1 General
Successful production testing of exploration wells requires the choice of appropriate test string design, equipment and facilities, and strict adherence to safety measures. An integrated planning approach must involve production technology, reservoir engineering, production operations and drilling engineering. Setting clear test objectives which are fully understood by company and contractor personnel is essential.
There is currently renewed interest in the drilling of deep, high temperature and high pressure wells. During a test of this nature, surface pressures may approach 15,000 psi and temperatures of 300°F may be present with concentrations of H2S and CO2 (Partial pressures greater than 0.0142 psi and 7 psi respectively).
To achieve this, equipment exists or is being developed, that encompasses the following areas:
·Drill Stem Test Tools (15,000 psi @ 400°F)
·Subsea Tree and related equipment (15,000 psi @ 300°F)
·High Pressure surface equipment (15,000 psi @ 260°F)
·Surface Data Acquisition System
·High Temperature Memory and Amerada Equipment gauges
All equipment described in the following text has a 10,000 psi WP. For pressures up to 15,000 psi, special mention is made as and where necessary.
Typically, the main differences between 10 K and 15 K testing is in the equipment used upstream of the choke manifold. It is important to note that limitations imposed by high temperature may outweigh those of pressure on surface equipment. Temperatures below 175°F downstream of the chokemanifold,can also cause problems with relation to H2Sembrittlement(22 HRC). These issues are explained further in the guideline.
2 Summary of main changes resulting from high pressure/ temperature testing
Since HP/HT well testing is a non-routine activity it requires special attention in terms of
1.selectionof equipment,
2.programmingand preparation and,
3.supervision.
The following guidelines relate to 15,000 psi WP, 250°F temperature rating and H2S service. Where the temperature exceeds 250°F, special recommendations are made.
2.1 Equipment issues
2.1.1 Choice of seals
Tubing and accessories or DST string connections, should preferably have metal-to-metal sealing. If temperatures greater than 250°F and/or CO2 is envisaged, andelastomersare required to be used they are to be ofViton-type material, or equivalent, rated to 400°F.
2.1.2 Subsea
The subsea test tree (SSTT) should have a chemical injection point between the shear and block balls, and include a built in temperature transducer. This will facilitate guarding against hydrate formation, by the injection of chemicals and will also permit the monitoring of wellhead temperatures. The inlet connections at the SSTT should have integrated double check valves, and fittings should be of the autoclave type. Preference should be given toSSTT's,and Lubricators/Retainers valves, that use metal-to-metal seals due to potential gas impregnation and explosive decompression ofelastomerseals.
2.1.3 Surface Test Tree STT (Flowhead) and choke manifold
Surface test tree (flowhead), should have metal-to-metal seals as well as self-sealing metal-to-metal gate valves.
Chemical injection points at the STT,FlowlineManifold (or Data Header) and Choke Manifold, should have dual check valves incorporated and block and bleed facilities.Fittings to be of the autoclave variety.
All connections between the STT and the choke manifold should haveGraylocconnections and be of anchored rigid piping. Where movement between the STT and choke manifold is expected, (e.g. floating rigs), then aCoflexiphose withGraylocfittings is recommended. For flowing well temperatures in excess of 220°F continuous use ofCoflexiphoses is not recommended. Methods of lowering FTHT should instead be undertaken. These could include cooling of riser and/or choking back on well, at choke manifold.
2.1.4 Surface equipment downstream of choke manifold
Allpipeworkbetween choke manifold and inlet to steam heat exchanger should be rigid and straight. Where elbow sections are required these should have welded connections and where movement is expected, metal-to-metal seals are preferred. All the foregoing must be of 10,000 psi rating.
The steam heat exchanger rating should be 10,000 psi upstream of thechoke,and 5,000 psi downstream with a quick acting ESD system, activated by a high pressure pilot (PSH). This signal from the pilot would activate the SDV, located upstream of the choke manifold as well as vent trapped pressure to flare.
The temperature of the steam entering the exchanger will be controlled by a thermocouple device linked to a control valve. The steam lines will be fitted with non-return valves.
The 1440 psi standard separator should be fitted with audible alarms on both high and low levels, to assist in exercising immediate local control.
The surge vessel should have a vent line, sized large enough to cater for total gas flow via the liquid outlet of the separator, a situation that could arise in high rate condensate wells.
2.1.5Downholedata acquisition equipment
Care must be taken in the selection of memory gauges, as their temperature rating is restricted to ±350°F. Battery packs and clocks require specific attention, as they are particularly susceptible to damage resulting from very high temperatures. The possible H2S/CO2 effects at elevated temperatures should be carefully discussed with the gauge supplier. Use of elastomeric seals should be avoided for reasons discussed earlier. Service agreements that hold theOpcoliable for damage when operating within the pressure/temperature range specified, should also be avoided.
Downholeand wellhead samplers chosen should be mercury-free, due to potential hazards with this substance.
2.2 Supervision and quality control issues
·To achieve a safe and efficient operation, the following support functions are particularly important in high pressure and temperature applications:
·Quality Assurance and Control, Maintenance, Certification, Pressure Testing and Leak Detection and First Class Supervision. Deficiency in any one area may lead to an inefficient and unsafe operation.
·It is equally important to design wells such that well closure is possible AT ANY TIME.
·Each test should be treated individually, and all equipment should be tested to maximum operating or design specifications by:
-manufacturer
-certifying agency
-user
Additionally, records of field use, maintenance, inspection and certification should be available and reviewed.