1 Bottom hole pressure and temperature
It should be noted that the information given in the following tables only partially shows the expected performance specification of the gauges. Company experiences in the 10,000 psi and 15,000 psi ranges are limited, thus no specific recommendation can be made here.
One of the problems associated with the compilation of such broad spectrum data sheets is the basis on which gauge specifications are quoted by the various manufacturers and service companies.
There are now many pressure and temperature downhole sensing devices, it is often difficult to ascertain just what each supplier means by their performance figures, how they define certain key functions and how this relates practically to field operations.
Two examples illustrate this problem:
·Many electronic gauges are used with a downhole memory recorder. The way that the memory records data can mask the performance of the sensing device.
·Specifications can often be misleading when quoted out of context. A "quartz" transducer displays impressive accuracy/resolution, until we take account of the poor real time thermal response of Quartz.
A "Quartz capacitance" gauge is sometimes thought to be similar to a "quartz" gauge, when in reality, the "quartz" component has to do with obtaining a smoother surface between capacitance plates and nothing to do with the way a vibrating quartz transducer operates.
In general, three main types of gauges are categorised as follows:
1.Bottom hole mechanical downhole recording pressure gauges.
2.Bottom hole electronic downhole recording pressure gauges.
3.Bottom hole electronic surface recording pressure gauges.
Manufacturers of pressure sensors most commonly depict their products and their performance characteristics through technical specifications. The definitions of the parameters describing the transducer performances are reviewed below.
Typical pressure measurement parameters can be split into the following two main classes:
·Static parameters
·Dynamic parameters
1.1 Static parameters
These parameters describe the transducer performances in static conditions. Under this classification, we find:
·Accuracy
·Resolution
·Stability
·Sensitivity
1.1.1 Accuracy
The manufacturer generally refers to the static accuracy which can be considered to be the algebraic sum of all the errors influencing the pressure measurement.
These errors are due to:
·MQD (Mean Quadratic Deviation): the discrepancy between the theoretical mathematical curve and the actual transducer response after calibration.
·Hysteresis: highest discrepancy of the transducer output signal between increasing and decreasing pressure excursions, at the same pressure level.
·Repeatability: the discrepancy between two consecutive measurements at a given pressure.
·dP/dT: temperature sensitivity of the pressure sensor.
1.1.2 Resolution
This is the minimum pressure change that is detected by the sensor.
When referring to a gauge resolution the associated electronics must be taken into account and one must specify the resolution for a certain sampling time (varies from 0.1 sec. to several secs.)
The gauge resolution (tool) is equal to the sum of three factors, the sensor resolution, the digitiser resolution and the electronics noise induced by the amplification chain. In the case of tools equipped with strain gauge transducers this latest factor is by an order of magnitude the predominant parameter.
1.1.3 Stability
This is the ability of a sensor to retain its performance characteristics for a relatively long period of time.
The stability gives the sensor mean drift in psi per day obtained at given pressure and temperature. Three levels of stability can be defined:
·short-term stability for the first day of test
·medium term stability for the following six days
·long-term stability for a minimum of one month.
1.1.4 Sensitivity
This is the ratio of the transducer output variation induced by a change of pressure to this change of pressure. In other terms, the sensitivity represents the slope of the transducer output versus the pressure curve.
1.2 Dynamic parameters
These parameters describe the transducer performances in Dynamic conditions. Under this classification we find:
·transient response during temperature variation
·transient response during pressure variation.
1.2.1 Transient response during temperature variation
The sensor response is monitored under Dynamic temperature conditions whilst the applied pressure is kept constant.
The peak error represents the maximum discrepancy between the applied pressure and the stabilised sensor output.
The stabilisation time represents the time needed to be within 1 psi of the stabilised pressure.
The offset represents the difference between the initial and the final pressure. This parameter provides for a given temperature variation the time interval required to get a reliable pressure measurement.
1.2.2 Transient response during pressure variation
The sensor response is recorded before and after a pressure variation whilst the temperature is kept constant. Peak error and stabilisation time are measured as previously described.
1.3 Bottom hole mechanical downhole recording pressure gauges
These self-contained gauges are the type most commonly used in the petroleum industry, especially during exploration well testing operations, where the BHT is below 350°F. Approaching this temperature it is normal to run electronic gauges possibly with mechanical gauges as a back -up provided the 350°F is not surpassed.
In HPHT testing operations above 350°F, it is normal to run gauges in bundle carriers as part of the completion string as this gives the best chance of recovering pressure and temperature data. Additionally, this obviates wireline runs.
They comprise the following three essential components:
1.A pressure/temperature sensing device (e.g. a Bourdon tube).
2.A pressure-recorder section.
3.A mechanical clock.
This type of recorder is field proven and reliable. Normally two pressure recorders and one temperature recorder are run on wireline. The recorders are "hung-off" in a landing nipple with a soft setting tool and the wireline removed from the well. At the end of the test the recorders are retrieved again by wireline. The recorder chart can be read with the aid of a chart scanner which takes up to two hours per chart. Instead of a temperature recorder a maximum thermometer is often run in the nose of the lower pressure recorder. If bottom hole temperatures are expected to be above 300°F special high temperature clock and elements (non-bellows type) have to be used.
The handling of the pressure recorders is not only critical in the well during flow periods, but also during rigging up and running of the recorders. On occasions the readings on the chart have been completely obliterated by bouncing of the stylus. Correct handling, careful running and proper locking in place of the recorder in the well minimizes jarring of the stylus to provide readable charts.
If the pressure element has not had recent use (e.g. for two days) it should be reactivated by pre-pressurising and checked prior to a survey. Pre-pressurising consists of applying approximately the full range pressure, two or three times, in a short time period (e.g. 2 to 3 minutes). This is performed using a hand-operated pump, a calibration adaptor and a conventional dial gauge. Since the Bourdon tubes in all pressure elements "relax" when not in use, they are always pre-pressured at the factory before being calibrated to generate the calibration data.
1.4 Bottomhole electronic downhole recording pressure gauges
Recorders of this type are self-contained battery operated devices. The recorders are run on wireline and "hung-off" in a similar way to mechanical recorders. In most of these gauges a transducer converts force or displacement into an electrical signal that is recorded downhole. Pressure and temperature are recorded when the gauge is returned to the surface.
1.5 Bottomhole electronic surface recording pressure gauges
Gauges of this type incorporate a means of measuring bottom hole pressure and temperature and a method for transmission of measurements to the surface for recording as a function of time. Most of these gauges have a single conductor armoured cable to transmit the signals from the sensor to a monitoring system at the surface. The main advantages of this type of gauge are as follows:
1.During the test, malfunction of the gauge is immediately apparent and remedial action can be taken.
2.Pressure data can be interpreted instantly and the length of the various test periods adjusted accordingly.
These advantages can save costly rig time; gauges of this type are summarized in Table 300.
Whilst the conventional bottomhole mechanical downhole - recording pressure gauges technology has basically remained static, various manufacturers have entered the electronic gauge market and a thorough survey is recommended, prior to selection. Additionally, with very high pressures and temperatures, there is only a limited number of manufacturers that offer gauges above 300°F.
2 Surface pressure and temperature
Surface Data Acquisition using transducers processors and computer operated reporting systems have developed rapidly over recent years. They are now considered to be reliable, cost effective and common place, particularly in High Pressure/High Temperature well tests.
As monitoring of essential parameters become automated and real time, such a system would have the added value of identifying problem areas before equipment failure occurs.
2.1 Tubing head
The tubing head pressure and temperature are taken at the flowline manifold upstream of the choke manifold and are both recorded on a chart recorder. In addition, the tubing head pressure is measured at regular intervals by means of a deadweight tester. It should be noted that a deadweight tester does not give accurate readings on a floating rig due to heave; in this case electronic wellhead gauges can be used. Specifications of four types of these gauges are given in Table 301.
2.2 Separator
The separator temperature is measured by a thermometer placed in a thermowell in the outgoing gasline. The separator pressure is measured and recorded upstream of the orifice in the gas outlet line. The differential pressure over the orifice is measured by a meter (Barton) in inches of water.
2.3 Flowlines
It is recommended that pressure gauges are installed downstream of the control valves in the gas and oil line to the burner booms, so that the back pressure of the flares can easily be monitored.
2.4 Heater
When a heater is used there should be thermowells and pressure taps on inlet and outlet lines.
3 Flow rates
Flow rate figures are used as the basis of important decisions at a much later stage after the test. It is therefore very important that the flow rate figures are accurate and reliable. Reading of relative sections of EP-61-000, Planning and Programming Manual, addresses the following topics more definitively.
3.1 Liquid flow rates
Liquid flow rates are measured using positive displacement meters, turbine meters or vortex type meters which are positioned in the fluid outlet line of the separator. The readings of these meters are compared with measurements in a gauge tank at regular intervals during the test.
The meter readings are then multiplied by the meter factor to find the correct flowrate (It should be noted that the meter factor includes the correction for the shrinkage).
Liquid flow rates are reported at 60°F. For this purpose the meter reading is multiplied by a volume reduction factor "K". This factor is given in tables when the temperature and specific gravity of the fluid are known. Most separators have a shrinkage tester built on the same skid. This shrinkage tester can be used to estimate the shrinkage during the test. It should only be used for flow calculating purposes when there is no gauge tank available. It is recommended that the oil in the gauge tank is allowed to settle for about half an hour to allow gas to escape, and hence allow a more accurate figure to be obtained. A further advantage of a gauge tank is that it facilitates accurate BS and W measurements.
3.2 Gas flow rates
Gas flow rates are always measured with an orifice type meter. Before the test the differential pressure meter should be checked with a U-tube manometer and the static pressure recorder with a deadweight tester. Care should be taken that no liquids can accumulate in the lines from the orifice fitting to the meter. A layout with drip-pots in the lines to the meter is shown in Section 3.9.1. It should be appreciated that not all the gas is measured by the orifice meter in the gas outlet of the separator; there is still a certain amount of gas in solution in the oil leaving the separator; tables are available to calculate this amount of gas.
The production test contractor should have complete documentation material on site allowing calculations to be easily checked.
4 Specific gravities
The values of the specific gravity of oil and gas at 60°F are used to calculate the respective flow rates.
4.1 Specific gravity of oil
The specific gravity of oil is measured using a hydrometer according to ASTM D1298-67 IP 160/68 "Density, Specific Gravity or API Gravity of Crude Production and Liquid Petroleum Producers". A full set of hydrometers should be part of the production test laboratory equipment.
The sample for specific gravity measurement should contain no water; the specific gravity measurement is expressed at 60°F.
4.2 Specific gravity of gas
The specific gravity of a gas is measured with a gas gravitometer. This meter works on the principle that the torque produced by a wheel which is activated by a jet of gas is proportional to the specific weight of the gas. The difference in torque produced by air and the tested gas is shown on an indicator scaled to read in terms of specific gravity (the specific gravity of air is one).
5 Sampling
The sampling requirements are based on the principle "Sample while you can". Hence as many samples as necessary should be taken during a given formation test, because a second sampling opportunity may not arise. However, sampling is only effective if it is representative of a "turbulent" stream emphasising the "where" sampling point.
Sampling is inexpensive compared to testing; therefore if there is an opportunity to take improved quality samples of a previously sampled interval, these samples should be taken and the earlier samples discarded.
Water samples should never be stored in tin cans, but always in glass or plastic bottles and always filled completely to the top.
Aluminium or stainless steel containers should be used for PVT samples. For storage of oil samples, 600 cc stainless steel containers are normally used with a maximum working pressure of 1800 psi; for storage of gas samples 20 litre aluminium containers are used with a maximum working pressure of 2800 psi. Shipping containers for bottom hole samples must have a maximum working pressure of 5,000 psi, 10,000 psi or 15,000 psi.
All sample containers should be provided with a firmly attached clearly legible identification enclosed in a weather-proof envelope. Sample bottles should always be shipped in special containers or crates.
The samples to be collected during a production test of an exploration well can be classified as follows:
1.Crude oil/condensate samples
2.Water samples
3.Gas samples
4.Surface PVT samples.
The quantity of samples collected should be a multiple of that required for analysis (as stated in Guidelines for manual sampling and analysis of hydrocarbon fluids) for the following reasons:
1.Loss/damage of samples during transportation.
2.Interest of third parties (associates, offtake refineries)
3.Repeat analysis in laboratories.
4.Interest of MF and EP functions in small samples.
5.Interest of MF and EP functions in drum samples for future field development.
A typical set of samples would be 10 pcs 200 litre drums for crude oil/condensate, 10 pcs 5 litre cans for crude oil condensate and 3 pcs 20 litre sampling bottles for gas produced from each separation stage.
5.1 PVT samples
Oil and gas PVT samples, taken from the separator at surface, are later mixed in the laboratory in the ratio according to the (Gas-Oil Ratio) GOR measured at the time of sampling, in order to acquire a representative sample of the original composition. Due to possible inaccuracies in gauging the oil flow rate and the gas flow rate the GOR may not be accurate and have an adverse effect on the composition of the mixture. Therefore bottom hole PVT sampling is preferred for oil wells.
The special bottom hole PVT sampling equipment, containers and services are available from service companies as follows:
1.Schlumberger - using surface controlled opening and closing of the sampler mechanism run on electric cable.
2.Schlumberger, Ruska, Woffard and Leutert - using (downhole) clock-controlled opening and closing of a sampler mechanism run on wireline.
Bottom hole samplers run on wireline are complicated in design since they include a clock mechanism. Bottom hole sampling requires experienced and skilled personnel, which is certainly the case with samplers run on wireline. A higher success ratio has been obtained with a sampler run on electrical cable which does not require a clock to activate its tripping mechanism.
Although the rental rate of electrically operated samplers is higher than the rate for wireline samplers, the total time involved to obtain representative bottom hole samples is generally less and therefore makes its use preferable on high rental (offshore) rigs. On retrieving PVT bottom hole samplers from oil wells, the bottom hole pressure will cause sufficient differential pressure for sealing off the trapped sample. This may not occur in the light gradient gas/gascondensate wells, since the trapped sample also loses temperature and therefore pressure, and sealing of the trapped sample becomes difficult. For wells with a GOR in excess of 2000, bottom hole sampling becomes unreliable. It is therefore recommended that surface PVT samples are obtained of large enough volumes for high GOR wells.
Enough bottom hole samplers should be available during a production test; one is used for transferring the bottom hole sample into the appropriate shipping container, while others are being run downhole to take a sample. The samples should be taken in accordance with API publication RP-44 ("Recommended Practices for Sampling Petroleum Reservoir Fluids"). It is recommended that 3 bottom hole PVT samples are taken preferably after the main build-up period, at a low flow rate (the flow rate should be high enough to obtain stable vertical flow conditions).
5.2 Sampling of gas for H2S analysis
Sampling cylinders made of low hardness mild steel, stainless steel, aluminium alloy or glass are safe for use with sour gas but not suitable for collection of gas for H2S analysis. The H2S will react with the sampling cylinder material and may be partly or completely absorbed in a short time. Internal coating of sample cylinders does not give satisfactory protection against absorption of H2S; the analysis is therefore performed on site (Section 11). The analysis can be carried out by the mudlogging contractor making use of electronic instruments, or by the production test contractor making use of Drager tubes. Equipment used by the mudlogging contractor should be checked and calibrated prior to production testing.
5.3 Natural gas sampling
Portable test equipment is available for use on-site to carry out flash separations, and measure and sample the resulting liquid and gas streams over a range of pre-selected pressures and temperatures. A typical use of the equipment is during the appraisal period of a new gas or gas-condensate field, to simulate likely process and handling conditions and forecast liquid yields and lean-gas properties over a range of conditions. This provides a more reliable basis for the design of facilities than could be obtained using normal calculations.
5.4 Trace elements
Services are available to sample gas during a production test and determine on site small quantities of the so called "trace elements" as well as very small quantities of H2S.
6 Sand
It is sometimes expected that a well will produce sand on a continuous basis, after "cleaning-up" (this is based on logs and cores). Sand production in oil and gas wells will later cause serious erosion in permanent production facilities. It is therefore most important to estimate the sand production rate at an early stage and establish which section of the producing interval produces the sand. This allows remedial action, such as gravel packing, sand consolidation, or plant design changes to be planned. The sand production rate of oil wells is measured by taking frequent well head samples which are centrifuged. When the sand production rate is low a large well head sample is taken and screened using a sieve, the sand production rate is expressed in lbs/1000 bbl. The sand production rate of gas wells is measured using a sand filter. At the end of a certain flow period the filter is opened up and the sand is weighed. The sand filter should be positioned upstream of the choke and have a by-pass incorporated.
7 Viscosity
The reader is referred to standard test method ASTM D445-79 - "Kinematic Viscosity of Transparent and Opaque Liquids (and the Calculation of Dynamic Viscosity)".
7.1 Kinematic viscosity
The kinematic viscosity is determined by measuring the time for a volume of liquid to flow, under gravity, through a calibrated glass capillary viscometer. The viscosity varies with temperature and therefore the viscosity is expressed at a certain temperature.
7.2 Dynamic viscosity
The Dynamic viscosity can be obtained by multiplying the kinematic viscosity by the density of the liquid.
8 Pour point
The reader is referred to standard test method ASTM D97-66 - "Pourpoints of Petroleum Oils".
The pour point of an oil is defined as the lowest temperature, expressed as a multiple of 3°C (5°F), at which the oil is observed to flow, when cooled and examined under prescribed conditions.
Pour points must be determined on clean oil samples by an experienced operator, in the laboratory, using the correct equipment. Simplified procedures carried out in the field may produce misleading results.
If in doubt, seek specialist advice.
9 Cloud point
The reader is referred to standard test method ASTM 250081-"Cloud point of Petroleum Oils".
The cloud point is defined as that temperature, expressed as a multiple of 1°C (2°F) at which a cloud or haze of wax crystals appears at the bottom of the test jar when the oil is cooled under prescribed conditions.
In opaque oils, the crystallisation point of wax is determined by observation of the temperature drop of a cooling sample as a function of time. A sudden decrease in the cooling rate is caused by heat released by crystallizing of the wax. Cloud points must be determined on clean samples by an experienced operator, using the correct equipment.
9.1 Flow, temperature and pressure monitoring points
9.1.1 Transducers
The schedule of transducers normally used are as follows:
ParameterRangeAccuracy % (PSD)
Temperature0-300°F0.25
Pressure0-1,000 psi0.1
0-1,500 psi0.1
0-5,000 psi0.1
0-10,000 psi0.1
0-15,000 psi0.1
Differential pressure0-200 ins/wg0.25
0-40 ins/wg0.25
0-400 ins/wg0.25
Flowrate0-10000 bbls/d0.01 bbl/resolution
These are the main ranges of transducers.
9.1.2 Data requirements
In brief the requirement for surface data is as follows:
1.Subsea tree (LRT)
temperature
2.Swivel (URT)
temperature
a)Wellhead
-pressure
-pressure
b)Choke manifold (downstream)
-pressure
-temperature
c)Separator
-gas line pressure
-gas line temperature
-orifice differential
-pressure
-oil temperature
-oil flow rate
-water flow rate