shown in figure 2. In a reverse acting diaphragm actuator, an increasing loading pressure causes the actuator stem to move upward compressing the spring. When the diaphragm pressure is decreased, the spring moves the actuator stem downward. In the event of failure of the loading pressure to the diaphragm of the actuator, the actuator stem moves to the extreme downward position.
6-6
Pneumatic control valves
FISHER DIAPHRAGM ACTUATOR (Direct acting) Type 657
Fig. 1
7-7
Pneumatic control valves FISHER DIAPHRAGM ACTUATOR (Reverse acting) Type 667
Fig. 2
8-8
Pneumatic control valves
1.2 CALIBRATION (for normally open valve) Calibration of Spring Adjusting Screw: -
Check that the spring adjusting screw is free
-
Position the indicator disc against the zero of the control scale after coupling actuator stem and valve plug stem
-
Apply 3 PSI to the Top Works
-
Screw the spring adjusting screw until disc return to zero. (The control stem actuator should not begin to move for a pressure below 3.1 psi).
1.3 DESIGNS ED, EAD, ET, EAT If a new stem is to be assembled in the valve plug, screw the valve plug until it wedges tight at the end of the valve stem thread. Determine drill size from figure 3, locate the pilot hole in the valve plug, and continue drilling the hole through the valve plug and stem assembly. Drive in the groove pin to lock the assembly. If the Design ED or EAD piston ring or the Design ET or EAT seal ring is visibly damaged, remove it and replace with a new part. Be careful not to scratch the surfaces of the ring groove in the valve plug, or the new ring may not seal properly. The Design ET or EAT seal ring must be pried and/or cut from the groove, so it cannot be used again. Grinding of metal seats, if required, should be done before installing the piston or seal ring. For Design ED or EAD bodies using a carbon-filled TFE piston ring, spread the ring apart slightly at the split and install it over the stem and into the groove in the valve plug. Graphite piston rings are furnished as a complete ring and must be broken into two approximately equal portions. Hold the ring securely and strike it across the edge of a table or bench. Be certain broken ends are re-matched when the piston ring is installed in the valve plug groove. For Design ET or EAT body, apply Molykote No 80 lubricant or equivalent to both back up and seal rings. Place the back-up ring over the stem and into the groove. Place the seal ring over the top edge of the valve plug so that it enters the groove on one side of the valve plug. Slowly and gently stretch the seal ring and work it over the top edge of the valve plug. The TFE material in the seal ring must be permitted time to cold-flow during the stretching procedure, so avoid jerking sharply on the seal. Stretching the seal over the valve plug may make it seem unduly loose when in the groove, but it will contract to its original size after insertion into the cage. When putting the valve plug into the cage, make sure the piston or seal ring is evenly engaged in the entrance chamfer at the top of the cage to avoid damaging the ring. Mount the bonnet on the body. Tighten the bonnet-to-body bolts to the recommended torque given in the following table (follow accepted bolting practices and lubricate bolts. 9-9
Pneumatic control valves
Body Size In. 1, 1-¼ 1-½-2 2-½ 3 4 6
Recommended Bolt Torque, Ft-Lb ED, EAD ET, EAT 100 104 80 75 100 104 130 130 190 191 400 404
Proper tightening of the bonnet bolts accomplished two purposes: a)
The spiral wound gasket compresses enough to both load and seals the seat ring gasket.
b)
The outer portion of the top gasket compresses so that the bonnet-to body joint forms a seal.
Note : Spiral wound gasket boltup characteristics are such that tightening of one bold may loosen an adjacent bolt. This will occur on subsequent tightening of all the bolts until the bonnet-to-body seal is made. This requires several trials on each bolt until the nut does not turn at the given torque. Mount the actuator on the bonnet and make up the stem connection according to procedure.Always ask the rig mechanic for advice in any case when the Geoservices operator has to disconnect any rig air or fluid.
10 - 10
Pneumatic control valves
SECTIONAL OF DESIGN "ED"
Fig.3
11 - 11
Pneumatic control valves
1.4 FISHER CONTROL VALVE BODIES 1.4.1
DESIGN "ED" CONTROL VALVE BODY "Globe" style body with balanced valve plug and metal seat. (Globe is a term derived from the globular shape of the body). Several calibrated orifices on the valve plug allow the downstream pressure to act simultaneously on both sides of the plug and ensure a good balance. The valve plug (see figure 3) has a piston-ring upper seal and is designed for general control applications. It ensures a tolerance of leakage no greater than 0.5 % of maximum flow-rate. The fluid action tends to close the valve. The guided and balanced plug ensures a greater stability to the system and as a result diaphragm actuator can be of a small size. Flow direction for standard and cavitrol cages is, in through the cage openings and out through the seat ring - Flow down. Equal percentage cages equip GEOSERVICES valve bodies on separator oil and gas outlets.
Note: There is an arrow on the Easy E valve body; the valve must be installed in piping with the arrow indicating the direction of flow.
12 - 12
Pneumatic control valves 1.4.2
DESIGN "ES" CONTROL VALVE BODY Design "ES" control valve body fits for all the general applications and covers a large range of temperature and pressure drop. The standard seat is metallic but an elastomer joint can be fitted. Maximum input pressure is 1440 psi for steel material and up to 64° F. Maximum pressure drop with a metallic seat is similar to the maximum input pressure up to 64° F. It ensures a tolerance of leakage no greater than 0.01 % of maximum flow rate. The leak is virtually nil with an elastomer joint. The "ES" type valve body is fitted with a microform ½" plug (equal percentage flow characteristic) and is found on 1" oil outlet and 2" water outlet from the 1440 psi separator. The ½" microform plug is guided by a cage and is only used for low flow rates. Flow direction: flow up. The fluid action tends to open the valve hut the action is very slight and doesn't need to be compensated by a larger diaphragm actuator.
Note: the arrow on the "ES" valve body must be installed in piping with the arrow indicating the direction of flow.
13 - 13
Pneumatic control valves
NORMALLY OPEN - SINGLE PORTED AUTOMATIC CONTROL VALVE (FISHER) SEPARATOR GAS OUTLET
14 - 14
Pneumatic control valves
NORMALLY CLOSED - SINGLE PORTED AUTOMATIC CONTROL VALVE (FISHER) SEPARATOR OIL OUTLET
15 - 15
Pneumatic control valves
1.5 THE PLUG The all or nothing shape is used for valves that must be fully open or fully closed, without the possibility of adjustment. The parabolic and V port shapes enable the passage section to be varied according to the rise of the plug. These forms are suitable for the adjustment of the flow rate. The set course for opening variation can be linear or exponential, in the case of a plug called an "equal percentage" plug. On separators, "Linear Parabolic" or V port plugs are nearly always used. 1.5.1
LINEAR PARABOLIC For 20% valve travels provides 20% of maximum capacity.
1.5.2
V PORT PLUG 40% of valve movement will only result in a small flow change.
16 - 16
Pneumatic controller
SECTION 11 PNEUMATIC CONTROLLERS
1-1
Pneumatic controller
1.1 LEVEL MEASUREMENT PRINCIPLES 1.1.1
Introduction
We define the level as: − The height between the free surface of a liquid inside a vessel and a reference point. − The height between the separation surface of two different liquids and a reference point. Level Measurement Principles
The measurement of liquid level is a fundamental one used in the automatic control of continuous processes. It is frequently used in conjunction with other basic measurements of temperature, pressure and flow for the control of processes in chemical and petroleum industries. Several principles of measurement are used in determining the level of liquids. The type of instrument selected being governed by the nature of the liquid, the shape of the vessel in which the liquid is contained, the pressure under which it is operating, and the application. To enable the various instruments used to quantify the measurement made, various units are used: linear units such as feet for a direct measurement of depth or pressure units such as psi for a pressure head. 1.1.2
Methods of level measurement
Level can be measured in a number of different ways. The simplicity or complexity of the instrument used will depend largely on the application of the measurement, whether it is an infrequent measurement made for long term records control of a complex process. The main types used can be grouped under the following classifications. − Visual Indicators − Float actuated instruments − Displacement type instruments
2-2
Pneumatic controller
1.1.2.1 Visual Indicators a.
b.
DIPSTICK The simplest, probably the most common method of measuring level in an open tank, is by means of a dipstick of gauge staff immersed in the liquid and marked off in contents or depth over a datum line. The dipstick although crude and simple is a very accurate method of level measurement but cannot be used for automatic recording or controlling purposes. It has many applications where a continuous indication is unnecessary buy where regular readings can easily be taken. SIGHT TUBE
The device is based on the communicating vessels principles. The two ends of a glass tube are connected to the vessel in which the liquid level is to be measured. The tube is mounted on the side of the vessel in the vertical position. The level in the tube is the same as that in the vessel. The liquid in the tube can be seen and its height can be measured with a graduated scale, which is placed behind the tube. The device is not convenient for high pressure.
3-3
Pneumatic controller
c.
SIGHT GLASS
With high pressures, a sight glass must replace the sight tube. This device is made within a steel chamber. Basically two models are available:
−
with front and back glass, allowing the passage of the light to give a clear indication of the level (transparent sight glass) − with only one glass on one side of the chamber (refracting sight glass); in this case the glass has generally longitudinal bevels on its inside to easy the reading by refracting the light. The thickness of the chamber and of the glass itself depends on the working pressure and temperature. Note: When using sight glasses, the liquid in the glass should be as clean as possible. the number of glasses used depends on the range of the level variations. As the glass may break, sight glass safety valves should always be used with sight glasses.
SIGHT GLASS SAFETY VALVE This valve is made of a body and a valve stem with a bevelled shutter acting as a tap. The stem of the valve has got a tip to push on the floating ball. The body has an inlet connected to the vessel, and an outlet directly connected to the sight glass. A handle enables positioning the stem inside the valve body. In the position shown, the shutter is away from its seat letting the passage to the sight glass open and the flow through the valve is only due to the level variations: the ball is then kept by its weight down in its groove. If the glass breaks, the flow increases very much and pushes the ball against its seat, hence insulating the sight glass, which can safely be repaired. To re-open the valve, the ball must be pushed back in its groove. This is performed by turning the handle half way clockwise in order to push the ball with the stem tip. However, this new position of the stem is not safe, impeding the ball to seat properly in case of a new failure. Hence the handle has to be returned to the initial position by turning it completely counter-clockwise.
4-4
Pneumatic controller
1.1.2.2 Float actuated instruments A class of level detectors is based on Archimede's principle. Archimede's principle states that the weight of a floating object is equal to the weight of the water displaced by the object. For an object to be in equilibrium, the upward force of buoyancy must be equal the downward force of gravity (weight). Also, the centre of gravity and the centre of the underwater volume (centre of buoyancy) must be vertically aligned.
When a rigid object is submerged in a fluid (completely or partially), there exits an upward force on the object that is equal to the weight of the fluid that is displaced by the object. Explanation: When the object is removed, the volume that the object occupied will fill with fluid. This volume of fluid must be supported by the pressure of the surrounding liquid since a fluid can not support itself. When no object is present, the net upward force on this volume of fluid must equal to its weight, i.e. the weight of the fluid displaced. When the object is present, this same upward force will act on the object.
FB = ρ fluid × Vsubmerged × g The net force on the object is given by,
Fnet ,obj = FB − Wobj Fnet ,obj = ρ f × Vsub × g − ρ obj × Vobj × g Note: When the density of the object is less than that of the fluid, the net force will be upwards and the object will rise. A Helium filled balloon is a good example. When an object is floating, the net force on it will be zero. This happens when the volume of the object submerged displaces an amount of liquid whose weight is equal to the weight of the object. A ship made of steel can float because it can displace more water than it weighs.
5-5
Pneumatic controller
FB = Wobj ρ f × Vsub × g = ρ obj × Vobj × g
Vsub ρ obj = Vobj ρf Thus the fraction of a floating object that is submerged stand in ratio to the density of the object to the density of the fluid. For objects with a vertical wall around the outside edge like a rectangle, we can reduce the above equation even farther,
A × d sub ρ obj = A × d obj ρf d sub ρ obj = d obj ρf Where A is the surface and d is the height of the object. To measure the level, based on the archimede’s principle, a hollow float is resting freely on the liquid surface and is connected by a cord, chain or thin metallic tape over a pulley to a counterbalance weight.
The float maintains a constant depth of immersion in a given liquid and rises and falls with any change in the liquid level. In doing so, it drives a pulley, which operates an indicating, recording or control mechanism to show the changes in level. Turbulence in the liquid can be prevented from affecting the float by the addition of a stilling well around it. This device cannot be used for applications where the liquid is under pressure. Here, some method of transferring the position of the float through the container wall is needed.
6-6
Pneumatic controller A caged float controller is used for pressurized applications.
A float and lever contained in a metallic cage, which is connected to the pressurized vessel, follows any variations in level. This movement is transmitted through the cage by a shaft rotating in a gland or stuffing box to a counterbalance lever outside the cage. This outside lever can operate a pneumatic controller or can be directly linked to a control valve regulating the low of liquid into or out the vessel.
1.1.2.3 Displacement type instruments The level detector, here, is a displacer usually produced for a cylinder with closed ends which is pressure tight. The displacer is denser than the liquid and therefore sinks in the liquid being measured. The actual measurement made is the apparent weight of the displacer, which decreases as the liquid level rises. The loss in weight is equal to the weight of liquid displaced, which in turn is governed by the volume of the displacer and the height of the fluid level relative to the bottom of the displacer. To exemplify this concept, a displacer of weight Wd and volume V is suspended to a scale and balanced by a counter weight Wa.
The apparent weight is given by:
Wa = Wd − Fup 7-7
Pneumatic controller
Wa = Wd − (Vsub × ρ f × g ) = Wd − (A × L × ρ f × g ) Where A is the area of the displacer and L is the height of the liquid relative to the bottom of the displacer. As a consequence the apparent weight is inversely proportional to the level. So, this device can be used as a transducer with the level indicated by a force. In practice, the scale is replaced by a dynomemetric system. The apparent weight of the displacer is measured by a torsion spring known as a torque tube assembly, which transforms the weight variations into an angular movement of a torque tube shaft. The angular movement can be used to drive a pneumatic or electronic transmitter or controller, producing an indicating or controlling output signal in direct proportion to the liquid level from the bottom of the displacer. The principle of the torque tube is schematically given in the figure.
One end of the tube is fixed on a flange while the free end is connected to the displacer arm, which is acting as a lever. The apparent weight Wa of the displacer, applies to the tube a torque T:
T = Wa × l Where l is the length of the displacer arm.
T = (Wd − Fup )× l = (Wd − A × L × ρ f × g )× l
Where A is the area of the displacer and L is the height of the liquid relative to the bottom of the displacer.
8-8
Pneumatic controller As a consequence, the tube twists by the amount (for small valves of temperature) of:
α=
T K
Where K is the constant of torsion of the tube The torque tube behaves like a spring where the force is replaced by the torque and the linear displacement by the angular displacement. Inside the tube, a rod is welded to the closed end of the torque tube and is free to rotate at the other end. This rod transmits the tube rotation out of the flanged end. The system is therefore very well suited for a perfect sealing.
LIQUID GAS INTERFACE From the previous relations, we get:
α=
(Wd − A × L × ρ
f
× g )× l
K
So when the liquid level L builds up around the displacer, its apparent weight decreases and, as a consequence, so does the angle a. Obviously, if the level is below the bottom of the displacer or above its top, no further change in the apparent weight takes place and therefore, no further indication of level change is possible. The total variation in level measurement is therefore, governed by the height of the displacer. If for the same torque tube, the height is increased, the section has to be decreased consequently so as to keep the total volume of the displacer constant. Note: The zero of the device is independent from the density of the liquid. The total deflection depends on the length of the displacer and on the density of the liquid. As the angular variation of the output is very small, an amplifier will be needed to give a readable output signal. The same device can be used to ensure liquid density, provided the displacer is all the time completely immersed in the liquids.
LIQUID-LIQUID INTERFACE Displacement units can be also used to measure the position of the interface between two immiscible liquids having different specific gravities. This is commonly down to measure the interface between oil and water in a separator to allow the oil and water to be drawn off the vessel individually. In this application, it is essential that the displacer is always submerged in liquid.
9-9
Pneumatic controller
1.2 PNEUMATIC CONTROLLERS Pneumatic controllers are designed to detect a variation in the system to be controlled and to transform this into a pressure impulse controlling the valve displacement to correct the variation. The system to be controlled can be a pressure or the level of a fluid. The Bourdon Tube detects the pressure variation. The float meausures the level of the fluid. These mechanisms act on a nozzle-flapper system. 1.2.1
Nozzle-flapper system
This system is supplied with air/gas under constant pressure controlled by a FISHER 67 FR REGULATOR. The gas pressure acting on the valve is adjusted by a restricted orifice A and a nozzle B, that can be more or less blocked by a flapper P, pivoting on a fixed point O. The flapper is mechanically linked to the detection mechanism (float or Bourdon Tube). Orifice A is much smaller than nozzle B (about half its diameter) so that when the flapper is away fro the nozzle, the gas is vented faster than the incoming flow and no pressure builds up. When the flapper blocks nozzle B, the pressure can build up in the system and be transmitted to the D.M.V. There is a risk that the valve reply time would be unsuitable for the oil flow rate or the variation in pressure and so a power relay is used to accelerate the nozzle-flapper system reply time.
10 - 10
Pneumatic controller
1.3 LIQUID LEVEL AND INTERFACE MEASUREMENT AND CONTROL Fisher Level Trol (Type 2500 - 249 V)
11 - 11
Pneumatic controller
RIGHT HAND MOUNTED TYPE 2500 PROPORTIONAL CONTROLLER
12 - 12
Pneumatic controller 1.3.1
Role
This equipment is designed to operate in conjunction with a normally closed automatic control valve in controlling the liquid level in a continuously supplied vessel. 1.3.2
Principle of design
The float-displacement-type level-measuring instrument is based on the apparent change in weight of a body when it is placed in a liquid. According to Archimedes' principle, a body placed in a liquid is buoyed up by a force equal to the weight of the displaced liquid. 1.3.3
Description
It is composed of three basic elements: − A plunger − A torque tube − Regulation and supply equipment PLUNGER The plunger (volume 100 cu. ins., weight 4 3/4 lbs) is made of stainless steel. TORQUE TUBE ASSEMBLY the torque tube assembly consists of the rotary shaft and the torque tube itself. The rotary shaft is usually made of steel but it can be Monel or Iconel. The rotary shaft converts the Archimedes' upthrust into angular displacement of the flapper. Note: since the torque tube-plunger assembly is fitted under tension with the torque tube attempting to raise the plunger, the lower the liquid level, the greater the couple on the torque tube.
REGULATION AND SUPPLY SYSTEM This consists of six parts: 13 - 13
Pneumatic controller
− − − − −
a case (or pilot) a flapper directly coupled to the rotary shaft an amplifier relay a proportional control valve a liquid level set point may be adjusted over a graduated disc and which acts directly on the position of the nozzle mounted on the end of a Bourdon tube. (this set point allows the desired level of liquid to be selected in advance providing that it lies between the top and the bottom of the plunger.) − two pressure gauges indicating the supply and outlet pressures of the controller. PRINCIPLE OF OPERATION The apparatus is provided with an air pilot supply at a pressure of 20 psi and an outlet pressure is converted in the range between 3 to 15 psi. DECREASE IN LEVEL Decrease the level in the separator, the upthrust on the plunger decreases, increasing the torque on the torque tube which thus rotates. The flapper which is fixed to the rotary shaft, rotates away from the nozzle increasing the amount of air vented to the atmosphere. This causes a decrease in pressure in chamber 'L', which causes the diaphragm assembly to move upward, opening the exhaust valve 'K' and allowing the pressure in chamber 'N' to bleed out to atmosphere. The pressure in the D.M.V. valve decreases, closing the valve and allowing the liquid level to rise until it reaches the set point. As shown schematically, the pressure from chamber 'N' goes to valve and to the proportional band adjustment three-way valve 'G'. The orifice of this three-way valve is adjustable so the amount of feed-back to the Bourdon Tube can be set to the amount desired. So, at the same time, the pressure in the Bourdon Tube is being decreased through the three-way valve, causing the nozzle to move closer and build-up the pressure in the system. The unit is again i equilibrium with the level. INCREASE IN LEVEL When we have an increase in level, it means that we have an increase in pressure output to open the valve. (The reverse action as mentioned above is taking place.) THE PROPORTIONAL BAND The proportional band of a liquid level may be defined as the number of inches of level change necessary to stroke the control valve.
14 - 14
Pneumatic controller
SCHEMATIC ILLUSTRATION OF TYPE 2500-249 V FISHER LEVEL CONTROLLER
15 - 15
Pneumatic controller FLOAT AND FLOAT ROD ON RIGHT OF TORQUE TUBE
A. The rise in level makes the float rise. When the flapper moves away from the nozzle, it causes a drop in output pressure applied on the control valve. B. The rise in level makes the float rise. The flapper nearer the nozzle causes a rise in output pressure.
FLOAT AND FLOAT ROD ON LEFT OF TORQUE TUBE A. The rise in level makes the float rise. The flapper moves nearer the nozzle causing a rise in output pressure applied on the control valve. B. The rise in level makes the float rise. The flapper moves away from the nozzle causing a drop in output pressure applied in the automatic valve. Oil and water level on the separators used, are always controlled by normally closed valves and regulators will have to be fitted for direct action. (Rising level _ Increase in output _ Valve opens.)
16 - 16
Pneumatic controller
1.4 LEVEL TROL FOR 600/720 PSI SEPARATOR Model: Mounting: Action: Supply pressure: Black bourdon tube Output pressure range:
2500 - 249 v right hand direct acting 22 psi 3 to 15 psi
17 - 17
Pneumatic controller
1.4.1
Calibration in the shop
− − −
Check that the supply pressure is 22 PSI. Set proportional band adjustment on 100%. With substitute weight WL (lowest level) in place on the displacer rod, adjust the raise level dial to give 3 PSI output pressure. − Remove substitute weight WL and replace it with substitute weight WH (highest level) on the displacer rod. − The output pressure should be 15 PSI. If not it can be adjusted by sliding the level set arm i the elongated slot. This action changed the sensitivity of the nozzle flapper system. Sliding the level set arm to the left increases the sensitivity and increases the output span. − Remove weight WH and hang weight WL. Reset the output pressure to 3 PSI by adjusting the raise level dial. Repeat the above steps (4 and 5) and relocate the level set arm again until the required output pressure span is obtained. − Set the raise level dial to 3.0 to 3.5 and the proportional band to 10%. With substitute weight WL on the displacer rod observe the output pressure that should be 3 PSI. If not, adjust the flapper clamp nut and alignment screw to obtain the proper output pressure. This adjustment will insure that any proportional band at any level may be set without further flapper adjustment. Note: If the Level Trol cannot be calibrated it is necessary to look for other troubles such as non perpendicular flapper-nozzle condition, leaky connections, binding displacer rod, damaged bourdon tube or even a torque tube sized for a different set of service conditions.
18 - 18
Pneumatic controller
1.5 LEVEL TROL FOR 1440 PSI SEPARATOR Model Mounting Action Supply pressure Red bourdon tube Output pressure range: 1.5.1
2500 - 249 v right hand direct acting 36 psi 6 to 30 psi (3 - 15 psi)
Calibration in the shop
− − −
Check that the supply pressure is 36 PSI (20 PSI if 3 - 15 PSI). Set proportional band adjustment on 100%. With substitute weight WL (lowest level) in place on the displacer rod, adjust the raise level dial to give 6 PSI output pressure. − Remove substitute weight WL and replace it with substitute weight WH (highest level) and the displacer rod. − The output pressure should be 30 PSI. If not it can ba adjusted by sliding the level set arm in the elongated slot. This action changes the sensitivity of the nozzle flapper system. Sliding the level set arm to the left increases the sensitivity and increases the output span. − Remove weight WH and hang weight WL. Reset the output pressure to 6 PSI by adjusting the raise level dial. Repeat the above steps (4 and 5) and relocate the level set arm again until the required output pressure span is obtained. − Set the raise level dial to 3.0 to 3.5 and the proportional band to 10%. With substitute weight WL on the displacer rod observe the output pressure that should be PSI. If not, adjust the flapper clamp nut and alignment screw to obtain the proper output pressure. This adjustment will insure that any proportional band at any level may be set without further flapper adjustment. Note: If the Level Trol cannot be calibrated it is necessary to look for other troubles such as non perpendicular flapper-nozzle condition, leaky connections, binding displacer rod, damaged bourdon tube or even a torque tube sized for a different set of service conditions.
19 - 19
Pneumatic controller
1.6 GEC-ELLIOTT CONTROL VALVES LIMITED TYPE 2900 LIQUID LEVEL CONTROLLER 1.6.1
Introduction
Fisher combines economy and quality to provide a rugged liquid level controller for oil production field processing systems. The displacement principle is used in the detection of liquid level of specific gravity interface. The units are available as either snap acting or proportional (throttling) with direct or reverse action. 1.6.2
Construction features
PILOTS Type 2900 − The Type 2900 internal pilot relay action is easily changed between snap acting and throttling by inverting the switching block, marked with a "T" in Figure 2 to the side marked "S" without additional parts. − Adjustment of the relay nozzle pressure is all that is required to calibrate the Type 2900. Using the nozzle pressure gauge, the Type 2900 can be dry float adjusted for accurate blind level operation. − The Type 2900 is resistant to operational vibration, especially wave motion and compressor pulsation. − The liquid level controller was designed with rugged service demands in mind. The pilot assembly is completely enclosed in a sturdy case with gauge windows for both "Supply" and "Output" pressure gauges. Double connections are also provided for piping convenience. − The Type 2900 is easily converted from direct to reverse acting by rotating the controller 180° on the sensor assembly or by rotating the entire unit 180° on the vessel. Conversion can also be accomplished by changing from a 2900 nozzle to a 2901 style or vise versa. See Figure 3. Type 2901 The Type 2901 pilot was designed for snap action on gas applications where supply gas must be conserved. This pilot incorporates a small, 3-way valve in the nozzle to provide intermittent bleed only. All other construction is the same as the Type 2900. CONTROL SENSORS Type 244V The sensor consists of a K-monel flexure tube secured to a carbon steel mounting hub. The flexure tube assembly is fabricated to provide a hermetic seal. Therefore it has no packing box and needs no lubrication or packing maintenance. The control sensor has a maximum working temperature of 140°F with the standard plastic displace. Type 279V The Type 279V is basically a Type 244V as shown in Figure 4 with a shorter flexure tube assembly for smaller I.D. vessels. Type 279VBU The Type 279VBU is an external cage mounted unit incorporating the short flexure tube. DISPLACERS 20 - 20
Pneumatic controller
Displacers are available in solid plastic (6000 psig max. working pressure) or optional 304 SST (1440 psig max. working pressure) for either horizontal or vertical mounting. Type
Hub.Size (inch) 2
244 V 279 V 279 VBU
3&4 2 2
Displacer Size (inch) 1-7/8 X 12 1-7/8 x 12 2-3/4 x 8 1-7/8 x 9 1-7/8 X 9
Material Plastic 304 SST X X X x X X X ... X ...
X-available. Special displacers can be provided on request.
Principle of operation: − Direct Acting Increasing process level gives an increasing controller output − Reverse Acting Decreasing process level gives an increasing controller output PROPORTIONAL CONTROL
21 - 21
Pneumatic controller
DIRECT ACTING Supply pressure of 20 to 50 psig is supplied to chamber "A". On rising level, disc "B" moves to restrict nozzle opening "C" and pressure builds on diaphragm "E". When the force on diaphragm "E" is great enough to overcome the force of the relay springs, the diaphragm assembly moves toward the inner valve "H" closing exhaust port "G". Both exhaust "G" and supply "F" are now closed. As the diaphragm assembly continues to move, supply port "F" opens to pressurize chamber "J" and the control valve. Diaphragm "K" is now pressurized with a force opposite of diaphragm "E". Since chambers "L" and "M" are vented to atmosphere there is no influencing force on diaphragm "N". Diaphragms "K" and "E" seeking an equilibrium, enable proportional control. As the process level drops, disc "B" moves away from nozzle "C". The force across diaphragm "K plus the force of the relay spring is now greater than the force on diaphragm "E", the diaphragm assembly moves down, closing supply port "F". As the pressure on diaphragm "E" continues to decrease, exhaust port "G" opens and allows the pressure on the control valve diaphragm to bleed to atmosphere. REVERSE ACTING For reverse acting proportional control, the principle of operation remains the same but the controller assembly is mounted on top of the flexure tube assembly. This enables an increasing signal to the control valve diaphragm on decreasing liquid level. SNAP-ACTING CONTROL
DIRECT ACTING
With increased level, nozzle "C" is open and 20 to 50 psig supply pressure is in chambers "L" and "J" ad loading the control valve. The pressures on diaphragm "K" are opposite and equal. The pressure on diaphragm "N" is upward because chamber "M" is vented to atmosphere. As the liquid level decreases, disc "B" will cover nozzle "C". This causes pressure to build up on diaphragm "E" overcoming the relay spring and the opposite force on diaphragm "N". The increased pressure on diaphragm "E" closes supply port "G" and opens exhaust port "F". Chamber "J" and the control valve loading pressure are vented to atmosphere. With chamber "J" 22 - 22
Pneumatic controller
vented to atmosphere, the forces in chamber "L" on diaphragms "N" and "K" are opposite and equal. The relatively unopposed force o diaphragm "E" now causes the pilot to snap closed. As the liquid level increases, disc "B" will uncover nozzle "C". This bleeds the pressure from diaphragm "E". The relay sprig close exhaust port "F" and open supply port "G". chamber "J" is pressurized and the forces on diaphragm "K" are neutralized again. The unopposed pressure on diaphragm "N" causes the pilot to snap open. REVERSE ACTING For revere snap-acting control, the principle of operation remains the same but the controller assembly is mounted below the flexure tube assembly. This ensures an increasing signal to the control valve diaphragm on decreasing liquid level.
23 - 23
Pneumatic controller
1.7 FISHER CONTROL VALVE ASSEMBLY TYPE 4150 Let us assume that a pressure drop occurs in the separator. The Bourdon Tube contracts and brings the flapper towards the nozzle. The nozzle will be partially blocked and pressure will build up in chamber 'H' of the FISHER relay due tot he constant air supply through restriction 'F'. The pressure build-up pushes diaphragm 'G' upwards, opening relay valve 'K' and allowing the inlet pressure to flow to the automatic valve through chamber 'J'. The pressure in chamber 'J' builds up, tending to push the diaphragm down and close relay valve 'K'. The pressure in chamber 'J' is transmitted to the D.M.V. and the valve throttles closer to its seat. The diaphragm ratio between 'H' and 'J' is 3 : 1. At the same time, the pressure that is relayed to the valve is relayed to a bellows chamber 'E', which pushes the flapper away fro the nozzle and allows air to vent from nozzle 'D', stopping the pressure build-up in chamber 'H'. The pressure relayed to bellows chamber 'E' is adjusted by a three-way valve, called the Proportional Band Valve. By this, we can see that a number of cause ad effect situations are happening simultaneously, some to increase the pressure to the D.M.V., and some to decrease it. If the pressure in the separator rises, the flapper moves away from the nozzle, venting pressure in chamber 'H', thus causing the pressure in chamber 'J' (and the pressure in the D.M.V. to bleed to atmosphere via the small valve 'L'. The loss of pressure in chamber 'J' is also transmitted to bellows 'E', causing the flapper to move closer to the nozzle. Note: Although output from the relay valve may vary from 0 - 20 psi, and the 3 - 15 psi range is useful because it is within this range that the D.M.V. valve works i.e. at 3 psi on the gas D.M.V., the valve is fully open and at 15 psi the valve is fully closed. Therefore, the wizard is calibrated to give 3 psi output at 100% of the Bourdon Tube range and 15 psi at 0% of the Bourdon Tube range. As shown schematically, the output pressure from relay chamber 'J' goes to the control valve diaphragm and also the proportional band three-way valve 'M'. The orifice in this valve can be set to the amount of feed-back desired to proportional bellows 'E'. When valve 'M' is fully open, all the diaphragm pressure is transmitted to bellows 'E'. Beam moves away from nozzle 'D', stopping the pressure build-up in relay chamber 'H'. This produces 100% proportional band based on the rating of the Bourdon Tube.
PROPORTIONAL BAND This is the percentage of the controlled pressure variation, in relation to the capacity of the Bourdon Tube, capable of causing the complete stroke of the valve. This pressure variation is independent of the controller's set point pressure. Example: A wizard is equipped with 1000 psi Bourdon Tube. The set point is at 400 psi, Proportional Band 10%. The valve plug will stroke completely for a pressure change of: 1000 x
24 - 24
10 = 100 psi 100
Pneumatic controller
So the valve will stroke completely between 350 psi and 450 psi.
DIAGRAM OF FISHER RELAY
25 - 25
Pneumatic controller
FISHER TYPE 4150 WITH PROPORTIONAL ACTION
PROPORTIONAL BAND ADJUSTMENT, SUB-ASSEMBLY
26 - 26
Pneumatic controller 1.7.1
Pressure controller fisher wizard ii (type 4150)
CALIBRATION Material required − 200 psi pilot air supply − Dead Weight Tester − Precision pressure gauge (preferably a mercury column) ADJUSTMENT OF PRESSURE RANGE − Adjust proportional band to 100% (10). In this position, application of 100% Bourdon Tube nominal pressure should move the valve from fully closed to fully open. − Adjust set point to give an output of 15 PSI with no pressure applied to the Bourdon Tube. − Apply 100% nominal pressure to the Bourdon Tube when the output should fall to 3 psi. If it does not, adjust the nozzle block to left or right to obtain 3 psi. − Adjust until, for a fixed point, application of 100% nominal pressure will give a range of 3 - 15 psi. ADJUSTMENT OF SET POINT − Adjust proportional band to 10% to give sensitive control. − Adjust set point to 50% of scale. − Apply 50% of nominal pressure to the Bourdon Tube. − Adjust the height of the nozzle to give an output of 9 psi. Note: Do not raise the nozzle more than 0.07" because the Allen screw will cut the "O" ring seal.
Once the calibration is complete, check that: − with the set point just above zero and no pressure on the Bourdon Tube, the output is 3 psi (or less). − with the set point just below 100% nominal pressure on the Bourdon Tube, the output is 15 psi (or more). PROPORTIONAL BAND TEST From the definition of proportional band, application of 25% of nominal pressure to the Bourdon Tube, with the proportional band at 25%, should give 3 - 15 PSI change in the output pressure. − Adjust to 25% proportional band − Adjust set point to give 15 PSI output − Apply 25% nominal pressure to Bourdon Tube − Output should be 3 PSI or less. − Maintain 25% proportional band − Adjust set point to give 15 PSI output − Apply 50% nominal pressure to Bourdon Tube − Output should be 3 PSI or less.
27 - 27
Pneumatic controller
−
Increase to 75% nominal pressure, adjusting as above and check for 3 PSI or less. − Adjust as above, apply 100% nominal pressure and check for 3 PSI or less. TESTING BELLOWS ALIGNMENT − • Put proportional band close to zero, with no pressure on the Bourdon Tube − • Adjust set point to give 9 PSI output − • Mark position of set point on scale − • Apply 100% nominal pressure to Bourdon Tube − • Adjust set point to give 9 PSI output − • Mark the position of the set point on the scale The two marks should be at approximately the same distance from the 50% line. If this is not so, it is necessary to change the bellows which may have been subjected to excess pressure or other cause of damage. Note: If the nozzle is positioned for direct action, then read 15 PSI for 3 PSI and vice versa.
FIELD REGULATION − Ensure that the valve supply pressure to the Bourdon Tube is fully open. − Ensure that the supply pressure is set at 20 PSI. − Adjust proportional band setting to 10% for safety. − Adjust set point to give 15 PSI output to close the valve. − Check for correct operation of the controller by moving the Bourdon Tube manually. A small deflection should give a large alteration in output pressure. − Adjust proportional band to a value giving minimum pumping and alteration in differential pressure for a relatively constant static pressure.
28 - 28
Pneumatic controller
MAINTENANCE Two important points: − Draining the pressure reducer filter bowl occasionally to prevent liquid interfering with controller operations. A small drain valve is fitted for this purpose. − Clean the restrictor orifice occasionally by pressing the pin to allow free passage of pilot air through the relay orifice. OPERATING INCIDENTS Failure to obtain complete pressure range to the control valve: − Ensure that the output pressure gauge reads correctly − Check for faults in the lines and unions. Pressure pulsations on the output pressure or cycling: − The proportional band being set too low can produce cycling at the outlet of a controller. − Check that the valve is not blocked or seized by a foreign body (hydrates etc.) − If the valve plug operates too close to the seat, the valve is probably oversized. FAULTS − Linkage broken between Bourdon Tube and flapper. − Ruptured relay diaphragms.
29 - 29
Pneumatic controller
FUNCTIONAL DIAGRAM OF A CONTROL VALVE ASSEMBLY
30 - 30
Pneumatic controller
DIAPHRAGM ASSEMBLY (Standard Temperature only)
31 - 31
Oil volume
SECTION 12 OIL VOLUME (TANKS AND METERS)
1-1
Oil volume
1.1
TANKS Tanks come in two varieties. 1. Atmospheric gauge tanks 2. Pressurised surge tanks. The tank on a test, serves one of three purposes: 1.
To calibrate the meters on the separator
2.
To measure oil flow rate when the flow rate is less than the minimum for the meters on the separators.
3.
To measure the shrinkage/meter factor combined.
Why two types of tank?
1.1.1 Gauge tank The gauge tank operates at atmospheric pressure. It normally has two compartments of 50 bbls each, with hatches and vents on the roof. There are two compartments so that when the tank is being used for flow calculation, the measurement of flow rate does not have to stop while the tank is being emptied. (One compartment is emptied while the other is used for measurement.) The tank is fitted with sightglasses so that the level can be read without the necessity of dipping the tank. The tanks are normally rectangular and have a calibration coefficient marked on a plate. Advantages:
Simple design, can be dipped if sightglasses are plugged, or if you have oil and water in tank. Relatively cheap.
Disadvantages:
Cannot be used with H2S. Cannot accept any pressure inside.
Safety:
As mentioned above they should never be used in the presence of H2S. (Even if the material is stamped as being H2S.) The vent lines on the roof are fitted with flame arresters. The vent hoses should be run to a safe area. (Overboard on an offshore job.) It should be noted that in certain areas atmospheric gauge tanks are forbidden offshore. There is a connection on the roof that allows connection to a foam supply. Never, never pressurize a gauge tank, they have been known to explode. There is a weak point in the roof that will normally give first in the case of over-pressure. Never flow the well directly into a gauge tank without passing through the separator. (Clean up) If a client insists, maintain a small choke and have someone on the oil manifold at all times.
2-2
Oil volume
1.1.2 Surge tank The surge tank is normally a vertical, 100 bbl single compartment tank that can operate up to 50 psi. This makes it ideal for work with H2S. the gas line is taken along the boom, or to the pit with the separator gas line. The tank is fitted with a graduated sightglass so that volumes can be measured. The tank is also fitted with a safety valve and rupture disc. Advantages:
Pressurised, for use with H2S, possible to measure GOR2 if an orifice meter and control valve are fitted on gas outlet line. This tank can be used for measuring clean up returns, because it is a pressurised vessel.
Disadvantages:
Cost, only single compartment. Unable to dip tank.
3-3
Oil volume
THE 35 BBL/100 BBL Surge Tank
4-4
Oil volume Safety
Check the validity of the official test documentation of the surge tank Check the setting of the safety valve before starting operations Check the condition of the rupture disc. Tanks must be earthed and the resistance value checked. 2 (minimum section of 1 cm cable ) Ensure an unrestricted flow from the vessel is available before flowing in. Empty all liquids before flowing in and be beware of any residual H2S. Any residual liquid or gas must be evacuated with steam before working inside a tank or any welding job on the equipment. Flushing with water is NOT sufficient. Breathing apparatus is mandatory when entering or working inside a tank. Empty tanks and vessels prior to transportation or lifting. The flow rate should always be limited so as not to fill the tank too rapidly, 30 min. filling time is a reasonable figure, it corresponds to 3800 bbl per day or 160 bbl / hr. for the 100 bbl surge tank. Never fill the tank above 80 % of it's capacity. A flowrate of 1350 bbl per day is the maximum for the 35 bbl surge tank. In case of the calibration of a 3" vortex flow meter the flow rate has to be increased to 5000 bbl / day, but the flowing time has to be reduced accordingly, in all cases someone should be on standby near the tank to divert the flow from the tank if necessary. A surge tank must be used whenever H2S is expected or suspected during a test. A wizard press. controller acts on an normally open automatic control valve and regulates the pressure inside the surge tank , the gas is evacuated to the flare line. This valve closes whenever the pressure is below 40 psi. if the wizard is set correctly, the valve will be fully open if the pressure inside the tank exceeds 70 psi. The liquid level is adjusted manually so constant supervision is still required, HI - LO pilots are installed to indicate if the level is above or below pre-set limits. A safety valve and a rupture disc on top of the surge tank can prevent the bursting of the tank due to excess pressure. Never tie the surge tank gas line into the separator gas outlet. Never fill the tank beyond 80% of its capacity. Ensure the tank and flare knock-out drum is grounded. Offshore an earth strap bolted to the deck. On land, an earth stake driven into the ground. In dry climates water the earth stake daily!. Earth straps should have a .cross sectional area of at least 1 cm2 5-5
Oil volume Check the operation of the Hi-Lo level alarms. Lifting or transportation of the equipment shall only be performed with the tank empty. operational position is vertical, transport position horizontal. The tank and flare knock-out drum should only be lifted by the lifting eyes set in the frame. Pipe the drain from the flare knock-out drum to the flare pit. Technical data SURGE TANK
SURGE TANK
100BBLS
35 BBLS
Capacity
16 M3
5.6 M3
Dimensions overall
7.800mm X 2.380mm X 2.700mm
6.600mm X 2.380mm X 2.700mm
Dimensions vessel
5.800mm X 1.300m ∅
4.000mm X 2.000mm∅
Working Pressure
70 PSI
70 PSI
(4.8 bars)
(4.8 bars)
-29 to + 40 Deg C
- 29 to + 40 Deg C
Inlet
3" Fig 206 Female
3"Fig 206 Female
Outlet gas
3" Fig 206 Male
3"Fig 206 Male
Outlet oil
3" Fig 206 Male
3"Fig 206 Male
Safety valve line
Piped into gas outlet line
Piped into gas outlet line
Drain
Piped into oil outlet line
Piped into oil outlet line
Specifications
Working Temperature CONNECTIONS
1.1.2.1 Operation of the Surge Tank 1. The tank is used to calibrate oil meters, or measure oil flow on wells, which have a flowrate less than the minimum rate for the flowmeters of the separator. 2. To this end, a tank calibration is marked on a plate on the side of the vessel. 3. The tank is fitted with graduated sight glasses so that volumes can be measured. 4. Flowrates should be limited, so as not to fill the tank to rapidly. A filling time of 30 minutes is normal. there should always be an operator in close proximity to the tank while it is filling. 5. When calibrating flow meters setting an initial liquid level just above the manhole is recommended, as the manhole can give significant errors in volume calculations.
6-6
Oil volume 6. Check operation of the HI - Lo level alarms before starting test. To start from a completely empty tank, the Lo-Level alarm has to be bypassed until the liquid level is above the Lo - Level sensor. 7. The filling and emptying of the tank must be supervised at all times. 8. The pressure in the tank is insufficient for burning to a burner. The transfer pump must be used to empty the tank. Note : When using tank for meter calibration ensure "O" level is above manhole cover. (Manhole can give significant error). Check date and condition of rupture disc. Ensure the gas outlet line goes to pit or along to end of burner boom.
7-7
Oil volume
1.2
SHRINKAGE TESTER The shrinkage factor can be calculated in a laboratory, but it is simple to find it by means of an instrument called the shrinkage tester that is connected to the separator.
1.2.1 Principle It is a calibrated container into which oil can be admitted under the same conditions as the separator. The oil is then slowly decompressed and the shrinkage value can be read off directly, expression %, form a graduated scale.
8-8
Oil volume
1.2.2 Shrinkage tester operations Refer to below Shrinkage tester diagram
9-9
Oil volume Before starting shrinkage measurement, flush the sight glass 3 times to bring fresh oil into the sight glass. (In the case where the shrinkage tester is connected to sight glass. On some separators the shrinkage tester is tied into the oil line) a. b. c.
Check that all valves are closed. Open valves V1, 2 and 9 and thereby pressurize the tester. Close V9 and open V12 to sweep the separator of any gas from previous measurement. d. Close V12. Repeat steps b and c 3 times. e. Open V9 again and pressurise tester. Open valves V5, 7 and V11 and thereby slowly begin to fill tester. f. When the level reaches the bottom of the tester sight glass close V11 and V9 open V12 and flush the tester contents to a bucket. This flushes the lines and tester with fresh oil. g. Open V9 again, then open V11 and slowly begin to fill the tester. h. When the level reaches the "O" mark on the tester, close valve V11 and V7. Close also V2 and V9. i. If level is above "O" mark, proceed as follows: Very gently open V12 and VERY SLOWLY drop level. At "O" mark close V12. Monitor tester pressure, ensure it comes back to separator pressure. Leave 2-3 minutes to stabilize. j. If level is below "O" mark (Separator level low), proceed as follows: Open V7 and V11, then open VERY SLOWLY V10, level will be "pulled up" very Monitor tester pressure, ensure it comes back to separator pressure. Leave 2-3 minutes to stabilize. k. At this point all valves on the shrinkage tester should be closed. (Including V2 V7 on sight glass.) l. Open VERY SLIGHTLY valve V10 to allow the sample to slowly degas. The nozzle, which makes it easier to control the rate of degassing. m. The level in the tester will fall, after decompression is complete (+/- 1-2 hours) the shrinkage value can be read of the scale, directly in percent. The final temperature shall also be read, this temperature shall be used to calculate the "K" (VCF) factor. (Volume reduction)
1.3
OIL FLOW RATE MEASUREMENT (FLOCO METER) Oil flow rate coming from separators can generally be measured by gauging the reception tank or flowing the oil through a positive flow meter.
1.3.1 Gauging the reception tank (stock tank) The producer is only interested in the amount of stock tank oil the well is producing i.e. degassed oil at 60°F and 14.73 psi. This is a very accurate method of measurement. If the oil has passed through a separator, only the tank temperature will need to be taken into account (BSW and shrinkage will not be factors)
1.3.2 Positive flow meter Generally most positiv Floco meter. Some correction factors have to be included in the oil flow calculations for: •
amount of volume reduction due to gas entrained in the oil (shrinkage).
•
amount of volume reduction due to water and solids in the oil (BSW).
10 - 10
Oil volume •
temperature of the oil. apparent flow rate.
•
the oil in the separator is under pressure and the apparent oil flow rate is greater.
An increase above 60°F of the oil increases the
11 - 11
Oil volume
1.3.3 Floco Flowmeter DESCRIPTION Type
:
F 2500-2
Service
:
H2S - 720 PSI WP
Liquid meter dia.
:
2" (3")
Ends
:
flange ASA 300 LBS RF
Flow rate
:
3 - 60 GPM (90)
Non reset register - 7 wheel totalizer readout in U.S. barrels No. 3059 Overall length face-to-face :
12 - 12
304,8 mm
Oil volume LAYOUT
13 - 13
Oil volume
N° 1 2 3 4 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49
14 - 14
DESCRIPTION Body bolt, 3/8 - 24 x 1 1/4 Soc.Hd Washer, 3/8 Flat Nut, blind O-ring, bearing seal Nut, bearing Sideplate, register-side, plain-side Wearplate Rotor bearing Hinge Pin, Rotor Rotor Hinge Assembly Spring Spring grommet Hub Assembly Wedge O-ring, body seal Liner Meter Body Dowel pin Bridge Seal (set of two) Bridge Drive Screw Nameplate Bridge screw, 5/16 -18 x 7/8 Soc.Hd Bridge screw washer Bushing, O-ring Drive pin Drive coupling and shaft assembly Magnet, drive E-ring Housing, bearing assembly O-ring, Buna-N Magnet, driven, assembly Drive pin Worm Screw, 10-32 x 1/2 Register adapter assembly Worm gear assembly Calibration gear, drive (See Section 5.2) Calibration gear, driven (see Section 5.2) Register assembly Not Required Register gasket Gasket, Seal Glass Register Retainer, Register Glass Register Box Assembly (includes Items 43, 44, 45, 48 & 49) Lid, Register, Housing Pin Register Lid
Oil volume
CALIBRATION GEAR CHART
15 - 15
Oil volume
1.3.4 Ball Vortex Liquid Meters (Rotron) (Oilgear) PRINCIPLE The liquid flowing through the meter creates a VORTEX in an offset chamber. The VORTEX rotational velocity is proportional to the flowrate and is measured directly on a readout meter which is driven by the rotor through a magnetic coupling.
ACCURACY Factory Calibration
± 0.5% of reading
Repeatability
± 0.2% of reading
BALL BEARINGS
SLEEVE BEARINGS RANGE
2" - 850 to 6850 bbls/d 3" - 2050 to 17000 bbls/d
16 - 16
700 to 8500 bbls/d 3400 to 22000 bbls/d
Oil volume CONSTRUCTION Roots Vortex Series P liquid meters are manufactured in five pipe sizes - 1", 2", 3", 4" and 6" - and in a variety of materials and bearings types. They are intended for handling clear liquids at flow rates, pressures and temperatures within their nameplate ratings. The construction of a Roots Vortex meter is described by its model number. The diagram on the following page explains the Model Number system. MAINTENANCE Meter application will govern the frequency at which maintenance is required. Periodic inspection is recommended as preventative maintenance. INSPECTION A recommended inspection check list should include at least the following items: •
Check externally for leaks.
•
Check for obstruction to flow by foreign objects.
•
Remove the cover and inspect the rotor assembly for worn or damaged parts. Particular attention should be given to the bearings.
•
Remove the readout and check for proper operation
THE BALL VORTEX METER PRINCIPLE
17 - 17
Oil volume
INSTALLATION DIAGRAM
OILGEAR TYPE PV LIQUID METER CORRECTLY INSTALLED
Line drawing illustrating the correct flow direction when facing the read-out hub-top view. The letter “A” or “B” will be found on the meter code (register)
18 - 18
Oil volume REPAIR Before attempting disassembly, depressurize and drain the line. necessary to remove the meter from the line for normal repairs.
It is not
CALIBRATION Each Ball Vortex liquid meter is calibrated at the factory and the calibration plug cover is sealed. Factory calibration is accomplished using well designed, carefully maintained proving equipment. Meter inaccuracy after installation is frequently the result of improper installation or faulty standards of comparison. If meter registration is suspect, first check the installation to be sure all requirements are met. When using a gravimetric proving system, specific gravity and temperature must be carefully considered in computing the volumetric equivalent of the weight of the liquid used for testing. For field proving the recommended flow standard is a large volumetric calibrated tank or pipeline type ball piston prover. In Production testing the volumetric tank method is exclusively used for meter calibration. Errors found after proving are accounted for in the arithmetical calculations of oil volumes, by introducing a correction factor. The calibration plug is NEVER adjusted in the field. The proving tank should be equal to at least the amount passed by the meter in one minute at its maximum rate. If meter registration is found to be low, check first for a damaged rotor or worn or damaged bearings, before attempting any adjustment. If meter registration is found to be high, check for upstream obstructions which could result in increased liquid velocity, or an obstruction under the septum which will cause over registration. Liquid flowing at or near it's vapour pressure, may flash and cause over registration as will entrained gas. If the meter does not register, check for proper installation of the readout device. If properly installed, check the readout for proper operation by removing and turning by hand. LUBRICATION The bearings of the Roots Vortex meter are lubricated by the liquid being metered. However, if the meter is handling contaminated liquids or solutions which tend to precipitate solids, it is advisable to periodically flush the meter with clean liquid or water. Flushing is particularly important if the meter will stand idle while filled with solutions which can precipitate solids. Remove the readout by loosening the three set screws and twisting the readout as it is pulled off the mounting ring. Remove the cover screws and then remove the readout side cover by pulling straight away from the meter. Protect the rotor during this step. The rotor assembly may come out when the cover is removed. If it remains, it should be removed by gently pulling on it while taking precautions to prevent damage.
19 - 19
Oil volume If it is necessary to replace the bearings or the magnet assembly, it is recommended that a fixture similar to that shown below be used to prevent bending the rotor shaft when driving the old pins out of the new ones in. Replace all "O" rings once they have been removed. Reassemble the meter following the reverse procedures and clean all parts before reinstalling them. Particular care should be taken to clean the blind side bearing cavity. Apply a suitable "O" ring lubricant to all "O" rings before installation. tighten the cover screws to between 15 and 20 ft - lb torque. For units with tungsten carbide bearings, carefully seat the lightly lubricated "O" ring on the bushing collar and true in its groove, insert the collar and "O" ring into the retainer until fully seated against the "O" ring positioning stop. The blind end collar and "O" ring must be installed while removed from the rotor assembly. The magnet end collar and "O" ring may be inserted into the cover and diaphragm with the rotor assembly as the "seating tool". The final step is to insert the rotor and cover combination into the meter body, carefully guiding the back carbide sleeve bearing into the carbide bushing and collar, without unseating either the blind end "O" ring or the magnet end "O" ring from their fully seated positions. Refer to the proper parts list for rotor assembly part numbers and for correct location of the parts making up the rotor assembly.
20 - 20
Oil volume RANGE OF 2" FLOCO AND 3" ROTRON METERS FITTED ON THE SEPARATOR OIL OUTLET 2" FLOCO
2" ROTRON
3" ROTRON
{100 - 2200 BPD
{850 - 8500 BPD
{2200 - 22000 DPC
{3-64 GPM
{25-250 GPM
{64-642 GPM
Metering problems on a separator have led us to recognise the "gap" which exists between the 3" Rotron and 2" meter. The lower range of the 3" Rotron is 100 gpm (3400 BPD) and the upper range of the Floco is 60 gpm (2060 BPD). Originally, we were using ball bearing Rotron with a lower limit of 60 gpm and there was no metering gap. When it was found that the ball bearings were giving a lot of trouble, the type of Rotron was changed to the sleeve bearing type, with the higher lower range. The manufacturer was contacted at that time and we were given assurance that this type of meter would keep an accuracy of 2% even below its lower theoretical limit. Controls made with two independent laboratories have shown that this is simply untrue. Below 100 gpm, the accuracy of the Rotron drops sharply and errors up to 12% can be expected near 60 gpm. On the contrary the Floco meter, used above its upper limit of 60 gpm shows an excellent behaviour, with errors within the 1.5% limit, and this up to 100 gpm. Consequently, when a flow rate has to be measured in the measuring gap, between 60 and 100 gpm, the measurement must be done not with the Rotron but with the Floco. The latter can take an over speed for several hours without being destroyed.
21 - 21
Oil volume
22 - 22
Oil volume
1.4
OIL READINGS AND CALCULATIONS The computation of the oil flow rate from the separator is one of the fundamental functions to be performed during a well test. The oil rate is calculated using either the FLOCO or the ROTRON. The meter which will be utilised, depends entirely on the flowrate. The following are the flowrate ranges for the 2" floco and the 3" rotron. FLOCO
Range 200 - 2200 bbls/day
ROTRON
Range 3400 - 22000 bbls/day (Sleeve type bearing)
It can be seen that the two ranges do not overlap. These are however, the official manufacturers ranges, experience has shown that the 2" floco will operate up to 3500 bbls/day. It is far preferable to use the floco somewhat above its stated range, than to use the rotron below its range. (The accuracy of the rotron below 3400 bbl/day is very poor). A number of factors come into play concerning the oil rate. They are: "K" (or VCF) factor: The volume reduction factor due to temperature, known as the "K" factor. This is derived from tables or a chart.
1.4.1 Shrinkage The "SHRINKAGE" is the reduction of the volume of oil due to the release of dissolved gas in solution leaving the separator. Oil volumes are always reported at "STANDARD CONDITIONS" usually 14.73 psia at 60°F. The oil leaving the separator will always be at elevated pressures and temperatures and will therefore normally still contain some dissolved gas. In taking the oil to atmospheric conditions this gas will be released, and the oil volume will reduce because of it. The shrinkage can be derived from either a shrinkage tester, gauge tank or from tables. The method used will depend on equipment available and client. In order of reliability they are: •
The gauge tank method
•
The shrinkage tester
•
Tables of charts. They only really give an approximation and make several assumptions about the fluid that may or may not be true.
The temperature used to calculate the "K" factor above is THE FINAL SHRINKAGE TEMPERATURE, either of the tank or the shrinkage tester, and NOT the flowing temperature of the oil line of the separator. If the charts are used to ESTIMATE the shrinkage then the "K" factor will be 1, because the charts give the shrinkage at 60°F.
23 - 23
Oil volume
1.4.2 "BSW": The BSW is the Basic Sediments and Water, that is the amount of water and sediment present in the well flow. It is normally measured by taking samples of well flow at the choke manifold and oil outlet of the separator. A centrifuge is then used to separate out the constituent parts of the sample. The glasses are graduated so that the BSW can be read of as a percentage. The BSW will be introduced into the oil computation so that the final oil rate calculated reflects the pure oil rate alone. It is important to understand that if water is being dumped from the separator then the BSW at the choke manifold will NOT be the same as the BSW at the oil outlet. theoretically, in this case, if the water level is kept low in the separator the BSW at the oil outlet will be zero. If, however, water is not dumped from the separator, but simply allowed to leave the separator with the oil, then the BSW at both choke manifold and meter run should be the same. Essentially, in a nutshell, the BSW used for oil calculation will be the BSW at the meter run. BSW measurement The Basic Sediment and Water has to be determined in order to be able to calculate the NET oil flow from the well, and to be aware of the presence of water and sediments. METHOD The basic piece of equipment for BSW determination is the centrifuge. This may be driven by an electric motor or hand driven. Samples of well flow are taken from the well head, upstream of the choke, and placed int he centrifuge in order to separate out the oil, water and sediment. In the case of emulsions a demulsifier may have to be used. (Only a drop in each glass.) The glasses should be filled to the 10 ml mark (or 100 ml depending on size of glass) to make percentage calculations simple. The method of sample taking is important. If the needle on the choke manifold is only cracked open to fill the sample glasses, the sample taken will not be representative. A good flow into a bucket has to be established and a plastic container filled. This container should then be well shaken and the sample glasses filled form it. Centrifuge the samples for a good 2 - 3 minutes. The percentage of sediment and water can then be read off the millilitre scale. The average of the two readings is taken as the result. If the separator is running two phases only this BSW shall be entered into the oil calculation. If the separator is running 3 phase, (water is being dumped and measured from the separator), the BSW is for information only on the "Well Test Data Sheet". Caution: The centrifuge runs at a very high speed, never open an electric centrifuge until the rotor has stopped completely.
1.4.3 Meter factor All meters have an error, it is normal to ascertain this error before the test begins. This is achieved by pumping water through the meters, at a rate around the expected well flow rate. The flow is directed to the gauge tank, where the precise amount of water pumped can be measured. (Min 20 - 30 bbls). by reading the meter before and after, and comparing with the tank reading, a meter factor can be arrived at. 24 - 24
Oil volume Meter factor = tank vol/meter vol. i.e. if 30 bbls are flowed through the meter but this reads as 28 bbls in the tank, then the meter factor = 28/30 = 0.9333. This is a very simple calculation but you would be surprised how many people, even experienced people, get it the wrong way round.
1.4.4 Meter and Shrinkage factor This is a method whereby a combined correction factor for meter and shrinkage factor is calculated using a gauge or surge tank. It is the most accurate, and therefore most preferable, method of calculating these two factors. The procedure is as follows. During a given flow period in the test the well flow is directed from the burner to the gauge/surge tank. At the precise moment that the valves are operated, the meter is read. It is necessary before starting to have a level of dead oil in the tank. Some 20 or 30 bbls of oil are passed to the tank. When this quantity of oil has passed to the tank, the flow directed back to the burner again. As before the meter is read at the moment the flow is diverted. What we have now is a precise quantity of oil having passed through the meter to the tank, say 25 bbls. The oil in the tank is now left to "shrink". Because the tank is at atmospheric pressure the oil will gradually degas, and shrink due to this degassing. When the oil has completely degassed (can take 2 - 3 hours or more) the new tank level is read and converted to bbls. This may be 21 bbls. As before by dividing the tank volume by meter volume we get a correction factor. This factor represents a composite correction, comprising meter factor AND shrinkage. The final tank temperature is also read and form this the "K" (or VCF) factor is calculated.
1.4.5 Rate Calculation The meter is normally read every 15 or possibly 30 minutes. The difference in meter readings is then multiplied by the various correction factors described above, and then by the time factor to give bbls/day (or M3/day if working in SI). The time factor is 96 for 15 minute readings and 48 for 30 minute readings. The formula for oil rate is as follows:
Q = Vo × Mf × (1 − BSW ) × (1 − shr ) × K
where: Vo is the difference between two readings. Mf = Meter Factor (Usually in the range 0.95 - 1.1) (1-BSW) = factor derived from expressing the BSW as a fraction and subtracting it from 1. e.g.. BSW = 5% therefore fraction = 0.05 and 1 - 0.05 = 0.95 (1-SHR)= correction due to shrinkage. K (or VCF) = correction for temperature to base 60°F (or 15°C if working in SI system). Be careful to use the correct depending on which unit system you are working in.
1.4.6 Specific Gravity One other property which is measured is the oil Specific Gravity. The SG does not go directly into the calculation of oil rates, but may be needed for example, if the estimation of shrinkage charts are used. It is an important parameter which is 25 - 25
Oil volume normally entered into the oil calculation sheet. The SG is an expression of the "weight" of the oil in relation to fresh water. It is simply a ratio, and has NO units. It should NOT be confused with density! It is measured using glass hydrometers. The temperature is also measured at the same time and the SG measured must be corrected to 60°F (15°C if in SI).
26 - 26
Daniel
SECTION 13 DANIEL ORIFICE METER
1-1
Daniel
DIFFERENTIAL - PRESSURE PRIMARY - ELEMENT ORIFICE METER (DANIEL)
2-2
Daniel
1.1 DANIEL ORIFICE BOX This is a device which enable the orifice plate to be changed without interrupting the separator gas flow. The orifice plate is placed in a TEFLON gasket and then put into an orifice plate carrier. This carrier has gears on either side which are engaged by gear wheels within the Daniel Box. The box is composed of two compartments, separated by a sliding gate valve. The upper compartment is sealed on top by a removable gasket and sealing bar. The operation of installing an orifice plate is very simple. With the gasket and sealing bar off and the sliding valve closed, the orifice plate carrier is put into the top compartment. The sealing bar and gasket are replaced and the pressure is equalized between the two compartments by an equalizing valve. The sliding gate is opened and the orifice plate carrier is wound down into the gas flow path by gear wheels. The sliding gate valve is closed and pressure bled off from the top. (Full details of operation are given on next page).
1.1.1 Installation −
Remove all scale, sediment and dirt from the flange faces, pipe and Daniel Box. The roughness of the inside of the pipe should correspond with commercially finished steel pipe. Gasket the line flanges and install the fitting in the line, be sure that the flow direction correspond with the arrow on the body.
−
Install bleeder valve (N°10B) and grease gun (N°23) to connections on Daniel Box.
−
With no orifice plate in line and the gate valve closed, do a hydraulic pressure test corresponding to the test pressure of the Daniel Box, line pipe and flanges i.e. Separator test pressure. After the hydraulic test, check for any welding slag or foreign matter that may be in the pipe and remove it.
1.1.2 Operation Operation of the Daniel Box is shown in Figure 1. However, there are some points that should be raised when using a Daniel Box. −
If the gas flow rate is now known, always put an orifice that is larger and work down until the right size plate is in the line.
−
Lift the orifice plate into the top compartment just before a choke change.
3-3
Daniel
DANIEL ORFICE METER
4-4
Daniel
10. Crank carrier arm (n°7) until carrier meshes with the lower gear. 11. After meshing, crank carrier arm (n°6) until the plate carrier is all the way down. 12 Crank slide valve arm (n°5) until indicator shows "closed". 13 The orifice plate is now in the flow. 14. Close equaliser valve (n°1) and open bleeder valve (n°10B) to bleed-off pressure in upper chamber. Close after pressure is bled-off. CAUTION - It is important to close the bleeder valve, since gas may leak past the slide valve and escape to atmosphere, causing a concentration of explosive H2S. 15. The orifice fitting is now in service. INSTRUCTIONS FOR REMOVAL OF ORIFICE PLATE
INSTRUCTIONS FOR INSTALLATION FOR ORIFICE PLATE 1. Select an orifice plate of sufficient size to easily pass the anticipated flow rate from the separator. A smaller orifice may consequently be substituted if the initial selection does not produce an adequate differential. NOTE - Size of the orifice is stamped on the outer edge of the downstream side of the plate.
1. Check that bleeder valve (n°10B) is closed. 2. Open equalizer valve (n°1) to equalize pressures in top and bottom chambers. 3. Crank the slide valve (n°5) to the "open" position on the indicator. 4. Crank lower carrier shaft arm (n°6) until plate carrier meshes with upper carrier gear. 5. Crank upper carrier shaft arm (n°7) until plate carrier touches top of upper chamber. 6. Crank slide valve arm (n°5) to the "closed" position on the indicator. 7. Close equalizer valve (n°1). 8. Open upper chamber bleeder valve (n°10B) and let pressure bleed off from the top chamber. 9. Loosen set screws (n°11) in clamping bar (n°12).
2. Install the orifice plate in the plate carrier (believed face of orifice to be on downstream side). 3. Check that side valve (n°5) and equalizer valve NOTE - Do not remove clamping bar at this (n°1) are closed, and that upper chamber bleed stage valve (n°10B) is open. 4. Loosen set screws (n°11) in clamping bar from 10. Crank upper carrier arm (n°7) to loosen the sealing slot. Remove sealing bar (n°9) and gasket (n°9A). bar (n°9) and the gasket. CAUTION - Do not stand in line with slot during this operation. Pressure inside top chamber may cause injection of clamping and sealing bars.
NOTE - This operation will relieve any remaining pressure in the upper chamber. 11. Remove clamping bar (n°12), sealing bar (n°9) and gasket (n°9A).
5. Install orifice plate carrier in the top of the orifice NOTE - Take care not damage the gasket. fitting. Turn carrier arm (n°7) slowly until the carrier is meshed with the gear. Crank carrier down until it 12. Crank upper chamber arm (n°7) to raise the carrier touches the slide valve. from the top chamber until the gear is not meshed. 6. Inspect sealing bar gasket (n°9A). If this is not 13. Remove orifice plate from the carrier and from the satisfactory, use a new one. Install sealing bar plate gasket. (n°9) and replace clamping bar (n°12) in the slot. Tighten all set screws (n°11). 7. Close upper chamber bleeder valve (n°10B). 8. Open the equalizer valve (n°1 and let pressures equalize in upper and lower chambers. 9. Crank the slide valve (n°5) to the open position on the indicator.
5-5
Daniel
1.1.3 Lubrication procedure Daniel type I Lubricant is expressly made for use in "SENIOR" Orifice Fittings for Lubricating the all-important slide valve, insuring maximum operating performance. Since it is a chemical compound rather than a petroleum base product, the lubricant has significant advantages. −
Type I Lubricant is effective over a wide range of temperature, - 40° to + 500°F.
−
The Lubricant contains no fillers or inert materials, thus eliminating hardening or oxidizing.
−
Type I Lubricant is insoluble in water and extremely resistant to hydrocarbons within its temperature range.
Daniel Type I Lubricant is formed into sticks, 1/2" in diameter, 2" long for packaging 24 sticks to the box. The cylinder shape fits neatly into the grease fitting which comes on the SENIOR. INSTRUCTIONS FOR LUBRICATING 1. Lubricate the slide valve one per month, whether or not the orifice plate is removed. 2. Before lubricating, open the bleeder valve and close both the slide valve and the equalizer valve. 3. To lubricate, remove stem from grease fitting, insert lubricant stick, replace stem and slowly turn. 4. Inject lubricant slowly. If done hastily, high pressure from the lubricant may rupture valve seat gasket or force apart the valve and seat. 5. Crank stem all the way in to grease fitting. If more lubricant is required, repeat steps 3 and 4 above. To clean out dried or cracked lubricant when fitting has not been operated for long periods of time, close slide valve, de-pressure line and fill top chamber with a grease solvent. Also, solvent may be forced through grease fitting with a large chamber grease gun. After cleaning, replace with new lubricant.
1.1.4 Maintenance It is recommended that all Senior-type orifice fittings be operated once every thirty days. Slide valve (Part n°5) should be opened and closed and lubrication applied through Part n°23. If plate inspection is not required, it is recommended that gear shafts (n°6 and n°7) be rotated. Under conditions where there is likely to be an accumulation of sediment for any cause, blow-down valves should be installed in place of pipe plugs at bottom of fitting and blown as often as required. Plate carrier should always be raised into upper chamber before blowing or cleaning through blow-down valves.
6-6
Daniel
EXPLODED VIEW
7-7
Daniel
REAR VIEW OF DANIEL ORIFICE AND BARTON
8-8
Barton
SECTION 14 BARTON RECORDER
1-1
Barton
DIFFERENTIAL PRESSURE UNIT MODEL 199
2-2
Barton
DIFFERENTIAL PRESSURE RECORDERS
3-3
Ranarex
SECTION 15 RANAREX GAS GRAVITOMETERS
1-1
Ranarex
1.1 ROLE −
The Ranarex Gas Gravimeter allows the accurate determination of specific gravity of gas.
−
The instrument operates on the principle that the kinetic energy of air on counter rotating impellers.
1.2 HOW RANAREX OPERATES
Figure 1 The Ranarex Gravimeter uses dynamic forces to measure the specific gravity of gas. The simple operating principle is illustrated in Figure 1. The chassis of the instrument forms two cylindrical gas-tight measuring chambers, each having separate inlet and outlet connections. Each chamber contains an impeller and an impulse wheel, which have straight radial vanes. These wheels are mounted on separated shafts, facing each other but not touching, so that each chamber resembles an automotive fluid coupling. An electric motor and drive belt rotates both impellers at the same speed and in the same direction. The impellers draw continuous flows of gas simple and dry reference air into their respective chambers and spin the gas and air against the vanes of the corresponding impulse wheels which are proportional to the densities of the gas and of the reference air. This torques is transmitted from the chambers by the impulse wheel pivot shafts to two external measuring wheels. The upper measuring wheel has a spiral shaped rim (cam) and the lower measuring wheel has a circular rim. A flexible tape is wrapped over the measuring wheel rims in the crossed direction so that the gas and air torque exerts two opposing forces on the tape. These opposing forces prevent continuous rotation of the measuring wheels but permit controlled 2-2
Ranarex motion of the system as the gas torque changes. As the system moves, a pointer attached to the hub on the upper or cam wheel moves over the indicating scale, which is graduated to read specific gravity
Figure 2 - Ranarex measuring system Figure 2 explains the geometry of the measuring system for the two operating conditions. The left view shows the position of the cam and reference wheel when checking the "zero". This check is made each time the gravimeter is started, by operating with dry air flowing through both chambers. Both torques’ "Ta", produced by the air, will be equal and the measuring wheels will move until the opposing forces "Fa" are equal. The radii (moment arms) "Ra" must be equal to produce equal forces from equal torque. The angular position at which the cam radius equals the reference wheel radius corresponds to the 1.000 graduation on the indicating scale. The right views of Figure 2 shows the position of the system when measuring specific gravity below 1.000. Gas is admitted to the upper chamber and dry reference air to the lower chamber. The lighter gas creates a smaller torque "Tg" in the upper chamber than the torque "Ta" created by the air in the lower chamber. Temporarily, the upward force "Fg" created by the cam wheel will be smaller than the downward force "Fa" created by the reference wheel. The reference wheel and tape will then turn the cam wheel clockwise toward the balance position shown. As the cam wheel rotates the radius "Rg" gradually decreases. As the radius decreases, the resulting upward force "Fg" gradually increases and eventually is restored to its original value. When "Fg" becomes equal to "Fa" they will balance and motion will cease. Meanwhile the cam wheel has turned the pointer to a new 3-3
Ranarex angular position on the scale. The operator reads the inner circle of scale graduations having a range of 0.520 to 1.030 specific gravity. It is evident for these examples that the radius of the cam - not the force it exerts changes as the gas density varies. In effect, the measuring system divides the radius of the cam by the radius of the reference wheel. This is the equivalent of dividing the torque and density of the gas in the upper chamber by the torque and density of the reference air in the lower chamber, which is the specific gravity. To measure specific gravity above 1.000, the gas is admitted to the lower chamber and the dry reference air is admitted to the upper chamber. The measuring system then divides the torque and density of the air in the upper chamber by the torque and density of the gas in the lower chamber. This is the reciprocal of the specific gravity. The measuring system and pointer will reach a balance position as they did with gas below 1.000. However, the user reads the outer circle of scale graduations from 0.970 to 1.90, which are placed at the reciprocal values of the inner circle. As described later, the pressures of the gas and reference air are equalized and the temperatures of the gas and reference air are equalized. In addition, the belt and pulley drive turns the impellers at equal speeds. Therefore, changes in pressure, temperature and motor speed affect both torques equally. Since the torques produce opposing forces the effects of varying pressure, temperature and motor speed are cancelled. The length of the flexible tape is not critical for accurate measurement. The circular measuring wheel, which acts primarily as the reference device also serves as a take-up, winding or unwinding the tape as required. A high-capacity air drier is built into the Gravimeter to dry incoming ambient air for use as reference air and zeroing air. The Gravimeter is also equipped with a rotary selector valve which directs the flows of gas sample and dry reference air to the correct chamber for checking "zero", for measuring gas below 1.000 or for measuring gas below 1.000 or for measuring gas above 1.000 specific gravity. The drive motor is a low-current, non-arcing type for operation on 115 volt AC. When the Gravimeter is to be used in a motor vehicle or in an area where AC is not available, a DC-AC transistorized inverter is supplied to change 12-volt DC battery current to the correct AC supply. A different motor pulley should be ordered for 50 or 60 Hz. Measuring «sour gas» will not damage the RANAREX. The impellers and impulse wheels is molded phenol; the chamber and casing are aluminum; the shafts are stainless steel and all internal trim in contact with the gas is aluminum or stainless steel. These materials are not attacked by dry or moist sour gas.
1.3 CONDITIONING THE GAS AND AIR SAMPLES The RANAREX Gravimeter measures specific gravity in accordance with the accepted definition: "ratio of the density of the gas, under the observed conditions of pressure and temperature to the density of dry air at the same pressure and temperature" to comply with this definition to assure highest accuracy, requires a simple but adequate sampling system to satisfy the following: DRY AIR BASE
is provided by the built-in air drier. It uses silica gel as the desiccant and is readily rechargeable to simplify replacing the silica gel when exhausted.
PRESSURE
Reference air is admitted to the Gravimeter at barometric pressure. In order that the gas and air will be measured at the
4-4
Ranarex same pressure, the gas must be reduced to barometric pressure. Barometric pressure will automatically be maintained in the gas chamber if the gas flow rate is adjusted to 12 SCFH. Therefore, the Gravimeter is supplied with an integral rota-meter type flow meter with needle valve. As an operating convenience the flow scale is graduated in specific gravity units. The operator merely adjusts the needle valve so that the flow meter reads the approximate specific gravity of the gas. These flow meters are suitable for 20 PSIG inlet pressure; when sample pressure is higher it must be reduced with a conventional pressure-reducing regulator. TEMPERATURE
Reference air is admitted to the Gravimeter at the ambient temperature of the instrument. In order that gas and air will be measured at the same temperature, the gas must be heated or cooled to ambient temperature. This is especially important if the gas pressure has been reduced more than 100 PSIG, or if the gas flows through a temperature zone more than 10°F. different form the ambient temperature of the Gravimeter. If the gas is passed through a section of 3/8 inch metal tube at least 5 ft (preferably 10 ft) long, exposed to the ambient temperature of the Gravimeter and located after the last pressure reduction, temperature adjustment will be automatic. The tube may be coiled or bent in the form of a grid to fit the space available.
FILTERING
if the gas contains suspended particles larger than 25 microns, they must be removed. A commercial gas filter may be used or one may be made of steel or glass wool, in a tube. Either type should be connected ahead of the regulator and flow meter.
RANAREX instruments do not include the gas filter, pressure reducing regulator or sample hose because most users have individual preferences for these items and maintain their own stock.
1.4 SET-UP INSTRUCTIONS 1.4.1 Check accessories A.
B.
All RANAREX Gravimeters include: −
Electric cord, 6 ft of 18 gauge cable with male and female plugs
−
1 1/2 LB can of silica gel
−
Filling funnel
−
Instruction Manual, Form R1 212
When the RANAREX Gravimeter is operating on 12 volt DC battery current, the following is also furnished, unless excluded by purchaser: −
RANAREX Inverter
−
Battery Cables, 16 ft of 12-gauge wire with battery clips
−
Instruction Sheet, Form 5437
5-5
Ranarex
1.4.2 Select location for RANAREX Instrument should be easily visible and readily accessible from operator's position, not near hot or cold objects. Allow at least 5" clearance on the left side and 3" on the right side for making connections and normal operating functions. If the instrument is to be permanently mounted in one location, it should be secured with four ¼ - 20 machine screws. These screws will pass up through the mounting surface and through the holes of the RANAREX base to which the feet are attached. The feet may be used or omitted, as preferred. See figure 3 of the Operating manual for dimensions of RANAREX and location of mounting holes. See Figure 4 of the Operating manual for location of connections and external controls.
1.4.3 Install inverter First read carefully and completely the instructions Form 5437 packed with inverter. Caution: Do not operate RANAREX without first reading pages 5 and 6 Operating Instructions.
1.4.4 Fill air drier The air drier must be removed from the upper left side of the instrument (loosen the two fasteners). Draw the plastic drier assembly out of the Gravimeter just far enough so the rubber tube can be removed from the elbow at the rear of the drier. Remove the rubber closure plug on the front of the drier by lifting the lever at the center of the plug (but do not turn the lever). Hold the drier horizontal with the front face up and pour silica gel through a funnel into the spout. Tap or shake the drier vigorously and continue to fill to the base of the spout. Replace the rubber closure, attach the rubber tube on the elbow at rear of drier, and then install drier in Gravimeter. The rubber tube has an internal spring to prevent collapse; do not remove or lose this spring. The drier is permanently riveted together as an assembly. Do not attempt to remove the rivets and disassemble the drier. The capacity of the silica gel will vary according to the atmospheric humidity and it should be inspected through the drier cover at regular intervals. When the upper half of the narrow compartment shows a change from deep blue color to Grey-pink color, the silica gel must be replaced. Active silica gel has a deep blue color and should be kept in a tightly closed container. Exhausted silica gel has a light grayish, pink color and may be reactivated and used over and over again. Merely heat it in an open container at about 250°F until the dark blue color returns, and then store in a tightly closed container. Additional silica gel may be obtained from RANAREX Instruments as Part No. 30000259. This contains 1½ LB of indicating type silica gel in 6 - 16 mesh sizes.
1.4.5 Attach outlet hoses If RANAREX is operated in confined space, as inside a vehicle, the gas sample must be discharged outside the vehicle. This will prevent contaminating the operating space with noxious or hazardous gas and air mixtures. If measuring only gas below 1.000 specific gravity, attach hose to nipple "LIGHT GAS OUTLET" 6-6
Ranarex on upper right side of RANAREX case. If also measuring gases above 1.000 specific gravity, also attach hose to nipple "HEAVY GAS OUTLET". These hoses must remain attached when making air check or "zero point" check.
1.4.6 Gas filter If the gas contains suspended particles larger than 25 microns, or if it is "wet", filtering is required. If a commercial filter is not available, a suitable filter may be made of 1" pipe 15" long mounted vertically. Cap both ends and install a drain cock in bottom cap. Install inlet connection from gas line 2" from bottom and outlet to RANAREX 2" from top. Fill pipe loosely with commercial No. 0 steel wool. Drain filter frequently to keep steel wool free of condensate.
1.4.7 Gas temperature If the gas sample is above 100 psig pressure, of if the sample will flow through a temperature zone more than 10°F different from the ambient temperature of the RANAREX, temperature adjustment is required. Installs a section of 3/8" metal tube at least 5 ft (preferably 10 ft) long, and locate it near the RANAREX case. The tube may be coiled or bent in the form of a grid, to suit the space available.
1.5 Make gas sample connection Attach pressure-reducing regulator to sample tap and run sample hose to RANAREX location, but do not yet connect to RANAREX. Sample line must be capable of delivering 12 SCFH gas, free of condensed fractions or moisture, at pressure not exceeding 15 psig.
1.6 OPERATING INSTRUCTIONS Caution: This type RANAREX Gravimeter is provided with a Pointer Lock (Figure 4 of the Operating manual) which must be locked at all times when the RANAREX motor is not operating. The function of the lock is to exert tension on the flexible tape, which connects the cam and reference wheel (Figure 1). This tension maintains correct "tracking" of the tape when the RANAREX is stopped. The user is cautioned to leave the lock applied until after the RANAREX motor has been started and to apply the lock before shutting off the motor, to avoid operating inconvenience and prevent damage to the RANAREX. The "LOCK" position of the pointer is at the upper right corner of the scale, near the 0.970 1.030 graduations. The arrow of the knob and the legends shows the position of the locking mechanism on the RANAREX front cover. To check if the pointer is locked, turn the knob to "UNLOCK" and observe if the pointer drifts downward, even though slightly. Then turn knob to "LOCK" position and observe if the pointer snaps into original position. If doubt exists that the flexible tape is correctly tracked, check as explained on page 7.
1.6.1 Procedure The correct procedure for operating the RANAREX Gravimeter is described in the instruction plate located over the center of the indicating scale and reproduced here as Figure 5 of the Operating manual. It is recommended that the used 7-7
Ranarex observe the sequence of steps as listed. By so doing maximum accuracy will be achieved with minimum effort and time. In fact, the user is encouraged to read each item of the instructions each time the instrument is used until the correct sequence becomes a matter of habit. The following comments will also be helpful.
1.6.2 Zero adjustment The zero adjust screw should be turned in the direction opposite to the correction required in the pointer reading. For example, if the pointer must be moved clockwise to read 1,000 on the scale, the screw should be turned counterclockwise. After making adjustments, allow pointer to stabilize because there is a tendency to overshoot when turning the zero adjusts screw. In normal operation the zero adjusts screw should require only little adjustment, less than ¼ turn, to set pointer to 1,000. If more than ½ turn is ever required, stop motor and investigate for the cause. Never turn screw full travel clockwise with motor operating; never turn screw full travel counter-clockwise. RESPONSE TIME When measuring gas at the normal flow rate of 12 SCFH, the response time to reach final reading is 40 - 45 seconds. Operating at a higher flow rate obtained by adjusting the flow meter valve so the float reads higher than the actual gas specific gravity can reduce this time. For example, when measuring 0.6 gravity gas, a flow meter setting of about 1.2 will reduce the response time to about 30 seconds. However, the flow meter valve should not be opened so much that the float is lifted against the stop at the top of the flow tube. OVER-PRESSURE PROTECTION If by oversight the flow meter valve is opened before the selector valve is turned to "LG" or "HG", the valve cover will lift off the body to relieve the pressure and will be reseated by the spring. PURGING TO 1,000 AFTER READING ON GAS This is a necessity in order to bring the pointer within operating reach of the pointer lock mechanism. If the pointer starts toward 1,000 and then hesitates and remains at an intermediate reading, turn the selector valve halfway beyond "O" toward the next position. If the pointer then continues toward and reaches 1,000, check for an obstruction as described on page 6 of the Operating manual, "check gas and air flow".
1.7 MAINTENANCE 1.7.1 Disassembly When necessary to disassemble the Gravimeter, observe the sequence described in the "Disassembly Procedure", page 12 of the Operating manual.
1.8 LUBRICATION The motor bearing, impeller bearing and idler pulley bearing have long life lubrication and should give long service. If the impeller bearing binds or become extremely noisy, they may be lubricated as described on page 10 and 11 of the Operating manual, or the complete assembly may be replaced. The idler pulley 8-8
Ranarex bearing should be inspected and re-lubricated if it does not turn freely or becomes noisy. Note : Bearing is lubricated as shipped. It cannot be disassembled but can be re-lubricated when necessary. −
Grip round shaft where it extends from pulley.
−
Remove adapter shaft by gripping hex section ad turning for right-hand thread. Unscrew adapter shaft complete but do not lose split lock washer.
−
Insert tip of grease tube (RANAREX 187 - 14010) into tapped hole in pulley shaft. Fill hole with grease.
−
Replace adapter shaft in pulley shaft. Be sure split lock washer is in position in recess around base of male thread.
−
Tightening adapter shaft into pulley shaft will force grease into bearing. Excess grease will be forced out through seals but do not use more grease than needed to obtain smooth rotation of shaft in pulley.
1.8.1 Selector valve If the selector valve is exposed to dirty gas, it may require cleaning and lubrication. Should this become repeatedly necessary a gas filter should be installed. The air drier functions as a filter so a separate reference air filter should not be required. To clean the selector valve removes the screw at center of valve cover and withdraws screw, 2 washers, spring and cover. Clean off all old grease and dirt from faces and channels of both cover and body. Lubricate faces of cover and body with silicone grease or stopcock greases and replace all parts. If the valve cover or body become scored by dirt, it is necessary to grind the mating surfaces to eliminate the scoring. Clean both surfaces, apply fine valve grinding compound to them and reassemble the valve. Loosen or remove the détente spring, which engages the "O", "LG" and "HG" notches of the cover. Rotate the cover back and forth on the body well beyond its normal operating arc, continuing until the scoring is removed. Then thoroughly clean, lubricate and reassemble all parts.
1.8.2 Pointer lock If the connecting tape leaves the cam or reference wheel while the Gravimeter is in transit, the pointer lock requires adjustment in the following sequence: −
Remove front cover to check if the sides of the U-hook at end of lock spring are parallel with inner face of the cover, and if the setscrew is fully tightened in the shaft of the lock knob. Turn spring and tighten screw if necessary.
−
Remove indicating scale, track the connecting tape on the cam and reference wheel, then set pointer approximately at the 1.000 position. Hold front cover by hand in correct position o Gravimeter casing. Turn knob toward the lock position to check if the U-hook straddles the radial edge of the cam. If necessary, bend the spring in the correct direction at the knob shaft.
−
Again holding front over to casing by hand, turn know toward lock position to check if the spring takes up the slack in the connecting tape before the lower end of the spring snaps between the détente pins of the cover. If it does not, bend the upper section of the lock spring, at the knob, toward the cam edge. This will be toward the left when viewed from inside the cover. 9-9
Ranarex −
10 - 10
Finally, with the cover held to the casing, check if the lower end of the lock spring will snap between the détente pins and will be retained. If necessary, bend the lower end of the spring toward, or away from, the front cover, if required.
Gas flow rate computation
SECTION 16 GAS FLOW RATE COMPUTATION
1-1
Gas flow rate computation
1.1 GAS FLOW RATE MEASUREMENTS Natural gas is in a state of continuous flow from the time it leaves the reservoir until it is burned, either in the gas flare on a drill stem test or in domestic appliances. It was very important for the sale of natural gas in distribution systems that an accurate method of measuring gas flow-rate was found. Several American technical societies sponsored research into gas flow rate measurement and their findings were put together into a report - AGA - 3 (American Measurement Committee Gas Association, Gas Report n°3) Basically there are two types of metering devices used for gas measurement. 1. DYNAMIC METERS 2 VOLUMETRIC METERS Orifice Meter Diaphragm meter Venturi meter Laboratory wet test meter Flow nozzle Critical flow prover Pitot tube Rotameter Choke For measuring large flow rates, the orifice meter is used. An orifice of known size is located in the pipe. The restriction caused by the orifice causes a velocity increase and a pressure drop. This pressure drop is known as the differential pressure and is a function of the flow rate, static pressure, pipe I.D. and orifice size. The differential pressure may be taken either using flange taps or pipe taps. FLANGE TAPS 1"
1"
D
d
2.5 D
8D PIPE TAPS
The differential pressure is measured across the orifice from taps located one inch to either side of the orifice. The differential pressure is measured from taps located at 2.5 D upstream (where D = I.D. of pipe). The orifice may be installed in the line either between two flanges or in a Daniel's box. The orifice installed between two flanges is called a diaphragm. It is circular in shape, made of stainless steel and has 2-2
Gas flow rate computation a concentrically pierced in. calibrated orifice in it. Above the diaphragm is a tail, which sticks out the flange. This tail has orifice and pipe line sizes engraved on it. The flanges are bottled together with a diaphragm inside. The method is suitable for steady flow. It is economical and easy to use. However, large variations in flow would cause the insuring device to go off scale and another diaphragm to be put in. If continuous fluctuations are occurring, then this is not suitable.
3-3
Gas flow rate computation
1.2 GAS FLOW RATE CALCULATION (Orifice meter constants AGA - 3) The quantity measured by an orifice meter in an hour is expressed by the formula:
Qh = C ' hwpf Where Qh= C'=
Rate of flow at base conditions in cu/ft per hour Orifice flow constant. It is the rate of flow in cu/ft per hour at base conditions when the pressure extension, hwpf = 1.000 hw= Differential pressure in inches of water Pf= Static pressure in psia hwpf = 1.000 = Pressure extension.
1.2.1 Orifice flow constant C = Fb × Fr × Y × Fpb × Frb × Ftf × Fg × Fpv × Fm × Fa × F1 In calculation of gas flow rate only Fb, Y, Ftf, Fg and Fpv are significant. Therefore, for calculating gas flow rate in GEOSERVICES, C' will be taken into account:
C 1 = Fb × Y × Ftf × Fg × Fpv where Fb = Basic orifice flow factor. The value of this factor depends upon −
the location of the differential taps
−
the orifice diameter (d)
−
internal diameter of the pipe (D)
where The pressure base Pb= 14.73 PSI The temperature base Tb= 60°F Specific gravity gas (G) = 1 Flowing temperature Tf = 60°F Expansion factor Y=
1
Reynold's number is infinity Y = Expansion factor. When a gas passes through an orifice, the change in pressure and velocity is accompanied by a change in the specific weight. Y depends upon − 4-4
the location of the differential taps
Gas flow rate computation −
the location of the static pressure tap
−
ratio of orifice size to line pipe size (d/D)
−
ratio of differential to static pressure, static pressure taken at upstream tap = Pf1, static pressure taken at downstream tap = Pf2.
Ftf = Flowing temperature factor. Orifice factors were calculated at 60°F. Therefore, this correction factor corrects the flowing temperature to 60°F.
Ftf =
520 460 + actual flowing temperature
Fg = Specific gravity factor. Orifice factors were calculated with gas of specific gravity 1.000. The factor necessary to convert the specific gravity of the gas to 1 is
Fg =
1 G
Fpv = Super compressibility factor. Takes into account the deviation of the gas from the ideal gas laws i.e. BOYLES and CHARLES Law. By experimentation, factors have been worked out which take this non-ideality into account. EXERCISE 1 Line Size = 5.761" Orifice Size = 1.250 Static Pressure = 345 psig Differential Pressure = 64" H2O Gas Temperature = 110°F Gas Specific Gravity = 0.791 (Pipe taps, static pressure taken downstream) Calculate the flow rate/day If the oil flow rate = 2.560 STO BPD, calculate the G.O.R. EXERCISE 2 Line size = 7.981" Orifice Size = 3.500 Static Pressure = 850 psig Differential Pressure = 126" H2O Gas Temperature = 143°F Gas Specific Gravity = 0.695 (Flange taps, static pressure taken downstream) Calculate the gas flow rate/day If the oil flow rate = 6.895 STO BDP, calculate the G.O.R.
5-5
Gas flow rate computation
1.2.2 Unit Factor Table 1 UNITS REFERENCE CONDITIONS
Cuft/hour
Cuft/day
M3/hour
M3/day
60°F 14,73 psia
1
24
0.02832
0.6796
0°C 760 mm Hg
0.9483
22.760
0.02685
0.6445
15°C 760 mm Hg
1.0004
24.009
0.02833
0.6799
15°C 750 mm Hg
1.0137
24.329
0.02870
0.6889
6-6
Hydrates (Heater, Texsteam pump)
SECTION 17 HYDRATES (HEATER, TEXSTEAM PUMP)
1-1
Hydrates (Heater, Texsteam pump)
1.1 AMBIENT TEMPERATURE As Gas flows through a pipe it cools to the ambient temperature e.g. gas flow lines to a commercial station. In some gas fields, conditions exist which cause hydrate formation in the tubing but in most fields, hydrates are not a problem until the gas passes through the surface equipment. Hydrate formation is most likely to occur when gas is cooled and turbulent conditions exist e.g. in chokes, valve meters and pip-work. They can cause meters and valves to be inoperative and in sever cases, totally block the flow of fluid. This is critical because a hydrate plug may form in a low-pressure line causing the full well shut in pressure to be exerted on this line. There are several methods of hydrate prevention: 1.
Heating the gas above the hydrate formation temperature by the use of a direct or indirect heater. These heaters also have long nose chokes immersed in the heating medium and can be used if the gas temperature is low.
2.
Injection of anti-freeze agents, such as methanol, glycol and ammonia. These cause the water to dissolve, and not contribute to, hydrate formation. (Texsteam Pump)
3.
Downhole heating in wells with relatively low temperatures. (Used only rarely on producing fields).
4.
Opening up the gas well to try and get the bottom hole temperature to surface as fast as possible.
5.
By using a downhole choke to restrict the flow in an area of high temperature.
Using the long nose choke on the heater, as the primary flow control device, the well can be choked back with the minimum likelihood of hydrates forming. (Pipework to the heater is usually rated at 5000 PSI). On the separator if hydrates form downstream of the back-pressure valve, then methanol/glycol can be injected between the Daniel Box and the back-pressure valve. In locations, which can supply steam, the pipe below the valve can be lagged with a steam coil wrapped around the pipe. Hydrates may also from in instrument lines and needle valves e.g. between the Daniel Box and Barton meter, and at the Data header. Installing bigger piping, eliminating leaks, installing ball or plug valves in meter piping instead of needle valves etc. may counteract the problem.
2 - 26
Hydrates (Heater, Texsteam pump)
TexTeam Pump To by pass flare Long nose choke Data header injection of methanol / glycal
HEATER
Choke manifold
From W.H.
SEPARATOR Pipe can be lagged Barton meter To gas flare Daniel box TexTeam Pump Injection of methanol / glycal
3-3
Hydrates (Heater, Texsteam pump)
1.2 HEATERS The first question asked is why are heaters required in an offshore or on-shore well testing package? Heaters are installed to heat the crude oil stream either to lower its viscosity and/or to pass it in separation of the gas/oil or, more particularly, an oil water emulsion. Another reason for having a heater in a test package is for gas well testing. When gas under high pressure is passed through a choke to reduce its pressure, it expands and cools. If this cooling is severe, it my result in hydrate formation and blocking of all the connecting lines. The basic heater design is aimed at combating this problem. The design is refereed to as a split bundle type. The incoming stream, which has been expanded and cooled through the choke manifold, passe directly into the high pressure coil, consisting of a number of passes of high pressure pipe where the gas is re-heated. The high-pressure stream then exists from the heater and passes through a heater choke, where it is expanded, reduced in pressure and once again cooled. It passes back into the heater and through the low-pressure coils and is re-heated. A by-pass manifold should always be incorporated as part of the heater so that the test stream can be diverted directly across the heater, without passing through it. Increasingly high heater outputs are being asked for, especially in the North Sea, where high surface pressures, high flow rates and cool temperatures lead to hydrate formation. Heaters are now in use with heat transfer capacities ranging from 1.5 to 4 MMBTU/HR with 2 MMBTU/HR being the most popular. They are fabricated with a variety of heating methods: −
GAS FIRED
−
OIL/DIESEL FIRED
−
ELECTRICALLY FIRED
−
HOT WATER CIRCULATION
−
STEAM
The first three are indirect heaters; the last two are direct heaters. The two most popular heaters are the gas fired and steam ones. 1. Steam Heaters are widely used in areas where steam is available e.g. offshore production platforms because it is very safe and also has a high heat transfer capacity. Only type of heater allowed in the North Sea. 2. Gas fired heaters (indirect) Heater consists of: −
Heater shell - thin walled horizontal vessel, having removable flanged covers at both ends.
−
Removable fire tube and burner assembly mounted on the lower portion of one of the end covers.
−
Removable coil assembly mounted on the upper portion of the opposite end cover.
The heater is filled with water, covering both the firebox and the high pressure coil assembly. This has two advantages - should the high-pressure coils rupture, the
4 - 26
Hydrates (Heater, Texsteam pump) well fluid will come into contact with water, the same applies when the firebox is perforated. Also installed above the firebox is the thermosiphon baffle. This gives better control over the direction of the hot water currents, allowing greater heat transfer and it reduces the possibility of steam generation, thus reducing scaling of the fire tube.
1.2.1 Description Type :
Skid mounted, water bath indirect heater
Made of:
1 cylindrical vessel 2 Coils for process fluid with positive choke 1 firing tube 1 stack 1 diesel burner 1 diesel pump with pneumatic motor 1 set of regulation & controlling instruments 1 gas burner 1 scrubber
Process fluid:
Oil, gas, oil & gas, oil mud & diesel.
Heating fluid: added)
Water, maximum temperature 90* C (glycol may be
Burner data:
burner liberation:
510.000 Kcal/h
Burner combustible:
diesel, gas
Pilot combustible:
propane gas
Instrument power:
air, propane, and gas
Diesel pump power:
air
Burner atomization:
air
Diesel consumption:
50 l/h at 8 bars
Pilot gas:
2,5 kg/h at 0.4 bars
Instruments:
3 Nm /h at 7 bars
Atomizing air:
30 Nm /h at 1,5 bar
Air for diesel pump:
70 Nm /h at 10 bars
1.2.2 Technical data Working Pressure primary coil
340 bar ( 5000 psi )
Working Pressure secondary coil
150 bar ( 2160 psi )
Working Pressure gas scrubber coil
16 bar ( 240 psi )
Corrosion allowance of all coils
1.5 mm
Shell Working Pressure
Atmospheric
5 - 26
Hydrates (Heater, Texsteam pump) Working Temperature shell and coils
121 deg. C ( 250 deg. F )
Exchange surface coils
26 m2
Nominal Calorific Power
500 Mcal/h (2MMBTU / h)
1.2.2.1
Dimensions Shell
3.450 mm x 8.140mm *
Overall Length
6.200 mm
Width
2.200 mm
Height
2.800 mm
2.2
Weight
Empty
11.300 kg
Full of water
17.300 kg
1.2.3 Special Features −
3" adjustable choke between primary and secondary coil
−
Diesel reservoir 400 liter
−
Tool box
1.2.4 Safety Devices −
Safety drilling of coils returns bends
−
High Temperature Shut Down (HTSD)
−
Gas Pilot Detector (CM 5 pilot guard)
1.2.5 Control Equipment
6 - 26
−
Temperature Controller (TC)
−
Temperature Control Valve (TCV) in burner diesel line
−
Temperature Control Valve (TCV) in burner gas line
−
Temperature Control Valve (TCV) in air supply line
−
High Temperature Shut Down (HTSD)
−
Shut Down Valve (SDV) in air supply line
−
Shut Down Valve (SDV) in burner diesel line
−
Shut Down Valve (SDV) in burner gas line
−
Gas Pilot Detector (CM 5 box)
−
Shut Down Valve (SDV) in pilot gas line
Hydrates (Heater, Texsteam pump)
1.2.6 Connections Diameter
Wing union
Crude / gas inlet
3"
3"fig.1002 female
Crude / gas outlet
3"
3" fig. 602 male
Burner gas inlet
1"
1" fig. 602 female
Burner gas outlet
1"
1" NPT
Water bath drain
3"
3" fig. 602 male
1.2.7 Operation 1.2.7.1
Diesel burning: Preparation −
Place the heater on a horizontal surface, rise the chimney place the gasket and tighten all bolts.
−
Fill up the heater with sweet water through the 6" top filler pipe until it overflows.
−
Close the manual valve G 2 to the gas burner.
−
Check those valve D 1 on diesel line and airline valve A 5 to diesel pump are closed.
−
Open air supply valves A 1 and A 3 to controller instruments, check for 1.5 bar (20 psi) min. pressure on temperature controller outlet, regulate if needed with RA 1
−
Open atomizing valve A 4, check for atomizing air pressure at about 2 bars then close the valve. The fine adjustment of the combustion can be adjusted with regulator RA 2.
−
Disconnect gas pilot outlet from scrubber and connect gas bottles to the gas pilot line.
−
Check that the 12 V battery is loaded and place the ignition box on its stand don’t forget to connect the earth lead to the frame.
Start up pilot −
Before any attempt to light the burners, always circulate the combustion chambers with the air blower between 5 and 10 minutes, by opening valves A 1 and A 6.
−
Open the manual valve PG 1 to gas pilot, check that the press. is about 1 bar. It can be regulated with RG 3.
−
Push "button" on CM 5 pilot guard, press "ignition» button on ignition box until pilot flame is on.
−
Once the temperature feeler from the CM 5 pilot guard is warm enough it will switch the pneumatic relay R and will supply air to the TC and HTCS and will also maintain AG 3 valve open.
Start main burner −
Open manual valve to diesel burner D 1.
7 - 26
Hydrates (Heater, Texsteam pump)
1.2.7.2
−
Open the manual valve A 5 to start the diesel pump.
−
Once main diesel burner is working the combustion can be finetuned with the air regular RA 2 (approximately 2 bar), and the pressure on the diesel line around 7 bar. (Use the regulator on the diesel pump to adjust the diesel press.)
−
If the main burner is not starting, the TC controller could be out of its normal setting, adjust it so the main burner starts.
−
Set max. temperature 95° C on HTSD controller.
−
Set temperature required on TC controller maximum 90° C.
Gas burning: Preparation −
Place the heater on a horizontal surface, rise the chimney place the gasket and tighten all bolts.
−
Fill up the heater with sweet water through the 6" top filler pipe until it overflows.
−
Verify that valves G 1, G 2, G 3, PG 1, are closed on gas burner line and pilot line.
−
Open atomizing valve A 1 and A 4, check for atomizing air pressure at about 2 bar then close valve A 4, once the main flame is burning it is possible to fine adjust the combustion if needed with regulator RA 2.
−
Open air supply valve A 3 to controller instruments, check for 1.5 bar (20 psi) min. pressure on temperature controller outlet, regulate if needed with RA 1
Start pilot −
Open air supply valve A 1 and A 6 to burner for 5 to 10 min. before any other operation.
−
Open manual inlet valve, on heater gas scrubber G 1
−
Set ''big joe"' RG 1 regulator to have 7.5 bar maximum outlet pressure.
−
Open the manual valve PG 1 to gas pilot, check that the press. is about 1 bar. it can be regulated with RG 3.
−
Push "button" on CM 5 pilot guard, press "ignition» button on ignition box until pilot flame is on.
−
Once the temperature feeler from the CM 5 pilot guard is warm enough it will switch the pneumatic relay R and will supply air to the TC and HTCS and maintain AG 3 valve open.
Start main burner
8 - 26
−
Open slowly manual valve to gas burner G 2.
−
If the main burner is not starting, the TC controller could be out of its normal setting, adjust it so the main burner starts.
−
Set max. temperature 95° C on HTSD controller.
Hydrates (Heater, Texsteam pump) −
Set temperature required on TC controller maximum 90° C.
Air circuit
Main gas circuit
A1
Air inlet isolating valve
G1
Gas supply from isolating valve
A2
Air circuit bleed off or output valve
G2
Gas Shut off to burner, manual
A3
Air supply valve to instruments
G3
Gas scrubber Drain
A4
Air Isolating valve atomizing air burner
RG 1
Regulator gas, high pressure
A5
Air Isolating valve diesel pump motor
RG 2
Regulator Gas, low pressure
A6
Air isolating valve to blower
AG 1 (SDV)
Automatic valve to cut Gas to burner, controlled by (HTSD)
RA 1
Regulator Air pressure for control instruments
S
Safety valve 10 Bar
RA 2
Regulator Air pressure for burner atomizing air
AG 2 (TCV)
Automatic valve to cut Gas to burner, controlled by (TC)
RA 3
Regulator Air pressure for blower
AA 1 (SDV)
Automatic Air valve to cut diesel pump, controlled by (HTSD)
AG 3
Automatic Gas valve controlled by (CM 5)
AA 2 (TCV)
Automatic Air valve to cut diesel pump, controlled by (TC)
PG 1
Pilot Gas Isolating valve
Diesel circuit
RG 3
Regulator for Gas pilot pressure
isolating control
separator,
Gas pilot circuit
Control designations
D1
Diesel burner isolating valve
D2
Diesel line check valve
TC
Temperature Controller in thermowell, connected to TCV valves
AD 1 (SDV)
Automatic Diesel valve to cut diesel supply controlled by (HTSD)
HTSD
High Temperature Shut-Down with thermowell, connected to SDV valves
AD 2 (TCV)
Automatic Diesel valve to cut diesel supply controlled by (TC)
TCV
Temperature Control Valve
SDV
Shut Down Valve
O
Oilier for diesel pump
R
Air Relay
F
Air filter for diesel pump
CM 5
Pilot Guard
9 - 26
Hydrates (Heater, Texsteam pump)
1.2.8 Safety −
Only personnel trained in the use of the heater may operate this equipment.
−
The Geoservices heater can either operate on gasoil or gas from the separator, if H2S is expected or suspected use the gasoil burner, (H2S when burned releases SO4 another dangerous gas.)
−
Check that the heater and ignition system is grounded.
−
Check that the stack is properly mounted and that all bolts and seals are tight.
−
Before starting the heater you have to blow fresh air through the combustion chamber during 5 to 10 minutes, this to sweep any gases from previous operation and avoids an explosion. A special air blower is installed for this purpose.
−
While igniting the pilot flame the air blower should stay on and only when the main burners are operating the air blower can be turned off.
−
Stay away from the front of the burner while igniting and don't allow any other person in the area (5 m around)
−
Always turn off the main supplies of gasoil or gas when stopping the heater.
−
Beware of hot surfaces on burner or vessel.
−
Install heater outside zone 1 or zone 2.
−
Drain heaters before any transportation and use only sweet water in the bath.
−
Never use the adjustable choke as a valve.
−
Check frequently for " wash and wear " on the adjustable choke.
−
Remove measuring instruments before hammering on the wing unions.
−
Use a sand trap when sand or salt production is expected in gas wells.
−
Never flow a well trough the heater if no choke or choke seat is installed, this to protect the internal threat of the choke seat.
10 - 26
Hydrates (Heater, Texsteam pump)
1.2.9 Heater instrumentation layout TC
HTSD
Vent R
RA1 A3
A1
CM5 A4 Reset Button RA2
Sensor
RG1
PG1
A6 A5 AA2
A2
A1
Air Inlet
AA1
RA3
Air Burner Blow AG2 Air RG2 AG1 G2
AG3
Gas Pilot
RG1
Gas Burner
G1
Scrubber To Diesel Burner
AD2
AD1
Gas Inlet
G3
D2 D1 Diesel Pump
Diesel Reservoir
11 - 26
Hydrates (Heater, Texsteam pump)
1.2.10 Trouble shooting PROBLEM
CAUSES
Pilot flame off, burner stopped
Check:-valve PG 1 is open-pilot gas supply bottles-pilot gas press. is at least 0,4 bars-if air supply is on-if TC temp. setting is above HTSD setting-if there is any liquid in gas pilot line (drain scrubber)
Burner stopped
Pilot flame off, (see above), fuel or gas supply low or finished, Temperature set on TC is reached, bad atomizing air or off.
Bad combustion
Check if atomizing air is working properly (valve A 4 open, A 6 closed) sufficient pressure for fuel and air, see burner section for further remedies.
Water boiling
TC and HTSD set to high, temperature controller’s defect. Or water level to low.
CM 5 pilot guard does not come on after ignition.
Adjust temperature sensor (bulb) closer to the pilot flame inside the burner housing.
Diesel supplies pressure to low.
Not sufficient air supply, oilier O empty or air filter F plugged.
Note: Before any intervention on the burner circuits you have to close all manuals operating fuel and air valves, beware of hot surfaces.
1.3 HIGH PRESSURE INJECTION PUMP 5002 TEXSTEAM 1.3.1 Description Chemical injectors are positive displacement type units powered by integral gas motors. These injectors fill the requirements of a broad range of applications because of their ability to achieve high discharge pressures (up to 20,000 psi) and wide volume ranges. A horizontal plunger and vertical resilient check valve arrangement assure high operating efficiency. The standard pump head has a Ductile Iron body and 10-8 stainless steel trim. All Stainless steel heads are also available for highly corrosive applications. A built-in priming valve facilitates pump head priming, enables the operator to easily check pump operation and offers a sample-catching device. The pump frame and body castings are high-strength aluminum. The operating mechanism operates in oil and is protected against dust and other atmospheric influences. A standard equipment safety valve offers protection against accidental overpressure of the main diaphragm. The adjustable packing is equipped with a lantern ring and a grease jack for lubricating the plunger and packing to insure long life. No grease jack is furnished with Teflon packing.
12 - 26
Hydrates (Heater, Texsteam pump)
1.3.2 Applications −
Introducing detergents in air-gas drilling operations.
−
Blending foaming agents in water ladened gas wells.
−
High-pressure addition of fluid compounds in blending and chemical processing.
−
Pilot laboratory procedure involving high-pressure circulation of mercury and other test substances.
−
Introduction of desalting agents, de-emulsifiers, inhibitors and flocculent in crude oil and gas streams.
−
High and low pressure lubrication systems.
−
Methanol and alcohol injection in gas systems to prevent freezing.
−
General high-pressure injection applications.
−
Fluid blending of extreme pressure within varied, controlled processes.
−
Hydrostatic testing.
−
Glycol circulation.
−
Pumping liquefied gases.
−
Water treatment.
−
High-pressure sampling.
13 - 26
Hydrates (Heater, Texsteam pump)
14 - 26
Hydrates (Heater, Texsteam pump)
1.3.3 Characteristics •
Model n°
5002
•
Plunger size
¼"
•
Operating ratio gas/fluid
1000/0
•
Maximum discharge pressure (psig)
•
Hard packing
20 000
Soft packing
3 000
Maximum volume Intermittent GPH
0.83
Intermittent GPD
20
Continuous GPH
0.67
Continuous GPD
16
GAS CONSUMPTION CHART Injection pressure in psi 50
1/4" piston Long stroke
Injection pressure in psi
1/4" piston Long stroke
280
1,000
306
100
281,2
1,500
318
150
282,4
2,000
330
200
283,6
3,000
356
250
284,8
3,500
368
300
286
4,000
380
400
289
5,000
404
500
292
6,000
428
600
294,6
7,000
452
700
297,2
8,000
476
800
300
9,000
500
900
303
10,000
522
Standard cubic feet of gas required to pump one gallon.
15 - 26
Hydrates (Heater, Texsteam pump)
1.3.4 Installation After removing pump from carton, inspect for possible damage in transit from factory. If the pump has been damaged, file claim with carrier. Bolt holes are provided for a permanent mounting (see drawing for dimensions). If more detailed information is required, request TXT Blueprint. Connect the suction line to pump head. When a reservoir is furnished with the pump, the suction line is already connected. Fill the reservoir and open (all the way) the sight feed shut-off assembly. It is important to have the valve open all the w ay when the pump is in operation because the valve seals-off in the open position and prevents air from entering the suction line through the valve. A dual strainer is furnished as part of this unit. When a power unit model (less tanks) is purchased, a strainer should be piped into the suction line to prevent sand, rust or other particles, which score the plunger or possible four the check valves, from entering the pump head. The sight feed assembly which can be used with the 3/8" and ½" plungers only. A street ell and nipple is required to pipe the sight feed into the bottom bushing of the pump head. This should be installed as shown. the inlet connections on the pump head and the sight feed are ¼" FPT. Connect the discharge line. The top connection on the pump head is the fluid discharge and has a female ¼" pipe thread connection. A line check should be installed in the discharge line as close to the point of injection as possible. For pumps with 3/8" plunger, offers a ¼" line check either in brass or stainless steel which will withstand working pressures of 3000 and 6000 psi respectively. For further plunger sizes, ½", 1 and 1¼", offers the stainless steel line check which withstands pressures up to 6000 psi. When installing these check valves note the arrow on the body, which indicates the direction of flow. Connect the power gas line. First blow power gas line clean to remove any loose rust particles, slag, sand, etc. Consider the pressure requirements of the pump. If the gas supply exceeds 50 psi (consider erratic pressure), the pump should be equipped with a regulator to reduce the gas pressure to 50 psi. Note: The regulator pipe (Item 2, General Assembly) between the inlet valve and pilot valve is for reducing only a small part of the gas supply to actuate the master valve. It does not reduce the main gas supply. Caution: The regulator does not regulate the pressure of the main gas supply. It is factory set at 12 psi. Do not readjust them unless the pressure gauge indicates reading other than 12 psi. This is important because over-pressure will cause excessive wear.
16 - 26
Hydrates (Heater, Texsteam pump) The safety valve is for protection of the diaphragm and is set at 50 psi. Pressure on the diaphragm should not in any case exceed 50 psi. Tie in gas line into inlet valve. Lubrication. Remove the cover plate and fill the chamber next to diaphragm with oil. Insert stick lubricant into the grease jack. No lubrication is required if the pump is equipped with Teflon packing and chrome-plated plunger. Adjust for desired volume by considering pump speed (see charts) and position of pin. Different volumes can be achieved by short and long stroke setting (see charts). The pump is assembled with the plunger travel-adjusting pin inserted in the hole of the plunger nearest the plunger-packing gland nut. This is the position of longest stroke. To shorten the stroke places the pin in the other hole.
1.3.5 Operating instructions Start the pump by slowly opening the inlet valve. Prime the pump head by opening the priming valve. After the pump discharges fluid without bubbles, close the priming valve for normal operation. At this point make a visual check of the plunger drip and using a flat blade screwdriver slowly tighten the gland nut to prevent excess drip and waste of chemicals. Do not overtighten plunger packing. It may be necessary to readjust the packing the next day. A slight leak during the break-in period is beneficial. Sufficient time should be allowed to let the packing "seat-in". Do not adjust packing under pressure. If low volumes are being pumped, the pump head, the fluid discharge line and all other fittings-up to the line check should be thoroughly purged of all air bubbles. If, in replacing parts in the pump head, corrosion is noted, notify the TXT factory of the type and name of the manufacturer of the compound being pumped. If any excessive wear or excessive replacement of parts is noted the TXT factory should be notified and the failing part numbers be identified. We are endeavoring to build the best equipment possible and your suggestions are always appreciated.
1.3.6 Maintenance Inspection of Pressure Regulator Loosen lock nut, back out regulator screw, remove the five body screws and lift-off bonnet. Lift out and inspect adjusting spring disc and adjusting spring. Unscrew lock nut and lift out adjusting spring plate, diaphragm, body gasket and diaphragm nut gasket. To inspect other parts, unscrew cap, lift out cap gasket. At this point seat block pin must be removed with punch. When pin is removed, valve seat assembly (reversible) and orifice screw can be removed. Now the valve seat block yoke can be lifted out through other side of body. Check inlet filter screen for obstructions. Reset regulator at 12 psi.
17 - 26
Hydrates (Heater, Texsteam pump) Master Valve Assembly Remove the six cap screws, remove housing cap and inspect diaphragms. After removing the diaphragms, the stem may be removed. To inspect valve spring, valve disc and lower valve seat, unscrew upper valve seat. Inspecting Pilot Valve Assembly Unscrew disc retainer, lift out valve spring, washer and valve disc. Close inspection of the valve disc sealing surface and drive socket slot is necessary. Very close inspection of the drive pin should be made, if ends are worn, the valve disc should be replaced. If body and valve discs are badly scored, replace. Realignment of the valve disc is important. Refer to positioning diagram. Replacement of diaphragms, spring and Related Parts Remove regulator, valve, and master valve. Remove 16 bolts. The cover is under tension. Care should be exercised when removing the last bolts. Two C-clamps or 5/16" x 2 (slightly longer than bolts) would be very helpful for this work. Trouble Shooting If the pump stops with plunger in extreme discharge position and gas or air is being discharged from the safety valve, or a constant discharge of gas or air is discharged when the safety valve lift ring is pulled, the diaphragm in the master valve is burst. If the pump does not more forward and a constant discharge of gas or air is observed in the lubricating oil chamber then the main diaphragms are ruptured. Pump is operating but not pumping fluid. −
Open bleeder valve to break air lock.
−
Check if sight feed shut-off assembly is screwed in "out" position.
−
Check top and bottom balls and seats for leaking.
(Refer to parts lists on next pages)
18 - 26
Hydrates (Heater, Texsteam pump)
1.3.7 Parts list 1. 2. 3. 4. 5. 6. 7. 8 9. 11. 12. 13. 14. 15. 16.* 17. 18. 19. 20. 21. 22. 23. 25. 26. 27. 28. 29. 31. 32. 33.* 34.
Pressure gauge 0-12 psi Pilot valve Nipple Inlet gas valve assembly Half union Master valve Attachment nipple Half union Line assembly from pilot valve to master valve (Copper) Air filter Elbow Elbow Cap screw Line from pilot valve to reg. Gasket Pilot valve assembly Grease jack Bolt 304SS Priming valve Nipple Strainer sight feed assembly Standard head assembly Body Screw Base Retainer Ball Housing Disc Spring Cover
35.*
Diaphragm (2 required neoprene)
36.
Drain plug
37. 38. 39. 41. 42. 43. 44. 45. 46.
Diaphragm housing bolts Bushing ¼" Safety valve set 50 # Set screw Screw Bolt Nut Gasket Base
47. 48. 49 50. 51. 52. 53. 54.* 55. 56. 57. 58.* 59.* 60.*
Pin Cover Flipper connection pin Stuffing box Gasket Nut Housing Packing Thrust Rod Screw Outlet body Spring Ball 3/8" 316SS O' ring Buna-N O' ring Viton Inlet body Outlet body Inlet body Washer Body Valve O'ring Buna-N
61. 62. 63. 64. 65. 66. 67.*
O'ring Viton 68.*
O'ring Buna-N O'ring Viton
69.
Bushing
*Recommended spare parts
19 - 26
Hydrates (Heater, Texsteam pump)
20 - 26
Hydrates (Heater, Texsteam pump)
1.3.8 Parts list 1.*
Upper valve seat
31.
Cotter pin
2.*
Valve spring
32.
Clevis pin
3.*
Valve disc
33.
Body C.I.
4.*
Lower valve seat
35.*
Valve Disc
5.
Housing, alum
36.*
Washer
6.
Cap bolt
37.*
Spring, SS
7.
Stem assembly
38.
Disc retainer
8.*
Diaphragm
39.
Washer
9.
Housing cap
40.
Cap screw
10.
Cap nut
41.
Elbow
11.*
Bowl
42.
Cap
12.*
Gasket
43.
Cap gasket
13.
Bushing
44.
Seat block pin
14.
Screen
45.*
Valve seat assembly
15.
Body
46.
Filter screen
16.
Shut-off assembly
47.
Orifice screw
17.
Body
48.
Body
18.*
Packing
49.
Valve seat block yoke
19.
Gland nut
50.
Diaphragm nut gasket
20.
Nut
51.*
Body gasket
21.
Valve stem
52.*
Diaphragm
22.
Lock pin
53
Spring plate
23.
Bearing
54
Lock nut
24.
Socket cap screw
55.
Spring
25.
Flipper bearing pin
56.
Spring disc
26.
Flipper arm
57.
Body screw
27.
Spring connector
58.
Bonnet
28.
Flipper spring
59.
Lock nut
29.
Flipper assembly
60.
Adjusting screw
30.
Flipper arm assembly
61.*
Drive pin
*Recommended spare parts
21 - 26
Hydrates (Heater, Texsteam pump)
22 - 26
Hydrates (Heater, Texsteam pump)
1.3.9 Injector head parts list 1.*
Plunger (armaloy - 17.7 ph)
2.
Packing gland nut, C.S. cad.
3.
Packing gland 303SS
4.
Lantern ring 303SS
5.
Packing, buna-N
6.
Pipe plug
7.
Top busing 303SS
8.
Check ball spring 316SS
9.
Gasket 304SS
10.*
Top check ball 3/8" 316SS
11.*
Top check valve seat assy 303
12.
Pump head
13.
Ball cage 303SS
14.*
Bottom check ball 316SS
15.*
Gasket 304SS
16.*
O'ring buna-N
17.*
Bottom check valve seat 303
18.
Bottom bushing 303SS
19.
Priming valve (not shown)
25.
O'ring buna-N (included in item 11)
5-A
Packing Teflon Hard above 3000 psi
11-A* Top seat (metal to metal) 303 16-A
Viton O'ring
17-A* Bottom seat (metal to metal) 303 25-A
Viton O'ring
*Recommended spare parts
23 - 26
Hydrates (Heater, Texsteam pump)
INJECTOR HEAD
24 - 26
Regulators
SECTION 18 REGULATORS
1-1
Regulators
1.1 ROLE •
To reduce the pressure
•
To keep the downstream pressure constant
•
To act, if necessary, as a filter.
1.2 DESCRIPTION Regulators are generally composed of: •
A body in several parts
•
A diaphragm
•
A calibration spring
•
A plug, its seat and a plug spring
•
A filter element can be added
1.3 OPERATION In order to go from upstream of the regulator to downstream, the gas to be reduced passes across a plug seat system. The downstream pressure, against the diaphragm, causes a force that is counter-balanced by the tension of the calibration spring. Adjustment of the spring tension will enable the value of this force to be adjusted. Let us examine what happens when the downstream pressure in the regulator varies: •
The downstream pressure is reduced The spring tension is then greater than the force exerted by the gas pressure o the diaphragm; consequently:
•
•
The plug moves away from its seat
•
The downstream pressure increases until the desired value is reached.
The downstream pressure is increased The spring tension is then less than the force exerted by the gas against the diaphragm. Consequently: •
The plug pushed by its support spring, approaches its seat
•
The downstream pressure falls until the desired value is reached.
1.3.1 Dismantling and assembly This aspect will be covered when studying the individual regulators.
1.3.2 Adjustment The value of the downstream pressure range will be a function of the spring used. To reduce the value of this range, a change of spring following the manufacturer instructions is all that is necessary.
2-2
Regulators The value of the downstream pressure (within its range) is obtained by adjusting the spring tension with the aid of an adjustment screw. This tension plays the role of a set point.
1.3.3 Maintenance •
Purge frequently
•
Clean the porous cartridge if there is one.
1.3.4 Breakdowns •
Pierced diaphragm
•
Blocked filter
1.4 TYPES OF REGULATORS We are now going to study four types of regulator •
FISHER type 67 FR
•
FISHER type 1305 antifreeze
•
FISHER type 621
•
FISHER type 630 "Big Joe"
1.4.1 FISHER 67 FR Regulator 4.1.1
ROLE
The object of this type of regulator is to supply, at constant pressure of air or gas, all sorts of pneumatic controllers. 4.1.2
OPERATION
This has already been studied. Nevertheless, one should note the small channel providing the communication between the regulator output and the diaphragm. REMARK If the downstream pressure is too great, the gas or air can vent through the hole in the middle of the diaphragm. •
During normal operation, this hole is covered by the tapered top part of the plug.
•
The gas can vent to the atmosphere through an orifice in the bonnet cap, an orifice that also allows the diaphragm to "breathe" during normal operation.
4.1.3
DISMANTLING AND REASSEMBLY
To dismantle the bonnet cap, begin by removing the spring calibration adjustment screw. 4.1.4
ADJUSTMENT
The outlet pressure from the regulator is marked on the bonnet cap. The different ranges possible are:
3-3
Regulators
Spring Range (In bars)
Spring Color
0.35 to 1.4
GREEN
0.35 to 2.4
SILVER
2.1 to 4.2
BLUE
3.85 to 7
RED
We generally use spring range 0.35 to 2.4. REMARK Each spring can nevertheless produce an outlet pressure equal to O. To change the regulator output pressure: o Unscrew the locknut (11) o Turn the adjustment screw (10) § screw to increase output pressure § unscrew to decrease output pressure o Retighten the locknut. The maximum input is 17.5 bars (250 PSI). 4.1.5
4.1.6
4.1.7
MAINTENANCE •
Purge frequently
•
Clean the porous cartridge.
BREAKDOWNS •
Pierced diaphragm
•
Blocked filter
67F AND 67FR SERIES REGULATORS WARNING Regulators should be installed, operated and maintained in accordance with federal, state and local codes rules and regulations and Fisher instructions. If the regulator vents gas or a leak develops in the system, it indicates that service is required. Failure to take the regulator out of service immediately may create a hazardous condition. Call a serviceman in case of trouble. Only a qualified person must install or service the regulator. INTRODUCTION The Type 67F and 67FR regulators are designed to provide a constant reduced pressure (air or gas) to pilot operated controllers and instruments. They can also be used for air spray guns, air jets, and other miscellaneous air and gas applications. Both the Type 67F and 67FR regulators are constructed with a filter. The cellulose filter removes particles greater than 0.0015" diameter. A stainless steel or brass filter removes particles greater than 0.002" diameter. The 67FR is designed with an integral low capacity relief valve. The metal valve stem seats against an orifice in the diaphragm head, which allows some leakage. (The amount is insignificant on air service.) A downstream pressure increase above the control point.
4-4
Regulators Control point will move the diaphragm off the valve stem, venting the excess pressure to the atmosphere through a drilled vent in the spring case. INSTALLATION WARNING The vent hole drilled in the bonnet must not be plugged. On outdoor installations this hole should be in the down position. If this is impractical, protect the regulator so that moisture cannot enter the vent. The Type 67FR must not be used for applications where gas cannot be vented to the atmosphere. All pipelines should be thoroughly cleaned and blown out before installing the regulator. Be sure that flow is in accordance with the letters denoting "IN" and "OUT" on the body. Inlet and outlet connections are tapped ¼" NPT. Install with the drain cock down. The drain cock (key 17) should be opened periodically to allow moisture, which has accumulated to drain. The regularity with which this is done will depend on how much moisture is in the system. OVER-PRESSURE PROTECTION As is the case with most regulators, the Series 67F and 67FR have an outlet pressure rating lower than the inlet pressure rating. Some type of over-pressure protection is needed if the actual inlet pressure exceeds the 100 psig maximum operating outlet pressure rating. The maximum inlet pressure rating is 250 psig. Over-pressure protection should also be provided when the inlet pressure is greater than the safe working pressure of downstream equipment. Full-capacity downstream relief protection must be provided with the 67F design if upstream pressure is high enough to damage equipment downstream. This also applies to the 67FR design, which only provides for low capacity relief. ADJUSTMENT The outlet spring range is shown on the paper label attached to the bonnet. Outlet pressure spring ranges are as follows: Spring Range in psig 3-20
Spring Color Green
5-35
Cadmium
30-60
Blue
35-100
Red
The above spring ranges are recommended, although reduced pressure down to O psig may be obtained with each spring. To change the outlet setting of the spring, first loosen locknut (key 11). Then turn adjusting screw (key 10) clockwise to increase outlet setting or counter-clockwise to decrease outlet setting. Be sure to tighten locknut after changing the setting.
5-5
Regulators
FISHER FR 67
6-6
Regulators MAINTENANCE CAUTION Before disassembly or removing the regulator from the line, isolate it from the pressure system and release all the pressure from the regulator. Due to normal wear, parts must be periodically inspected and replaced if necessary. The frequency of inspection depends on the severity of the service conditions. Before disassembling the unit for diaphragm replacement, loosen the locknut and turn the adjusting screw counter-clockwise until there is no compression on the spring. Remove the six screws (key 12) and separate the bonnet from the body. This exposes the diaphragm (key 7) for replacement. To replace the valve plug, remove the four cap screws (key 18) and remove the filter cap (key 25). The filter adapter (key 13) can now be removed with a deep socket wrench to gain access to the valve plug (key 4). When the filter element (key 29) becomes dirty, it should be cleaned with solvent and blown out with air or replaced. TYPE NUMBER When corresponding with the factory or representatives in regard to this regulator, always give the type number found stamped on the body. Refer to the complete part numbers when ordering parts.
1.4.2 FISHER 1305 ANTIFREEZE REGULATOR 4.2.1
ROLE
The aim of this regulator as its name indicates is to prevent the formation of hydrates during gas reduction. 4.2.2
DESCRIPTION
A small calibrated orifice (1) located upstream of the regulator causes the reduction. This orifice is always installed inside the separator where the gas is hottest. The heat is transmitted to the reduced gas by fins (2) located on the input adapter. This system enables the temperature of the input gas to be increased and also prevents the formation of hydrates. The task of the stem (3) linking the orifice to the bottom part of the diaphragm is to vary the quantity of gas input according to the fluctuations of the downstream pressure in the regulator. These pressure fluctuations are transmitted to the diaphragm. 4.2.3
OPERATION
Fall in downstream pressure: The spring pushes back the diaphragm, which consequently uncovers slightly more of the input orifice. As a result, the downstream pressure in the regulator is re-established. Increase in downstream pressure:
7-7
Regulators The pressure pushes back the diaphragm, which consequently closes slightly more of the input orifice. As a result, the downstream pressure in the reducer is re-established. 4.2.4
DISMANTLING AND ASSEMBLY
Dismantling presents no particular difficulty. Start by disconnecting the union (4). During these operations, proceed extremely carefully in order to avoid blocking the bosses of the stem, linking the orifice with the diaphragm. 4.2.5
ADJUSTMENT
The regulator output pressure is marked on the bonnet cap. It is a function of the type of spring used: •
10 to 75 PSI
•
50 to 150 PSI
•
100 to 225 PSI
•
200 to 500 PSI
As for other regulators, adjusting the spring tension can set the output pressure. 4.2.6
MAINTENANCE
It might be necessary to replace the disc opposite the orifice, on the end of the stem. To do this: •
Disconnect the union
•
Unscrew the disc carrier and replace it.
FISHER TYPE 1305 ANTIFREEZE REGULATOR
8-8
Regulators
1.4.3 FISHER TYPE 621 REGULATOR 4.3.1
ROLE
It is used on GEOSERVICES Heaters to reduce the supply gas for the principal burner. This reduction is carried out between the scrubber working at 100 PSI and the principal burner, which must be supplied between 10 and 25 PSI. 4.3.2
DESCRIPTION
•
A body (1) contains the spring and diaphragm.
•
A pipe (2) providing the communication between the bottom part of the diaphragm and the regulator output.
•
A calibrated orifice (3) allowing the fall in pressure.
•
A disc (4) more or less covering the calibrated orifice according to the variations in output pressure.
•
A linkage system (5) connecting the disc to the diaphragm.
4.3.3
OPERATION
The gas is reduced across the calibrated orifice. As for all regulators, a variation in the downstream pressure causes the disc to be displaces, thus enabling the passage of gas to be increased or reduced. As a result, the downstream pressure is re-established. 4.3.4
DISMANTLING AND ASSEMBLY
Nothing particular except during assembly: Replace the adjustment screw by compressing slightly the spring before retightening the bonnet cap positioning screw - this is done in order to give the diaphragm a bit of slack, enabling the regulator to work (do not forget it is a controller too). 4.3.5
ADJUSTMENT
The output pressure range is a function of two parameters: •
The spring
•
The diameter of the orifice, which can be changed according to the flow, anticipated.
On our regulators, we use: •
The type 10 - 25 PSI spring
•
The 3/8" orifice.
This information can be seen on the bonnet cap. The adjustment of a precise output pressure is obtained by regulating the spring tension.
9-9
Regulators 4.3.6 •
MAINTENANCE Disc and orifice inspection
You can easily do this by unscrewing the union, which connects the body (fixed on the tubing) to the diaphragm assembly. •
Make sure that the union is correctly tightened.
•
In the case of leakage from this point, change the gasket.
•
To remove the diaphragm:
4.3.7
a)
Remove the adjustment screw
b)
Remove the bonnet cap positioning screw
c)
Remove the diaphragm assembly-head by disconnecting the push rod (6) of the arm (7).
BREAKDOWNS
PIERCED DIAPHRAGM
10 - 10
Regulators 4.3.8
TYPES 620 AND 621 INSTALLATION Uncrate and inspect the regulator. Be certain that the body and seat ring are clean. Remove pipe scale and foreign material from the connecting pipelines. For threaded connections, coat male threads with pipe compound. The regulator may be installed in any position provided the flow is in the direction indicated by the flow direction arrow on the body. The regulator must be protected against damage by vehicles or other external sources. The operative ambient temperature range for Type 620 and 621 regulators is -20°F to +150°F. VENTS Spring-loaded Type 620 and 621 regulators have a screened vent assembly installed in the ¼" NPT spring case vent opening. Remove the vent assembly and install a remote vent line if necessary. Loading regulators for pressure-loaded constructions have atmospheric bleed provided by a bleed orifice fitting in the Type 1301F and an internal relief valve in the Types 67R and 67HR. WARNING The bleed orifice or relief valve of the pressure-loading regulator continuously vents a small amount of gas. Explosion of accumulated gas could cause personal injury or equipment damage. If the regulator is located where accumulation of the vented gas will create an explosion hazard, install a remote vent line to carry the vented gas to a safe area. Type 1301F belled orifice is furnished with a ¼" NPT screened opening: remove the screen and install a remote vent line. Types 67R and 67HR must be specified to have a tapped spring case if remote venting is desired. Remote vent lines must have the largest practical diameter. The vent line should be as short as possible with a minimum number of bends or elbows. Protect all vent openings against entrance of rain, snow, or any other foreign material that may plug the line and prevent proper operation of the regulator. Periodically check the vent openings to be sure they are not plugged. OVER-PRESSURE PROTECTION As in most regulators, the Types 620 and 621 spring-loaded and pressure-loaded regulators have maximum inlet pressure ratings, which exceed the maximum outlet pressure ratings. Outlet over-pressure protection must be provided if the actual inlet pressure is capable of exceeding the outlet pressure rating. Over-pressure protection may also be required for the loading regulator and main regulator spring case of pressure loaded regulators. WARNING Over-pressuring any portion of this equipment may cause damage to regulator pasts. Leaks in the regulator, or personal injury due to bursting of pressure-containing parts of explosion of accumulated gas. 11 - 11
Regulators To avoid over-pressure, provide an appropriate over-pressure protection device to ensure that none of the limits listed in tables 1 through 3 will be exceeded. PRINCIPLE OF OPERATION Refer to the operational schematic in figure 3. In Type 620 and 621 regulators, outlet pressure is registered under the diaphragm via the pilot tube and used as the operating medium. Type 621 monitoring regulator and monitoring pilot control pressure is registered through the ¼" NPT connection in the lower casing. If downstream demand increases, outlet pressure decreases. Spring compression pushes the diaphragm and pusher post down and pulls the disc away from the seat ring to permit increased gas flow. When downstream demand decreases, the outlet pressure increases. The increased pressure acting on the diaphragm compresses the spring and moves the disc closer to the seat ring to reduce gas flow. A Type 621 monitoring pilot allows quick bleed of the working pilot and main regulator of a monitoring system (see figure 4). When pressure under the diaphragm increases after the main disc (key 6) is seated, the spring-loaded back disc (key 65) (see figure 8) opens and allows pressure from the working pilot and main regulator to bleed back through the throat of the pilot. LOADING REGULATOR SUPPLY PRESSURE Use a clean, dry gas as supply pressure for the loading regulator of pressure-loaded units. Connect the supply to the ¼" NPT inlet connection of the loading regulator. The supply pressure may be obtained from the upstream piping, but be certain adequate over-pressure protection is provided for both the loading regulator and main regulator spring case. PUTTING UNIT INTO SERVICE Caution: In order to avoid an over-pressure condition and possible equipment damage or personal injury, pressure gauges should always be used to monitor pressures during startup. 1.
For pressure-loaded constructions, turn on supply pressure to loading regulator.
2.
Slowly open the upstream shutoff valve.
3.
Slowly open the downstream shutoff valve.
4.
Check all connections for leaks.
5.
If indicated by the monitoring pressure gauges, make final spring adjustments according to the "Adjustment" section. ADJUSTMENT The range of allowable pressure settings is marked on the nameplate. If a pressure setting beyond this range is necessary, substitute the appropriate main regulator spring or loading regulator spring. Change the nameplate to indicate the new pressure range.
12 - 12
Regulators Before increasing the setting, refer to manufacturing tables. Review the pressure limits for the spring range being used and be certain that the new pressure setting will not result in an over-pressure condition. Note: Always use a pressure gauge to monitor pressure when making adjustments. For spring-loaded Types 620 and 621 1.
Remove the adjusting screw cap from Type 621 (top view key 31).
2.
Loosen locknut (key 22).
3.
Increase the outlet setting by turning the adjusting screw (key 23) clockwise. Decrease the outlet setting by turning the adjusting screw counter-clockwise.
For pressure-loaded Type 621 regulators, perform adjustments on the loading regulator as follows: 1.
Loosen locknut if one is present.
2.
To increase outlet setting, turn adjusting screw clockwise. decrease outlet setting turn adjusting screw counter-clockwise.
3.
Tighten locknut.
To
TAKING UNIT OUT OF SERVICE Isolate the regulator from all pressure. For pressure-loaded constructions, shut off supply pressure to the loading regulator. Cautiously release all pressure from the regulator to be serviced before performing any maintenance on the unit. FISHER 'BIG JOE' PRESSURE REDUCING REGULATOR (630) This regulator is used to lower the separator gas pressure (max 1 500 PSI) to 100 PSI so that gas can be supplied to operate the separator instruments (in locations with no air supply) or to supply gas to the heater. The pressure reduction can depend on the size of the orifice and the spring rate. Specifications -
max inlet pressure 1 500 psig outlet pressure 3 - 40 psig or 27 - 500 psig operating temperature 20°F to 150°F.
13 - 13
Regulators
14 - 14
Regulators
1.4.4 FISHER TYPE 630 "BIG JOE" REGULATOR 4.4.1
ROLE
This regulator is used on our Heaters to lower the supply pressure between the separator outlet and the heater scrubber. That is to say, between 1500 PSI, which is the maximum reducer limit, and 100 PSI, which is the maximum working pressure limit of the scrubber. 4.4.2
DESCRIPTION
See diagram. 4.4.3
OPERATION
The same principle as for the 621. 4.4.4
DISMANTLING AND ASSEMBLY
During assembly, do not forget to put the case (3) containing the spring on the lowpressure side. The arrow on the bonnet cap indicates the flow direction of the fluid. During assembly, replace the adjustment screw by slightly compressing the spring before re-tightening the case positioning screws. This is to give the diaphragm a bit of slack. 4.4.5
ADJUSTMENT
The output pressure range is a function of two parameters: •
The spring
•
The orifice diameter.
Information about the spring and orifice is marked on the bonnet cap. a)
SPRING
On the equipment that we use, the most frequent output ranges are: •
46- 95 PSI
•
90- 150 PSI.
The output pressure desired can be adjusted by regulating the screw tension. b) ORIFICE The orifice normally used is the 3/16". In the heater body you will find 1/8" and ¼" orifices. Remember that ¼ 3/16 1/8. If the input pressure of fuel gas is weak (it is generally the separator pressure), you will have to use a large orifice and vice versa. We can see, therefore, that to obtain a correct supply pressure, one must regulate both the orifice diameter and the spring at the same time. Note: If there were a risk of the presence of H2S, you would be well advised to use Stainless Steel rather than brass orifices. 4.4.6
MAINTENANCE
•
Check that the orifice is clean.
•
Grease the male connections before tightening them. 15 - 15
Regulators •
To change the disc proceed in the following way: Remove the bonnet cap diaphragm assembly. Remove the disc carrier
Check the orifice. •
To change the diaphragm proceed in the following way: Remove the adjustment screw Remove the diaphragm assembly Replace the diaphragm.
•
To assemble: Check that the diaphragm connection stem is well fixed in the arm Tighten the bonnet cap screw before putting the diaphragm assembly back in position Do not forget to replace the adjustment screw before re-tightening the bonnet cap screws; in order to give the diaphragm the necessary slack.
4.4.7
BREAKDOWNS
See other regulators.
16 - 16
Burners and Booms
SECTION 19 BURNERS AND BOOMS
1-1
Burners and Booms
1.1 VULCAN BURNER The Vulcan burner has been designed to be a versatile burner for the clean disposal of crude oil, oil-based mud’s, and workover fluids. Although the burner can be configured in many ways due to Customer requirements, the standard Vulcan burner is equipped with six heads, each individual head comprising of: -
Venturi mixing chamber that atomizes fluid into fine droplets and where compressed air is injected into the flow. Static mixers tube where air and fluid are commingled thoroughly. A spray cone on the burner tip to achieve final atomization. A diesel or gas pilot
The four upper heads of the burner are for the disposal of well fluids and effluent. Depending on the expected flow rate, the number of guns can be selected by the opening or closing of valves on the burner oil manifold. The oil supply line to the burners is equipped with diesel injection piping to mix well effluent with diesel to achieve a more favorable burning mixture. The lower two guns are to provide a diesel or gas blanket flame to aid in the disposal of oil based mud’s, or oils with high water cut or solids. These lower guns may also be used for the disposal of surge tank contents whilst the well is flowing through the upper guns. The Vulcan burner also has water injection piping around the burner heads that enables atomized water to enter the flame. The action of high temperature on water vapor splits the water into its constituent elements that combine chemically with the hydrocarbons to improve burning, and eliminates the formation of black smoke. Also fitted to the burner head is a water screen to reduce radiated heat and enable personnel access to the burner head whilst burning is in progress. Flare ignition is carried out by the use of high-tension spark plugs igniting a gas or diesel pilot flame. Each burner head has an individual pilot to ensure early ignition of the atomized fluid from each gun. The spark plugs are connected to armored high-tension leads, which are in turn connected to three high-tension transformer units supplied by 220 or 110 V. AC supply. For added safety, non-return valves are fitted to the oil and air supply lines to prevent back flow into the boom and rig pipework.
2-2
Burners and Booms
1.1.1
Technical Data
Design pressure Working pressure Capacity Working temperature Configuration Dimensions
1.1.2
100 bars (1440 psi) at 53°C (125°F) 90 bars (1330 psi) at 121°C (250°F) 100 m3/h (15000 BPD) - 29°C to +121°C (- 20°F to + 250°F) Four 2" guns, two 1" ¼ guns Length Width Height Weight ( Stand alone )
Supplies
Air (Maximum rate) Water (Maximum rate) Diesel (For injection) Electricity (for pilot ignition system)
1.1.3
2650 mm (8.70 ft) 1200 mm (3.93 ft) 1650 mm (5.41 ft) 600 kg (1320 lbs.)
17 m3/min (600 cuft/min) at 10 bars (150 psi) 1.25 m3/min (325 gal/min) at 20 bars (300 psi) 0.8 M3/min (215 gal/MN) @ 10 Bars (150 psi) 220 V AC 50 or 60 Hz
Special Features Four main 2" guns for oil/mud burning Two independent 1" ¼ guns for diesel blanket or auxiliary burning Two stage atomization device consisting of: A mixing chamber preparing fluid/air mixture A static mixer gun producing fine spray Diesel injection capability on the main heads Two independent water lines equipped with nozzles for water injection into the flare to improve combustion and prevent black smoke Water screen around the guns to reduce heat radiations Individual gas/diesel pilot and ignition system on each head Supporting frame with two pivots and swivel joints permitting +/- 74° rotation
1.1.4
Safety Devices Non return valves on oil, air and diesel lines OPTIONAL EQUIPMENT Steam injection for heavy oil burning Diesel injection unit Remote operated pneumatic/hydraulic-rotating device Remote control valves on water lines for accurate adjustment of water injection rate
3-3
Burners and Booms
1.1.5
Connections
Oil Water screen Water injection Diesel injection Air Diesel cushion Pilot gas
1.1.6
Diameter 3" 2" 2" 2" 2" 2" ½"
B/
Water screen Floor to centre 1280 mm 390 mm line of flange (4.20') (1.28') connection Centre line of 0 421 mm(*) flange (1.38') connection to centre line of unit
(*) Connected through flexible hose
4-4
Weco 3" fig. 602 female 2" fig. 602 female 2" fig. 602 female 2" fig. 602 female 2" fig. 602 female 2" fig. 602 female
Position of Connections Oil
A/
Flange 3" 600 # RF 2" 150 # RF 2" 150 # RF 2" 600 # RF 2" 150 # RF 2" 600 # RF NPT
Water injection 390 mm (1.28')
Diesel Air Diesel injection cushion 990 mm 479 mm 180 mm (3.25') (1.57') (0.59')
421 mm(*) (1.38')
0
0
0
Burners and Booms
1.2 OPERATION OF THE VULCAN BURNER 1.2.1
Installation Install the burner on the boom in accordance with current certification. Connect the burner oil, water, air and diesel pipework to the boom pipework according to table 4. These connections and the burner valves and non-return valves must be pressure tested. Connect the gas or diesel supply to the pilot connections. Connect the air supply to the pilot connections. Connect the spark plugs to the high-tension cable, feed the high-tension cables through the protective shielding, and connect them to the ignition transformers. Connect the ignition transformers to the correct voltage AC supply. Turn on the air and gas or diesel supplies to the burner pilots. Press and hold the igniter button. The spark plugs will spark every two seconds, and should ignite the pilots. Regulate the pilot flame.
1.2.2
Burner start up and operation Determine the wind direction, and orientates the burner head so the wind direction is blowing parallel and from behind. Depending on the expected oil Flow rate open the required number of burner guns. Turn on the gas or diesel pilot supply; turn on the pilot air supply. Ignite the pilot by pressing and holding the ignition button. If ignition is not immediate, regulate the gas or diesel supply and try again. Start the air compressor and send air to the burner head at about 1-2 bar. Make sure the pilots remain lit. Start the water pump. Open the water valve to the water injection rings. Make sure that you have good atomization and that all the water nozzles are free and unplugged. Decrease the water supply, by regulating the valve, to the minimum to achieve good atomization. If a diesel or gas flame blanket is being used, slowly open the supply valve to the burner. When flare ignites, regulate the flame by adjusting the supply valve. The diesel blanket will normally burn with black smoke, as air will flow preferentially to the upper guns until oil production is being sent to them. Slowly open the oil supply valve to the upper burner nozzles. The burner should ignite, and burn with black smoke. Slowly increase the burning rate to the maximum by opening the oil and air supply valves to the burner. Black smoke will be reduced by the addition of more air. Do not increase either the air or oil supply without adjusting the other. When a stable flame is produced at the maximum flow-rate, increase the water injection into the flare by slowly opening the water supply valve. The black smoke will become thinner and eventually disappear. It should be noted that a lack of air would produce fallout and black smoke, especially at low flow rates. Fallout and black smoke will decrease with the addition of more air, and fallout can be eliminated completely when the right balance is achieved. The addition of water will stop black smoke formation, but
5-5
Burners and Booms too much water will cause fallout, even before you start to produce grey smoke.
1.2.3
Checks whilst the burner is in operation. -
Air supply piping is free from any return of hydrocarbons. Water nozzles remain unplugged and atomization is even and good. Wind direction is correct for burner orientation. There is no fallout and black smoke is minimized.
A close check should be made whilst burning on abrasive solids in oil or for drilling mud, etc. These fluids can be very damaging to the venturi and burner tips leading to poor atomization of oil and reduced burning efficiency. Fallout will become evident and steadily worsen under these conditions. Replacement of the affected parts should be carried out at the first opportunity.
1.2.4
Stopping Burning To stop the burning operation:
1.2.5
-
Close the oil supply valve to the burner.
-
When the flame is extinguished, allow the air to continue for a few minutes, before slowly closing the air supply valve. Hot oils or oil with dissolved gas will often re-ignite the burner briefly as the air pressure is decreased.
-
Shut down the pilot flame.
-
Let the water screen flow for a few minutes to cool the burner.
-
Flush the water line with fresh water to remove corrosive seawater.
-
Perform routine maintenance to prepare for the next job.
Methods to enhance burner performance Good burning is dependent on good atomization. Atomization can be improved by trying to attain the highest possible burner pressure. A minimum of 10 bar (150 psi) is recommended. If the flow rates are too low to achieve these pressures, the addition of increased compressed air has a positive effect on burner performance. Compressed air should slowly be increased as too high a velocity of an air/oil mixture leaving the burner tip can cause late ignition and the burner flame can be extinguished. The increase of compressed air to the burner will cause backpressure on the oil line and sometimes reduced oil flow. Caution should be taken to observe separator levels during burner adjustment. Correct maintenance of the burner is simple but imperative if clean burning is to be achieved. Before the start of every job the following safety and maintenance checks should be done. •
6-6
The burner tips should be checked for signs of wear. If they are worn the burner gun should be dismounted and the venturis, twisted parts, and burner tip should be replaced if worn.
Burners and Booms
1.3
•
The spark plugs and high-tension leads should be inspected for signs of corrosion or damage. Make sure there is no dirt on the spark plug tip that may cause shorting.
•
The pilot’s head must be dismantled and cleaned.
•
Propane flow rate or gas oil/compressed air ratio must be adjusted.
•
The water spray system must be cleaned and function checked.
•
The pressure test of the burner head is compulsory in order to verify the efficiency of the check valve on the compressed air line.
SAFETY Use of the burner is the single largest source of ignition during normal rig operations. The Vulcan Burner is designed for ease of use and is a safe operation. To maintain safe working conditions, certain guidelines must be followed before the start, and during the burning operations. 1. The Burner must only be operated by trained personnel who are familiar with its operation. 2. Before starting any Burner operations all process lines and connections to the burner must be pressure tested. 3. The burner head isolation valves, and non-return valves on the air, oil, and diesel lines must be operational and pressure tested. 4. Burning operations must only be started upon direction from the customer. Stopping burner operations is upon direction of the customer or upon discovery of equipment malfunction. 5. Burning during boat or helicopter operations may be hazardous. Checks must be made for these, and other operations, that may interfere with burning. 6. A crew of fire fighters must be standing by during burning operations, to cool overheated equipment and structures. 7. Information on the estimated flow rate, oil viscosity and gravity should be obtained before the start of burner operations. 8. Burner set-up may be modified whilst burning, as the burner does not radiate excessive heat towards the rear. Certain safety rules must be observed whilst modifications to the burner set-up are made. − − − − − −
Wear cotton or flame retarding materials. Work clothing must not be made of Nylon or similar synthetic material. Wear work gloves. Wear safety goggles & ear protectors. Wear a life jacket or buoyancy aid. Secure yourself with a safety harness. Always have fire fighters and a rescue team present to lend assistance.
7-7
Burners and Booms
1.4 RECOMMENDED SPARE PARTS 1 ignition box 2 high-tension cables 2 spark plugs 50 water nozzles 1 complete burner head assembly 2 ½ 1 complete burner head assembly 1 ½ 1 'O' rings kit 1 complete gas pilot assembly 1 ball valve 2" 1 ball valve 1 ½ 1 swivel 3" 2 'O' rings for swivel 3" 4 bolts for flanges 4 rings for flange 1 ½" 4 rings for flange 2" 4 rings for flange 3" 1 check valve 3" 1 check valve 2" 2 venturi cones 6 grey lock seal 2" 2 grey lock seal 3"
8-8
Burners and Booms
Vulcan Burner Troubleshooting guide No
Have all maintenance procedures been carried out ?
Carry out maintenance
Yes Pressure test burner Pressure test successful?
No
Yes No
Orientate Burner
Burner orientated correctly for wind direction ? Yes Ignite Pilots Adjust Gas or Diesel supply
Check power supply and high tension circuit Pilots ignited ? No Start Water Injection spray Reduce water to minimum
No
Yes
Start air compressor
Open air valve to Burner. Air pressure 1-2 bar
Ignite flare blanket
Diesel/gas flare blanket used? Yes
Yes
No
Flare blanket burning without fallout ? Yes
Slowly open Oil supply valve to burner Stop Burning! No If diesel or gas injection is used, Increase Injection rate
Flare ignited?
No
Yes
Check fluid constituents are they flammable?
No
Slowly increase oil and air to maximum Use Diesel/Gas Blanket Fluid burning without fallout? No Increase air Decrease Water
Yes
No
Fluid burning with black smoke? Yes No
Decrease water injection
Fluid burning with grey smoke? Yes
Increase water injection
Yes No
Improved burning? No
Clean Burn!
9-9
Burners and Booms
1.5 BOOM INSTALLATION In the following pages you will find the typical cable installation of a 60’ burner boom, delta plates mounting.
10 - 10
Burners and Booms
BOOM 60’ DELTA PLATE MOUNTING
11 - 11
Burners and Booms
DETAIL 1
VERTICAL CABLE BOOM 60’ DELTA PLATE MOUNTING
12 - 12
Burners and Booms
DETAIL 2
VERTICAL CABLE
13 - 13
Burners and Booms
DETAIL 3
14 - 14
HORIZONTAL CABLES
Burners and Booms
DETAIL 4
HORIZONTAL CABLES
15 - 15
Burners and Booms
DELTA PLATE
16 - 16
Burners and Booms
CONNECTING PLATE DETAIL
17 - 17
Burners and Booms
BILL OF MATERIAL
18 - 18
Sampling
SECTION 20 SURFACE SAMPLING
1-1
Sampling
1.1
GENERAL Samples taken at the bottom of the producing well or at surface make it possible to analyze both the physical and chemical characteristics of the reservoir fluids. Results obtained in the laboratory can only be interpreted if the sample is representative because the volume necessary for analysis is only an infinitesimal part of the fluid in place. MAKE SURE THAT NO CHEMICALS ARE INJECTED UPSTREAM OF THE SEPARATOR (Glycol, Methanol, inhibitors etc.) at the time of sampling. If any such injection is stopped before sampling, allow ample time for the chemicals to be purged from the separator. If it is impossible to operate without injection of chemicals, note the chemical used and its injection rate. The choice of a sampling method should be made according to the type and conditions of the reservoir fluid, production characteristics, bottom hole and surface equipment available. In all cases the selected method should follow the procedures described in this chapter.
Note: if possible the separator liquid and gas samples should be taken simultaneously in order to have the same sampling conditions for both fluids. Bottom Hole Sampling if any will be advantageously performed at the same time. The earlier in the well life sampling is made, the better, but the well must be properly cleaned-up.
1.1.1 Sample point check The main difficulty while sampling arises from the fact that liquid and gas are in dynamic equilibrium in the Separator: Any drop in pressure or increase in temperature of the Separator liquid, which is at its bubble point, will result in the formation of gas. For the Separator gas, which is at its dew point (this is a normal dew point - not retrograde), an increase in pressure or decrease in temperature will result in condensation of the heavy components. In any such case when a fluid becomes diphasic during sampling, it is probable that disproportionate quantities of the two phases will be collected and the sample will not be representative. Before any sampling is attempted, the sample point should be checked to make sure there is no possibility of contamination (e.g. oil or condensate carry-over for a gas sampling point; water or sludge from a liquid point).
1.1.2 Special cases If more than one separator is in use, gas and liquid samples must be taken from the first (higher-pressure) separator. In exceptional circumstances, liquid samples could be taken from lower pressure separators, but only if samples of gas are taken from this lower pressure separator and all higherpressure separators; all gas flow rates must also be measured. H2S concentrations in a sample can change due to reaction, adsorption or solution, and laboratory analyses frequently give reduced concentrations due to this. Thus, in any case where H2S is present in a reservoir fluid, on-site
2-2
Sampling analysis (even by Dredger tube) is highly recommended. Concentrations in all produced fluids should be determined.
1.2
CONDITIONING OF THE WELL The flowing period during which the samples are to be taken should be preceded by a cleaning-up period long enough to eliminate the drilling completion or stimulation fluids. Well must flow through the Separator situate as close as possible to the Well Head, to avoid any disturbance and too lengthy stabilization periods in flow lines. With client agreement, immediately after the clean-up period, a first sampling is performed for safety. (When all further samples have been taken, the samples taken at the end of the clean-up period can be discarded). Sampling should be performed when the Gas Liquid Ratio (G.L.R.) is stable; stability should normally be better than 5%. In difficult wells, variations of up to 10% may be unavoidable. In general, the longer the flow period, the better the flow stability and quality of samples. This is achieved in producing the well with a low drawdown (saturated fluid) or at a bottom hole pressure higher than the bubble point pressure (undersaturated fluid), until a stable flow is reached, in order to avoid retrograde condensation in the reservoir near the bore hole (gas well) or gas liberation in the reservoir near the bore hole (oil well). Stabilization is achieved: When well head pressure and temperature remain stable. When flow rates and GOR are stable, the temperature and pressure of separator remaining unchanged. Choice of flow rate: It depends on the productivity of the well: In high productivity wells, there is no problem. In average or low production wells or if the productivity is unknown, the choice of flow rate giving regular flow of the 2 phase liquid and gas to the Separator might be difficult: Sampling a Gas Well Flow must be high enough to avoid liquid accumulations at the tubing shoe. If the GOR decreases, keep producing until stabilization is reached. Sampling an Oil Well Flow must be maintained at the minimum steady rate. When the Gas Oil Ratio (G.O.R.) is steady between two flow reductions, then the well is producing fluid representative of the reservoir.
3-3
Sampling
1.3
ADJUSTMENT OF SEPARATOR PRESSURE The pressure must be adjusted to minimize liquid carry over at the Separator Outlet.
1.4
DOWN-HOLE CONDITIONS
The Down Hole flowing pressure shall be recorded during sampling. A pressure gradient while flowing is useful to compute the pressure at the level of perforations. Pressure and temperature of reservoir under static conditions are also necessary. All other information requested on the Surface Sampling Sheet
1.5
SAMPLING PROCEDURES - GENERAL RECOMMENDATIONS
1. CONNECTION LINE TO SAMPLING BOTTLES MUST BE AS SHORT AS POSSIBLE. Two 2.5 m Flexible Hoses with Quick Unions are provided in the Sampling Kit - one for gas sampling, one for oil sampling. 2. Full purging of Flexible Hose before sampling is necessary to make sure that the sample is representative of the fluid actually leaving the separator (i.e. for which the flow rate is measured). 3. Sample Bottles must be clean and dry. 4. OFFICIAL PRESSURE TEST MUST NOT BE DUE WITHIN THE NEXT 6 MONTHS 5. Need for duplicate samples: it is recommended that three samples of each phase (coupled if possible) be taken. This is an insurance against sample leaks or other losses and allows crosschecking of samples in the Laboratory. 6. Need for sufficient sample quantities for the entire PVT study. Condition 5. is normally sufficient. 7. Information to be given on each sample. The laboratory PVT study of the sample can be carried out properly only if all the information obtained during the well test has been noted carefully and then sent to the laboratory. Surface Sampling sheet (separate one for each sample) should be filled in completely. This means every space should have some entry with units as appropriate; an example is given hereafter. If a measurement was not made or is unknown, enter N/A for "Not applicable". Any observation about unusual character of fluid, problems during sampling etc. should be given under "Remarks". A copy of the Surface Sampling sheet must be enclosed, in a protective envelope, with the samples to be sent to the laboratory or to be stored. A COPY OF THE WELL TEST REPORT SHOULD BE SENT SEPARATELY TO THE PVT LABORATORY ALONG WITH THE TRANSPORT DETAILS 8. Reporting of sampling data should include: method and transfer fluid used, quantities (even approximate) of materials remaining in the sample bottle, and reporting any event which may mean one sample is less reliable than another.
4-4
Sampling 9. OIL BOTTLES MUST NEVER BE LEFT FULL OF LIQUID SAMPLE. A GAS CAP OF AT LEAST 10% IS COMPULSORY FOR SAMPLE STORAGE AND/OR TRANSPORTATION. 10. If 0.5 liter gas bottles are provided, fill up one bottle with gas after standard sampling is completed. This will be available for chromatographic analysis. If 0.5 liter gas bottles are not available, a standard oil bottle can be filled if required, using nitrogen as displacement fluid. As connection to oil bottle (¼" NPT x 3/16" RIC) is unique in the Sampling Kit, this sampling can be effected at the end of operation only. MAKE SURE THAT NO TRACE OF OIL OR SOLVENT REMAINS IN THE UNION. A 0.5 liter gas bottle or 628 cc oil bottle is filled in about 5 minutes. 11. Sample Bottle Checking immediately after the sampling must be performed, and once the Flexible Hoses have been disconnected, a leak test is made on the Valves by immersing them into a bucket full of water. If the test shows no leaks, the Valve outlets are fitted with Protector Plugs and sealed. Finally Bottle End Protectors are installed. If a leaking valve is detected for an oil or condensate sample, the sample is invalid and sampling should be repeated. A leaking gas sample should likewise be rejected, unless the leak is cured before any significant quantity of gas has been lost. (Pressure still within 2% of Separator pressure). 12. It is prohibited to re-use a contaminated bottle following a miscarried sampling. 13. It is recommended to fill up a 5 gal (20 liter) jerrycan with flashed Separator or Tank oil and to give it to client for his possible use. 14. For transportation purposes, the Bottle is placed into a special Transportation Container. (Together WITH Surface Sampling sheet and Maintenance Report on Sampling Bottles.) 15. Surface Sampling can only be carried out if at the minimum stabilized flow rate the G.O.R. is very close to the initial G.O.R.
1.6
GAS SAMPLING 1.6.1 Number of sample bottles to be used Take a minimum of three bottles (20 or 20 liter) for each sampling sequence for a normal PVT study to ensure full control of representativeness and sufficient quantity of sample. THIS IS IRRESPECTIVE OF GOR - i.e. ANY GOR = 3 BOTTLES. In case of low separator pressure (< 100 psi) and/or sampling with small sample bottles (less than 10 liters) the following minimum gas volumes should be collected: Reservoir Fluid Type
Volume of Gas at STANDARD CONDITIONS to be sampled
Oil reservoir
200 litres = 7 cubic feet
Gas reservoir
500 litres = 18 cubic feet
5-5
Sampling On some occasions, if the customer wants very extensive or duplicate PVT studies, additional quantities of samples may be requested.
1.6.2 Methods The following gas sampling methods are listed in order of decreasing reliability. All methods try to avoid condensation of heavy components. Separator gas behaves so, that either increasing pressure or decreasing temperature is likely to produce condensation. The vacuum method should be used in nearly all cases. 1.6.2.1
VACUUM METHOD This method is to fill a container in which vacuum has previously been made. It eliminates any condensation, since one of the bottles has been filled, it is not re-circulated. In the Lab, any condensation is re-vaporized. Evacuated bottles are normally brought up from base to the well site or Vacuum Pump is available on side. Remember the Pump and Vacuum Gauge are not explosion proof! Sample Bottles are evacuated in a horizontal or vertical position with Vacuum Pump connected to one valve, and Vacuum Gauge connected to the other valve. The minimum vacuum (maximum pressure) allowed is 10 mmHg (10 Torr) but the recommended vacuum of 1 to 2 mmHg should normally be obtained before sampling is attempted. It takes ½ hour to 1 hour to evacuate a 20 litres Bottle to the recommended void of 1 to 2 Torr. When sampling, no heating of the bottle is necessary, nor should purging or re-circulating of gas be attempted. Poor vacuum will lead to air contamination of the sample. 1. Check that the Bottle is "green" tagged, equipped with Stainless Steel Valves and fitted with End Protectors. Check that the "Maintenance Report on Sampling Bottles" is provided and correctly filled in. Make up equipment as illustrated on the drawing opposite. 2. Connect the Union and Flexible Hose to the Gas Sampling Point of the Separator. 3. Connect the Gas Bottle to the Swivel Adapter; making sure the Teflon Seal is in place. Check that the Bottom Valve of Bottle is tightly closed. 4. Open slowly the Separator Sampling Point, to pressurize sampling line (Watch Pressure Gauge). Close the Separator Sampling Point. Loosen the Swivel Connection at the Bottle: gas leaks at the connection with the Bottle. Tighten the Swivel Connection.
6-6
Sampling 5. Repeat the procedure in (4) five times. 6. Open Separator Sampling Point. Read and note pressure on Gas Sampling Pressure Gauge after allowing few minutes for stabilization. 7. Open slowly the Gas Bottle Top Valve, making sure that there is no appreciable pressure drop indicated on the Sampling Pressure Gauge. Fill up slowly the Gas Bottle, checking again that pressure remains constant. (It takes about 20 minutes to fill a 20 litres bottle, 10 minutes for a 10 litres bottle etc.) 8. Close the Top Valve of the Gas Bottle. 9. Close the Separator Sampling Point. 10. Unscrew the Swivel Joint slowly. Gas leaks as the inside pressure of the line drops to atmospheric pressure. 11. Disconnect bottle. 12. Check tightness, seal and label bottle "FULL" immediately. Place in Transportation Container and store in shade. Note Bottle number and time of sampling in the sequence of events. Do not forget to complete fully the sampling sheet and include one copy in the Transportation Container.
7-7
Sampling
8-8
Sampling 1.6.2.2
AIR DISPLACEMENT METHOD In this method the bottle contains air at atmospheric pressure, or partial vacuum. The set-up is the same as for the VACUUM METHOD. If possible the bottle should be heated to separator temperature. To ensure complete displacement of the air or gas originally in the bottle, two procedures can be used:
1.6.2.3
REPEATING PURGING After mounting connection and purging of the Flexible Hose as for the VACUUM METHOD - steps 1 to 5 1. 2. 3. 4. 5. 6.
7. 8. 9. 10. 11. 12.
Open slowly the Top Valve of Sampling Bottle Open slowly the Separator Sampling Point Valve until pressure reaches about 75% of Separator pressure. Close Separator Sampling Point Valve. Open Bottom Valve to purge the contents of the Bottle to atmospheric pressure. Close Bottom Valve. Repeat the process of filling with gas at 75% of Separator pressure and purging at least 7 times. (More often, say 10 or 12 times if Separator pressure is < 100 psi). Finally fill the Bottle to 100% of Separator pressure. Close Top Valve. No circulation of gas should be attempted. Close the Separator Sampling Point. Unscrew the Swivel Joint slowly. Gas leaks as the inside pressure of the line drops to atmospheric pressure. Disconnect Bottle. Check tightness, seal and label Bottle "FULL" immediately. Place in container. Store in shade.
Note Bottle number and time of sampling in the sequence of events. Do not forget to complete fully the Sampling Sheet and include one copy in the Transportation Container. Bottle pressure is maintained below separator pressure during purging in order to reduce the possibility of condensation. If, however, there is significant cooling at the Control Valve during filling, the filling procedure should be slowed down or stopped and restarted. 1.6.2.4
CIRCULATING 1.
2.
3. 4. 5.
Connect to the Lower Valve of the Sampling Bottle via transparent tubing: Either a Gas Flowmeter or a Gas Meter. (Measuring Volumetric flow requires a StopWatch with a Gas Flowmeter) After mounting, connection of the Flexible Hose and purging as for the VACUUM METHOD steps 1 to 5. Open the Separator Sampling Point Valve. Open slowly top Valve of the Sampling Bottle. Admit gas into the Bottle, while maintaining the smallest possible pressure drop across the Flexible Hose. When Bottle pressure reaches Separator pressure, open the Bottom Valve of the Bottle. 9-9
Sampling 6.
Circulate gas until a volume of gas equal to 10 times the produce "absolute pressure x volume of the Bottle" in a coherent unit system has been recorded on the Gas Meter.
Example:
214.7 Separator pressure = 200 psig = = 14.6 atm absolute pressure 14.7 20 litre bottle used, thus:
10 × (20 × 14.6 ) = 2900l 7. 8. 9. 10. 11. 12.
Close Bottom Valve, Wait for pressure stabilization. Close Top Valve. Close the Separator Sampling Point. Unscrew the Swivel Joint slowly. Gas leaks as the inside pressure of the line drops to atmospheric pressure. Disconnect Bottle. Check tightness, seal and label bottle "FULL" immediately. Place it in a container. Store in shade.
Note Bottle number and time of sampling in the sequence of events. Do not forget to complete fully the Sampling Sheet and include one copy in the Transportation Container. If it is not possible to maintain the bottle at Separator temperature during circulation and/or condensate is seen issuing from the Bottle Lower Valve, the circulation must be performed at a lower pressure (e.g. 75% of Separator pressure). This is done by controlling flow at the Separator Output and at the Bottle Lower Valve. If significant cooling of the Control Valves occurs, purging should be slowed down or stopped temporarily. When purging is complete (same volume as computed above), the Lower Valve is closed, and pressure allowed to build up to Separator pressure before the Bottle Upper Valve is closed. 1.6.2.5
WATER DISPLACEMENT METHOD This method is similar to the mercury displacement method; the bottle being initially full of water, which is bled off slowly as the sample is collected. Purging with gas is not usually required. The major problem in this method is the possibility of solution of the more soluble components (especially H2S and CO2 from the gas). Thus the type of water used is very important and the following three possibilities are given in order of decreasing reliability: SEPARATOR WATER
This is the best option here (if the well is producing water) because this water is already saturated with separator gas. After ensuring that the water tapping point used is not producing any separator hydrocarbon liquid (oil or condensate), the Sample Bottle should be filled by gravity from the bottom with water at separator pressure. It may not be possible for the Bottle to be installed below the water output of the Separator, but Separator
10 - 10
Sampling pressure will be sufficient to cause the water to flow. Water is circulated until 4 or 5 bottle volumes have been passed through. Purging of Flexible Hose is then made as for VACUUM SAMPLING Steps 1 to 5 but the Pressure Gauge is attached to the Lower Valve of the Sample Bottle as for oil sampling. Open the Separator Sampling Point Valve, then: 1 2 3
4 5 6 7 8 9
Open top Valve of Sampling Bottle. Open slowly Bottom Valve of Sampling Bottle. The Pressure Gauge should show Separator pressure. Bleed off water from the lowermost Needle Valve, while maintaining outlet pressure at Separator pressure. If the Bottle is at a temperature below the Separator temperature, leave 1 or 2% of water in the Bottle, to avoid loss of any condensate, which may have formed during filling. Otherwise, bleeding off is continued until the first bubbles of gas are seen at the Exit Valve. Close Bottom Valve. Close Top Valve. close the Separator Sampling Point. unscrew the Swivel Joint slowly. Gas leaks as the inside pressure of the line drops to atmospheric pressure. Disconnect Bottle. Check tightness, seal and label Bottle "FULL" immediately and place it in a container. Store in shade.
Note Bottle number and time of sampling in the sequence of events. Do not forget to complete fully the Sampling Sheet and include one copy in the Transportation Container. SALT WATER (Only if water cut = 0)
This can be true seawater or fresh water, which has been saturated with common salt (sodium chloride). With the bottle full of salt-water, mounting, connection and purging of tubing should be made as for VACUUM METHODS Steps 1 to 5. The Pressure Gauge is attached to the Sample Bottle Upper Valve. 1 2
3 4 5 6 7 8 9
Open slowly Top Valve of Sampling Bottle Open slowly Bottom Valve to bleed off salt water. Also open Separator Sampling Point, maintaining sampling pressure at 2 or 3 times atmospheric pressure with Bottom Valve (i.e. 30 - 40 psig: this pressure should be well below Separator pressure). Close immediately Bottom Valve when gas appears. With Top Valve allow pressure to build up slowly to Separator pressure. Close Top Valve. Close the Separator Sampling Point. Unscrew the Swivel Joint slowly. Gas leaks as the inside pressure of the line drops to atmospheric pressure. Disconnect Bottle. Check tightness, seal and label Bottle "FULL" immediately and place it in a container. Store in shade.
Note Bottle number and time of sampling in the sequence of events. Do not forget to complete fully the Sampling Sheet and include one copy in the Transportation Container. 11 - 11
Sampling FRESH WATER (Only if water cut = O)
This procedure should be avoided if at all possible. The sampling technique is the same as for Salt Water, so all water must be bled off during the sampling.
1.7
SEPARATOR OIL OR CONDENSATE SAMPLING AT SEPARATOR
Three bottles at least should be taken for each sampling to ensure good representation and sufficient quantity of sample for a normal PVT study. THIS IS IRRESPECTIVE OF GOR - i.e. ANY GOR: 3 BOTTLES. On some occasions, if the customer wants very extensive or duplicate PVT studies, additional quantities of samples may be requested.
1.7.1 Methods All methods aim to keep the Separator liquid at or above its bubble point pressure until it is transferred inside the Sample Bottle (by keeping sample at Separator pressure and below Separator temperature). The Sampling Bottle must be maintained at or below Separator Temperature. This prevents a gas liberation, which would interfere with the filling in operation. In cases where the Separator temperature is below ambient temperature, the Sample Bottle should be cooled in a water/ice or water/salt/ice bath. The oil or condensate methods below are listed in order of decreasing reliability. Note Bottle number and time of sampling in the sequence of events. Do not forget to complete fully the Sampling Sheet and include one copy in the Transportation Container Please to refer to oil sampling using the surface sampling kit.
1.8
WELL HEAD SAMPLING
1.8.1 Oil sampling at well head This sampling is possible only when the Well Head pressure is higher than the bubble point pressure at Well Head temperature. For this condition to be achieved it may often be necessary for samples to be taken at a low flow rate (i.e. less than 10 tubing total volumes per day). Clearly a good idea of the Bubble Point is needed. It is advisable that Separator Samples be taken at the same time to act as a back up in case of unexpected two-phase flow at Well Head, or other cause of invalid sampling. Normal liquid sampling methods should be used BUT MAKE SURE SAMPLE BOTTLES, GAUGES AND TUBINGS HAVE A WORKING PRESSURE RATED ABOVE WELLHEAD PRESSURE.
12 - 12
Sampling
1.8.2 Gas sampling at well head Since most gas-condensate wells produce two phases at the surface, this will only be possible on the rare occasions when monophasic Well Head flow is expected (Well Head pressure higher than dew point pressure at Well Head temperature). As in Oil Sampling at Well Head, Separator back up Samples should be taken. Most applications will be for dry gas wells where no liquid is formed in the Separator; here, a Well Head Sample will be identical to a Separator Gas Sample. Normal gas sampling methods should be used (i.e. usually VACUUM method) BUT MAKE SURE SAMPLE BOTTLES, GAUGES AND TUBINGS HAVE A WORKING PRESSURE RATED ABOVE WELLHEAD PRESSURE
1.9
USING THE SAMPLING SKID
1.9.1 Sampling skid description The PVT surface sampling skid is an open framework stand for mounting and supporting the oil and gas sampling cylinders and with all the valves, interconnecting pipe work and pressure gauges necessary for the sampling operation panel mounted to the supporting frame. The sampling skid comprises two sections for the separate – but simultaneous – sampling of the gas and liquid equilibrium phases from the test separator. Dedicated flexible sampling lines are used to connect from sample points on the test separator to the inlet fittings of the sample skid. The sampling lines should be kept and maintained solely for use for each of the specific phases to be sampled and are tagged accordingly (gas/oil) to avoid cross use. A schematic of the sampling skid system is shown at the end.
1.9.2 Gas sampling The gas sampling section inlet connection is ¼ inch Swagelok on the back panel. One or two 20 liters gas sample cylinders can be supported in the frame and connected for sampling with short sections of fixed flexible lines. Control of the gas flow is via an on/off ball valve and fine control during sampling via a horizontally mounted needle valve. The body of needle valve is positioned in an insulated water bath immediately below the panel. Prior to sampling the water bath is filled with hot water (> 40° C) to a depth such that the body of the needle valve is submersed. The temperature of the water helps prevent hydrates forming across the valve flow area during sampling that can cause total blockage of the valve. Immediately downstream of the flow control valve is a pressure gauge panel mounted above the valve.
1.9.3 Liquid sampling A flexible sampling line is used to connect the oil section of the skid to the sample point at the test separator similarly as for the gas sampling via a rear mounted ¼ inch swagelok fitting. Again, a ball valve is used to control on/off flow to the system. The oil sample cylinder is mounted and secured on an angled support plate at the front of the skid. The cylinder is positioned with the double port valve at the top. A sample fluid, flexible line connection is made to, one side of the sample valve at the top of the cylinder. The sample line flush valve is mounted on the other
13 - 13
Sampling side of the sample valve on the top of the cylinder. A displacement fluid, flexible line connection is made to the valve at the bottom of the cylinder. Two gauges are mounted one above the other, used to monitor, during sampling, the sample pressure and the displacement fluid pressure. Two gauges are needed as a check against malfunction or operational problems during the sampling and to measure a shipping pressure of the sample for reference in the PVT laboratory. 1.9.3.1
SAMPLING GAS: 20-LITER SAMPLE
Gas sample, as seen previously, are traditionally taken from the gas outlet of the test separator. All test separators will have take off points at various points along the gas outlet flow line. A preferred sample point is on the top of the horizontal section where the outlet leaves the top of the separator. The next preferred alternative, is any point on the bottom of a horizontal pipe section. For dry gas reservoir system the client may request 2 X 20 L gas sample per condensate sample. This is to provide additional gas for the recombination because of the lower ratio of liquid to gas for these systems. SAMPLING PROCEDURE
Referring to figure schematic layout of Test separator sampling. 1. Check gas cylinders are fully evacuated with on site vacuum pump. 2. Identify suitable sampling point on gas outlet flow line as per discussion above. 3. Connect sample line to take off point on test separator gas outlet with double valve connection (V1 & V2). 4. Connect sample line to gas inlet of sampling skid (back of panel V4). 5. Positions gas sample cylinder(s) on sample skid, secure and connect inlet line, record cylinder serial number. 6. Fill water bath (containing V4) with hot water (>40°C), ensure valve body is fully immersed in the water. 7. Equipment should be assembled with all valves in closed position. 8. Valve V6 at the bottom of the gas sample cylinder must remain plugged and closed. 9. Open fully valve V2. 10. Crack open valve V1, check for leak in sample line. 11. Open valve V3 and crack open V4; gauge G1 will show test separator gas pressure. 12. Open fully valve V4, check for leaks in sample skid connections up to the gas sample cylinder. 13. With valves V1, V2, V3 and V4 fully open begin sample line flush process. 14 - 14
Sampling 14. Close valve V3, and crack open the swagelok connection on connecting line to gas cylinder at valve V5. 15. Watch gas pressure on gauge G1 and close fitting again before the pressure reaches zero. 16. Reopen valve V3 and pressurize the system again. 17. Repeat 14 to 16 5-6 times, and finally, close the fitting on the cylinder inlet connection with system pressure close to zero on gauge G1. 18. Close valve V4. 19. Open valve V5. 20. When opening valve V5 the final check for vacuum on the sample cylinder is the negative deflection of the gauge G1. 21. Commence taking sample by cracking open valve V4. 22. Control the pressure increase of the sample cylinder with valve V4, sampling period is approximately 30 – 40 minutes, which gives an approximate pressure increase of 15 psi/minute (1 bar/minute) for a test separator pressure of 500 psi. 23. Continue to control filling of the gas sample cylinder until test separator pressure is reached, record pressure. 24. Close valve V3 and V4; check pressure remains stable no leaks. 25. Close valve V5. 26. Cracks open gas cylinder fitting connection (V5) and bleed off pressure. 27. Remove connecting fitting. 28. Secure shipping plug in valve V5 opening. 29. Return gases sample cylinder to transportation box and tag as used and containing a sample. OIL SAMPLING
Similarly to the gas sampling traditionally liquid samples are taken in 6 – 50 MI cylinders the latest generation of which is the piston type. Oil (liquid) sample cylinders are normally supplied cleaned and ready for use filled with a displacement fluid (glycol/water mix). A check should be made that cylinders are charged with the displacement fluid and if so that there are no losses. The preferred sample point for produced hydrocarbon liquid from the test separator is the oil outlet flow line. Most separators will be equipped with sample points on the flow line. An alternative is a take off point on the bottom of the site glass level indicator for the separator. This point is not ideal because of the relatively large volume between the take off point and the bulk fluid of the separator. Sampling from the site glass can also interfere with the separator operation and show a false indication. SAMPLING PROCEDURE 15 - 15
Sampling Refer to figure: schematic diagram of PVT Test Separator sampling. 1. Locate and prepare sampling point on the oil production flow line, ensure double valve (alternate, use site glass V14). 2. All equipment valves should be closed prior to sampling. 3. Connect sample line to valve connection. 4. With valve V9 closed, open V7 and V8 and check for leaks. 5. Sample line must be flushed into a suitable container by valve V9 prior to connect it to the sampling skid. 6. Secure sample cylinder to support plate with double port valve at top, record cylinder serial number. 7. Connect sample line to sample skid liquid connection, rear of panel G2. 8. Flush through the top tubing to the sample cylinder through V10. 9. Close V10 and open V11, the sample side of the cylinder will now be primed with sample fluid. 10. Open V12 and pressurize up to V13. 11. Commence sampling by cracking open V13 and control the flow of displacement fluid in to a measuring cylinder. Flow rate of displacement fluid should be approximately 20 ml per minute to give a sampling time of approximately 30 – 40 minutes to match that of the gas sample. 12. Continuously check the pressure readings on gauges G2 and G3 are the same. Differential changes in the pressure on these gauges indicate a problem with the sample flow. 13. Continuously check the displacement fluid flow as this can alter or stop altogether. 14. As the measured volume of the displacement fluid approaches, 550 ml, pay particular attention and prepare to stop the sampling. 15. Finish sampling at 550 ml of displacement fluid. 16. Close V13. 17. Close V9. 18. Record sample pressure (should remain constant at separator sampling pressure). 19. Crack open V13 and slowly displace a further 50-ml of displacement fluid. This introduces a safety gas cap in the bottle for transportation. 20. Close V13. 21. Close V12. 22. Disconnect the displacement fluid line connection from the cylinder (at V12).
16 - 16
Sampling 23. Agitate sample cylinder still connected to sample skid at V11 and gauge G2. 24. Record pressure on G2 (this is the shipping pressure). 25. Close V11. 26. Disconnect the sample cylinder from the sampling skid (at V11). 27. Replace plugs in sample cylinder valve ports. 28. Return sample cylinder to transport box and tag as used and containing a sample.
17 - 17
Sampling
18 - 18
Sampling
OIL CYLINDER PISTON TYPE
Sampling
LEUTERT SURFACE SAMPLING SYSTEM USING THE TYPE 5 CYLINDER
20 - 20
Sampling
1.10 P.V.T. PROPERTIES In order to study the properties of gases and hydrocarbon liquids we need to understand the relationship between them. This is best understood by considering molecular behavior and its effect on three physical properties. Pressure
which is a function of molecular attraction and repulsion
Volume
which is a function of the number of molecules present
Temperature
which is a function of kinetic energy of the molecules
Pressure and molecular attraction tend to hold a material together. Temperature and molecules repulsion tends to separate a material. When a material appears to be at rest it is actually in dynamic equilibrium between the attractive and repulsive forces. If one of the physical confines is changed (P.V. or T.) then equilibrium must be established. For example if we add heat to the system then the temperature rises, because of the increase of kinetic energy of the system and : Either The pressure increase as a function of the increased number of times the excited molecules strike the walls of the container. Or The volume expands to accommodate the more excited molecules at the same pressure. In extreme case, when enough heat is added the forces become unbalanced (boiling liquid) and the material changes state into gas phase. Phase behaviour is best understood by considering phase diagram. Pure substances First we look at the simple phase diagram of a pure substance.
The phase diagram is a plot of Pressure against Temperature. For the purposes of hydrocarbon chemistry we can ignore the Solid part of the phase diagram and concentrate on the vapour pressure line TC with particular reference to C the critical point. The temperature and pressure at this point are defined as : Critical Temperature (Tc) –the temperature above which a gas cannot be liquified regardless of the pressure applied
21 - 21
Sampling Critical Pressure 5Pc) –the pressure above which liquid and gas cannot co-exist regardless temperature Two component systems Next we can look at two component systems.
We have developed a phase envelope. The line AC is the bubble point locus and BC is the dew point locus. We can see also the definition of critical point C which we applied to the pure component does not apply. Clearly liquid and gas can co-exist at temperatures and pressures above the critical point. The critical point is merely the point at which Bubble Point locus and Dew Point locus meet. This type of behavior becomes more exaggerated as the complexity of a hydrocarbon mixture increases as is shown in the following diagram.
It now becomes necessary to re-define the Pressure and Temperature above which gas and liquid cannot co-exist. The circondenbar is the pressure above, which liquid cannot be formed and the circondentherm is the temperature above which liquid cannot exist. Multicomponent Mixtures (Reservoir Fluids)
22 - 22
Sampling We should now turn our attention to real complex hydrocarbons fluids and below are presented typical phase diagrams for Reservoir fluids under the normal classifications accepted in petroleum engineering. LOW SHRINKAGE BLACK OIL
HIGH SHRINKAGE OIL
GAS CONDENSATE
23 - 23
Sampling WET GAS
DRY GAS
As previously stated, phase diagrams are plots of pressure against temperature, whereas in petroleum engineering we are usually more concerned with pressure vs. Volume (PV) at a fixed or perhaps one or two fixed temperatures. In this case it is interesting to consider the isotherm marked 1-2-3 on the phase diagrams which represents reservoir temperature. With reservoir oils a drop in pressure from 1-2 brings us the Bubble Point (the point at which the first bubble of gas of the lightest component in the mixture appears). As we proceed from 2-3 the gas becomes progressively richer in heavier components, as the liquid becomes progressively depleted of lights ends. With condensate reservoir gases a drop in pressure from 1-2 brings us to the Dew Point (the point at which the first drop of liquid appears). Here we observe retrograde condensation, which is that the heaviest components drop out first and the gas stream becomes progressively lighter as pressure drops. We should now consider what happens in practice when the reservoir fluid is produced to the surface, giving rise to both a drop in pressure and temperature. This can be best done by reference to the dotted line on the phase diagrams marked 2-Sep. The point marked Sep denotes the Separator Pressure and Temperature.
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Sampling With oils and condensate gas we remain within the phase envelope where liquid and gas can co-exist. The actual point within the phase envelope defines the relative compositions of the oil and gas according to physico-chemical parameters which will be explained later. What is interesting to observe is that the Wet Gas produces no liquid (in the reservoir) along the isotherm 1-2 but if the drop in pressure is accompanied by a drop in temperature, as happens during production, then liquid is produced at separator pressure and temperature. By definition a Dry Gas produces no liquid even at separator conditions, and heavy components present have to be chilled out from the gas stream to bring the temperature within the phase envelope.
1.11 WHEN A RESERVOIR SHOULD BE SAMPLED The aim of PVT sampling is to obtain a small sample fluid under pressure, which is identical to the reservoir fluid under initial conditions. To achieve this several factors must be taken into account : A. To decide upon the condition of the well to be sampled B. To decide which sampling technique will give the best chance of obtaining a representative fluid sample A field discovery well is usually subjected to relatively large drawdown pressures and considerable depletion in the production testing necessary to determine its extent. The second and third wells drilled will still encounter essentially virgin reservoir pressure and the problems associated with conditioning, sampling and analysis will be minimized. Depletion of a reservoir below the bubble point pressure, leads to extreme difficulty in obtaining a reliable sample. As the results from the analysis of reservoir fluids are generally used in material balance calculations it is desirable that the analysis is performed on original fluids samples. Extra pollution of data from a current bottom hole pressure to a higher bubble point pressure is always hazardous and should only be attempted in extreme cases. Selection of a well for sampling For the result of the fluid analysis to be of maximum value in the reservoir study, the sample must be representative of the phase that saturated the reservoir rock initially. In an oil reservoir it will be the gas phase. The well to be sampled should meet as many of the following conditions as possible : 1. The well should be centrally located in the field 2. It should have as high a productivity index as possible 3. The well should be completed in the section of the reservoir to be studied. In most cases this will be the oil zone. Care should be taken to eliminate any occuring gas coning. 4. The well should be free from water production 5. The flow in the reservoir should be single phase 6. If bottom hole sampling is required, no mechanical difficulties in running the sampler to a depth opposite the perforations should exist. Data required prior to sampling Before sampling is attempted it is important to obtain preliminary details of the reservoir and well characteristics for example: 1. The type of fluid expected to be encountered. Oil, gas, condensate, or water 2. Whether it is saturated or undersaturated
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Sampling 3. Whether the formation had high or low permeability In exploration wells Standing’s correlations can be used to estimate the bubble point pressure at formation temperature. To use this correlation the following data is required : 1. Initial and static reservoir pressure 2. Reservoir temperature 3. Oil and gas gravities 4. Stabilized gas-oil ratios at one or more flow rates Well conditioning The well should be flowed until a stabilized rate is achieved such that the G.O.R. is equal to the initial G.O.R. Stability should be achieved for a minimum of 4 hours for bottom hole sampling and 12 hours for surface sampling with a flowing bottom hole pressure greater than the bubble point pressure. During this period the oil and gas flow rates, well-head pressure, and flowing bottom hole pressure should all be constant. The latter gives the best indication of stability but can only be used if electronic surface read out gauges are available.
1.11.1 Oil reservoirs Undersaturated reservoirs These reservoirs are characterized by constant G.O.R. equal to the maximum gas solubility in oil. Bottom hole sampling and surface sampling can be carried out with the well flowing at any stabilized flow rate for which flowing reservoir pressure exceeds saturation pressure at reservoir conditions. Saturated reservoirs In these reservoirs the G.O.R. is only equal to the maximum gas stability in oil during a very short initial flow period. The G.O.R. then increases as the well is produced. Saturation pressure will equal to or near the initial static reservoir pressure, and if an initial gas cap is present will always equal the initial pressure. Bottom hole sampling can be carried out if the following procedures are adopted. The flow rate should be progressively reduced and then the well finally shut-in. During this period the flowing bottom hole pressure will increase and the free gas produced into the well bore, or remain stationary within the oil phase until when the well is shut in reservoir saturation pressure should be near to the initial static reservoir pressure. At this point the well should be opened on the smallest possible choke (e;g; 1/16”) and flowed for 10 to 15 minutes before the sampler closes. During this short flow period draw down should minimized and any liberated gas, too small to affect the validity of the samples. The flow rate should be progressively reduced over a long period (depending on the permeability of the reservoir) and finally shut in. During this period the flowing bottom hole pressure will increase until it approaches the initial static bottom hole pressure. The movable free gas will be produced into the well bore and the stationary free gas will remain in the pore space of the reservoir. This remaining free gas reduces the effective permeability of the reservoir rock to monophase reservoir fluid, and increases the pressure drawdown.
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Sampling
1.11.2 Gas reservoirs Since for these reservoirs it is impossible to determine in the field from well test data the exact nature of the reservoir fluid (dry or wet gas), sampling should always be carried out assuming the most difficult case, i.e. a gas condensate reservoir with a dew point equal to the initial static pressure. Surface sampling should always be carried out in gas reservoirs, bottom hole sampling being unsuitable for the following reasons : 1. The laboratory analysis requires a greater sample than the 600 cc or 1000 cc available with standard bottom hole samplers. 2. If a sample were taken, the effect of bringing the sampler to surface conditions would cause liquid to condense in the sampler chamber. This liquid would in most cases be only a small amount and would remain behind, wetting the walls of the chamber, during a normal transfer at atmospheric temperature. Even if the sampler was reheated to reservoir temperature, no guarantee that single phase conditions existed could be given in the field. In addition to the normal criteria for surface sampling in dealing with a gas reservoir, a further parameter has to be met. The liquid condensed in the tubing, between the bottom of the well and the tubing must be produced in the separator.
1.11.3 Volatile Oil Reservoir A volatile oil is one with a very high gas solubility in relation to its bubble point pressure and because of its high G.O.R. and low relative density can be confused in the field with a gas condensate reservoir. Because of these unusual characteristics, Standings correlations cannot be used to determine bubble point pressure, therefore these reservoirs should be sampled as gas condensates. If PVT analysis shows that it is an oil reservoir and the bubble point is established, bottom hole sampling can be employed on subsequent wells.
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Transfer Pump
SECTION 21 TRANSFER PUMP
1-1
Transfer Pump
1.1 GENERAL Pumps are used to empty one compartment of a tank; separator or other vessels where not enough pressure exist to empty it. The pump inlet is generally connected to the tank manifold for compartment selection; the outlet is generally connected to a manifold that permits the passage of the liquid to stock tanks to burners or burn pits through the normal piping. It may also be required to re-inject the oil from the separator into an existing production line or system, in which case a high-pressure transfer pump can be used.
1.1.1 Installation Aligning driver and pump Driver and pump units are factory aligned, but must be accurately realigned during and after installation. To align coupling, use a straight edge and feeler gauge to check for parallel and angular alignment as shown in illustration at left. Check the alignment at every step during installation; after the unit is mounted on skid or foundation, after piping has been secured, and after pump has run with the liquid at operating temperature. Do not depend on flexible couplings to compensate for misalignment. Installation of strainers Most types of pumps can be used for clean fluids only and a strainer or filter should be installed before the inlet and it should be cleaned on regular bases.
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Transfer Pump Installation of pipes Use of Teflon tape for installing pipes may cause damage to the pump. Piping should be checked carefully, allowing for expansion or contraction. pipe strain can distort the pump components, thus increasing wear, causing bearing misalignment, or breaking parts. Pipe supports and expansion joints should be used to avoid weight and stresses on the pump. See that flanges or unions fit without forcing. Pump part size does not necessarily establish correct pipe size. If in doubt as to the pipe size to used contact the engineering department. It is recommended that the pump be installed below the liquid level, with a short, large diameter supply line to assure a flooded inlet.
1.1.2 Pre-operation checks See instructions on preparation and mounting of the pumps. Determine the proper direction of rotation by using the appropriate instructions and illustrations. When a relief valve is used, make sure it is positioned and adjusted properly. After the unit is mounted and the piping connected, the pump should be checked to be sure it operates freely, without binding. After operation is proves satisfactory, both pump and driver should be tightly secured and the alignment rechecked before operation. Before starting, make sure the inlet and discharge valves are open and there is liquid in the pump. After starting the unit, check that the pump is delivering liquid, if not, stop the driver immediately and refer to the "trouble shooting check list». If the pump is delivering liquid, check the unit for quiet operation, vibration, localized heating, and excessive seal or packing leakage. It is recommended that the pressure and or vacuum is checked by installing gauges at both sides of the pump to make sure the pressure and or vacuum conforms to the specifications.
1.1.3 Operation A pump is a simple piece of equipment and should not give any major problems if the following precautions are taken. -
Check required electrical supply (V, Hz).
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Check that the ventilation on the electrical motor is not obstructed.
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Don't inverse inlet and outlet.
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Check transmission parts, (v belts, flexible couplings)
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Transfer Pump -
Check oil level and electrical cables.
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Grease bearings if grease nipples are fitted.
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When starting the pump for the first time immediately check the sense of rotation if the rotation is the wrong way around have the rig electrician inverse two of the three phases in the connection box.
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If flexible hoses are used checks the pressure rating, the condition of connections and hoses; tie down the hoses with cable or rope.
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Never start a pump in dry state or with inlet or outlet valves closed.
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If no flow is obtained within one minute, stop the pump and check that:
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Valves are open,
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Suction line is immersed with fluid,
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Liquid is not vaporizing in the suction line,
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No waxes have build up in the lines.
Open the by-pass valves while starting. (if fitted)
1.2 PERSONNEL SAFETY
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Know operating conditions.
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Never start a pump with the switching box open.
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Always use caution near rotating parts, including the drive system for the pump.
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Install proper guard(s). Never operate a pump without guards in place.
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Do not operate the equipment in excess of its rated capacity, pressure, speed, and temperature, or other than in accordance with the operation instructions.
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Install and properly set relief valve.
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Do not try to adjust or remedy operating defaults while pump is running or still plugged to the main power.
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Proper measures should be taken to avoid spillage and overflow.
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Identify all possible hazards. Determine what controls are needed; only you the user understand your product and system characteristics fully. The ultimate responsibility for the application and safety is with you.
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The pump must be earthen and the earth checked.
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Never place your hand or fingers either on the suction or discharge side of a pump, this can cause serious bodily injury.
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The possibility of fire and burns from flammable or hot liquid spillage from ruptured hoses should be particularly be noted and proper precautions taken.
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Static electricity is created by the fluid flowing through the pumps and hoses (if used), If the equipment is not properly grounded, sparking may occur, and the system may become hazardous. Sparks can ignite fumes from hydrocarbons and the fluid being pumped, as well as dust particles and other flammable substances. To reduce the risk of static sparking, ground the pump and all other equipment used or located in the area.
Transfer Pump
1.3 EQUIPMENT SAFETY -
Open all lines before starting pump.
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Never start a pump in "dry state" as it can seize the pump.
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Never install a pump immediately " in line "after the separator.
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Check the direction of rotation and the safety valve of the pump itself.
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Check if the pump still confirms with the safety regulations, plugs, connection boxes, electric motor.
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Diesel operated pumps should have flame arrestors on the exhaust, and the starting mechanism should be intrinsically safe or air started.
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Place the pump unit so no well fluids can come in direct contact with hot engines.
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It is important that the maximum capacity of the pump should be greater than the expected maximum well capacity.
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Determine consequences of spillage or leakage (all pumps or systems may fail)
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Explode
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Toxic
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Corrode
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Fire
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High temperature
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Chemical burn
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High pressure
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Other
Have appropriate safeguards been used? -
Temperature controls
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Pressure controls
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Leak detectors
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Shutoff devices
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High or low pressure safeguards
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Alarm devices
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Overfill or overflow detection
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Have all possible methods and sequences of failure been considered?
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Are there any other methods needed to control a hazard?
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Inspection for wear and/or deterioration of components.
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The relief valve is a safety device and is used to protect equipment and personnel from accidents due to overpressure; it should never be used as a control device to regulate pressure.
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If there is no relief valve in the system, never block the outlet stream, high pressure will occur, resulting in possible damage or breakage to the pump or system parts and possible injury to personnel. Even with a relief valve in
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Transfer Pump the system, do not operate the pump for more than a few minutes with the outlet line blocked. Rapid heating and possible damage will occur. -
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When working or repairs are made on a pump always isolate the driving system to avoid the accidental start-up by ignorance, neglectance or automatic systems. Remove the air supply for pneumatic operated pumps, remove fuses or electrical operated pumps, remove the engine starter key or isolate the starter on combustion engines that drive a pump,
Transfer Pump
1.4 TROUBLE SHOOTING GUIDE (GENERAL, FOR MOST PUMPS) PROBLEM 1. NO LIQUID DELIVERERED
2. RAPID WEAR
3. EXCESSIVE NOISE
CAUSE Pump not primed, if pump fails to deliver after 1 minute, stop the pump.
SOLUTION Prime it by pouring some liquid into the discharge side of the pump.
Rotating in the wrong direction.
Change the direction of rotation.
Inlet lifts to high; check this with gauge at pump inlet.
Review setup.
Clogged valve or inlet line, or valve upstream closed.
Clean line or open valve.
Air pockets or vapor lock.
Use a degasser, or bleed air.
Check valves blocked or corroded. Abrasives in liquid.
Repair checks valve assembly. Use strainers or filters.
Compatibility of liquid and pump material.
Use different pump.
Excessive pressure.
Lower discharge pressure.
Non lubricating liquid, (only for pumps that need a lubricating pump fluid). Starved pump.
Change to other pump type
Air leaks in inlet line.
Repair.
Air or gasses in liquid.
Use a degasser before inlet.
Pump speed to high.
Check on engine revolutions, and freq./voltage ratings on el. motors.
Relief valve chatter.
Check pressure setting or check line downstream is not blocked.
Improper mounting.
Check aligning thoroughly.
Check supply liquid, see also "no or insufficient liquid delivery".
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Transfer Pump PROBLEM 4. INSUFFICIENT LIQUID DELIVERED
5. PUMP TAKES TOO MUCH POWER
8-8
CAUSE Air leaks through packing or mechanical seal.
Repair.
SOLUTION
Air leaks in inlet line.
Repair.
Inlet lifts to high; check this with gauge at pump inlet.
Redesign the system.
Speed too slow.
Check engine revolutions, and or check frequency / voltage.
Viscosity of liquid too high for the size and length of pipe.
Change piping.
Foot valve or end of inlet pipe not immersed deeply enough in liquid.
Adjust.
Vortex formation at inlet.
Use a vortex breaker or immerge inlet deeper into liquid.
Pump damaged by foreign matter or misalignment.
Repair and install filter before pump if needed.
Excessive clearance caused by wear or corrosion.
Repair.
Relief valve set to low or stuck partially open.
Regulate relief valve or repair.
Check valve(s) blocked or corroded Speed too high.
Repair Check on engine revolutions, and or freq./voltage ratings on el. motors.
Liquid more viscous than previously anticipated.
Use more powerful pump.
Operating pressure higher than specified. Check with gauge at the pump outlet.
Use larger piping or eliminate any obstructions.
Outlet line obstructed.
Clean.
Mechanical defect, such as a bent shaft, packing gland too tight, or misalignment of piping.
Repair.
Relief valve not operating properly.
Regulate relief valve or repair.
Transfer Pump
1.5 SIHI PUMP TECHNICAL DATA Components: -
Electrical motor 18,5 kW, 3 phase, 380 V , turning at 1465 rev. / MN.
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Speed reducer type RX 101, from 1400 rev. / MN. to 683 rev. / MN. ( new reducers come with a plug at the top, replace this plug with a vent that is delivered with the pump.)
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Safety valve with bypass assures the protection against overpressure, (valid for the flow direction)
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Pump, SIHI ref. RPNA 101 -
Capacity
: 5000 BOPD
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Max. temp.
: 200 ° c
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Max. viscosity
: 75000 CST.
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Rotation direction
: reversible
1.5.1 Description This type of pump is a positive displacement pump. The pump uses gear wheels to vehicle fluid from the inlet to the outlet; the rotating gears give a constant transfer of liquid without any pulsation’s or turbulence. The drive gear wheel is the biggest and is attached to the main shaft; it grips into the driven gear and makes it turn as well. The liquid finds its way in-between the empty space of the gear teethes as the gear teethes has different dimensions (see drawing).
A separation plate between the gears prevents the liquid from flowing back. Only one shaft exit exist, so only one exit seal which can be inspected and replaced without disconnecting the piping (bleed down the lines first to avoid oil spillage.). This pump has a high efficiency, and viscosity chances don't have much influence on the flow rate.
1.5.2 Electrical wiring The schematic drawing underneath show how to wire the engine to a three phases alternative current.
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Transfer Pump 220 Volts between two phases or 380 Volts between two phases.
1.5.3 Maintenance Besides the usual checks before the use of a pump there is some periodical maintenance to be made;
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The oil level in the speed reducer should be checked regularly and an oil change made every 10.000 working hours or every two years.
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Clean the bearings after 10.000 working hours and put new grease, fill-up only one third of the space in the bearing.
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Inspect the seal on the shaft exit for leaks. Packing cord as shaft seal demands current adjustment to ensure correct leakage at the stuffing box. Dependent on RPM and viscosity the stuffing box must leak 10 – 100 drops a minute to remove the friction heat generated between shaft and packing cord. In the event of insufficient leakage the heat generation will cause hardened packing rings and increase wear on the shaft.
Transfer Pump
MAIN PARTS A : Pump casing
BC : Main bearing
AA : Front cover
BU : Rotor
AB : Idler
BV : Shaft
AC : Idler pin
CQ : Bearing bracket
AD : Idler bearing
CU : Ball bearing
BA : Rear cover
CJ : Packing rings
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Transfer Pump
1.6 SAFETY VALVE As a result of the Rotan pump operating against a closed discharge outlet, an unlimited pressure build up can occur. This means that a relief valve should protect the pump, piping and valves etc. The relief valve leads the pumped liquid from the discharge side back to the suction side when the set pressure is exceeded. The pump must not operate in by-pass mode for a long time, as it will cause heating of both liquid and pump. The standard relief valve only protects in one pumping direction. The adjusting screw on the relief valve should point to the suction side of the pump. In a case of a valve with a vertical adjusting screw, it shall point to the pressure side of the pump. Normally the valves are provided with a “P” for pressure side and an “S” for suction side. The opening pressure should be 1 – 3 bar over the normal operating pressure. The total overpressure (inlet pressure + differential pressure) must not exceed 10 bars for the type 101.
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Transfer Pump
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