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Surface equipment for UBD operations
Selecting surface equipment is the final step in designing an underbalanced drilling (UBD) operation. The surface equipment for UBD can be broken down into four categories:
- Drilling system
- Gas-generation equipment
- Well-control equipment
- Surface separation equipment.
- 1 Drilling systems
- 2 Gas-generation equipment
- 3 Well-control equipment
- 4 Separation equipment
- 5 References
- 6 See also
- 7 Noteworthy papers in OnePetro
- 8 External links
- 9 Category
Hole size and reservoir penetration, as well as directional trajectory, determine whether coiled tubing or jointed pipe is the optimal drillstring medium (Table 1). If the hole size required is larger than 6⅛ in., jointed pipe may need to be used. For hole sizes of 6⅛ in. or smaller, coiled tubing can be considered. The size of coiled tubing currently used for drilling operations is between 2 and 2⅞ in. outer diameter (OD). This is because of many factors, including:
- The flow rate through the coil
- Pressure drop through the tubing
- Weight on bit (WOB)
- Profile of the well
- Maximum pickup weight
- Both in-hole and surface equipment
- Weight of the coiled tubing itself
Occasionally, the ideal coiled tubing for an operation may be excluded because of such factors as crane or transport limitations or that the life of the coil may not be economical. Generally, coiled tubing has several advantages and disadvantages compared to jointed pipe systems. For jointed pipe systems, drillstring properties and tripping under pressure must be considered. If hole size and trajectory permit, coiled tubing is the simplest system to drill underbalanced.
If natural gas is used for UBD, a natural gas compressor may be required. This would need to be reviewed once the source of the gas is known. Most production platforms have a source of high-pressure gas, and, in this situation, a flow regulator and pressure regulator are required to control the amount of gas injected during the drilling process.
The use of tanked nitrogen could be considered on onshore locations, where a large truck could be used for its supply. Cryogenic nitrogen in 2,000-gal transport tanks provides high-quality nitrogen and utilizes equipment that is generally less expensive. Liquid nitrogen is passed through the nitrogen converter, where the fluid is pumped under pressure prior to being converted to gas. The gas is then injected into the string. Generally, the requirement is for the nitrogen converter and a work tank, with additional tanks being provided as necessary. For operations in excess of 48 hours, the requirement for liquid nitrogen could be quite large, and this can result in logistical difficulties. To move away from tank transport for large nitrogen-dependent drilling operations, the use of nitrogen generators is often recommended offshore.
A nitrogen generator is no more than a filtering system that filters nitrogen out of the atmosphere. A nitrogen generator uses small membranes to filter the air. Oxygen-enriched air is vented to the atmosphere, and nitrogen is boosted to the required injection pressure. Fig. 1 shows a nitrogen-generation system.
A nitrogen generator is 50% efficient. In real terms, if 1,500 ft 2 /min of nitrogen is required, then 3,000 ft 2 /min of air needs to be pumped into the generator. A full nitrogen system for 1,500 ft 2 /min would comprise of three or four large air compressors, a nitrogen generator, and a booster compressor. This equipment will take up significant deck space on an offshore rig or platform. Fig. 2 shows the nitrogen generation equipment rigged up on a jackup.
Another issue associated with nitrogen generation is the purity of the nitrogen itself. Purity varies depending on the amount of nitrogen required. At 95% purity (by mole), 5% oxygen is delivered. Although this is not enough oxygen to reach explosive levels, it is sufficient oxygen to cause corrosion problems. The corrosion is worsened when salt brine systems are used at elevated temperatures (Fig. 3).
The conventional blowout preventer (BOP) stack used for drilling is not compromised during UBD operations. The conventional BOP stack is not used for routine operations, and is not used to control the well except in the case of an emergency (Fig. 4).
A rotating control-head system and primary flowline with emergency shut down (ESD) valves is installed on top of the conventional BOP. If required, a single blind ram, operated by a special Koomey unit, is installed under the BOP stack to allow the drilling bottomhole assembly (BHA) to be run under pressure.
Well control is much simpler when drilling with reeled systems. A lubricator can be used to stage in the main components of the BHA, or, if a suitable downhole safety valve can be used, then a surface lubricator is not required. The injector head can then be placed directly on top of the wellhead system (Fig. 5).
The reeled systems can then be tripped much faster, and the rig-up is much simpler. However, one consideration relating to reeled systems is the cutting strength of the shear rams. Verification is required to ascertain that the shear rams will cut the tubing and any wireline or control-line systems inside the coil. For a standalone operation on a completed well, an example stack-up is shown.
If tripping is to be conducted underbalanced, a snubbing system must be installed on top of the rotating control-head system (Fig. 6). Current systems used offshore are called rig-assist snubbing systems. A jack with a 10-ft stroke is used to push pipe into the hole or to trip pipe out of the hole. Once the weight of the string exceeds the upward force of the well, the snubbing system is switched to standby, and the pipe is tripped in the hole using the drawworks. The ability to install a snubbing system below the rig floor allows the rig floor to be used in conventional drilling. The snubbing system is a so-called rig-assist unit. This unit needs the rig drawworks to pull and run pipe. It is designed to deal only with pipe light situations. Snubbing on an onshore rig, where there is no space under the rig floor to install a snubbing unit, must be conducted on the rig floor. To facilitate snubbing, so-called push/pull units are installed on the rig floor (Fig. 7).
Rotating diverter systems
The principle use of the rotating diverter system is to provide an effective annular seal around the drillpipe during drilling and tripping operations. The annular seal must be effective for a wide range of pressures, and for a variety of equipment sizes and operational procedures. The rotating control-diverter system achieves this by packing off around the drill pipe. The rotating control-head system consists of a pressure-containing housing where packer elements are supported between roller bearings and isolated by mechanical seals.
Types of rotating diverter
There are currently two types of rotating diverter: active and passive.
|Active Rotating Diverter||The active type uses external hydraulic pressure to activate the sealing mechanism and increase the sealing pressure as the annular pressure increases|
|Passive Rotating Diverter||The passive type, normally referred to as rotating control-head systems, uses a mechanical seal|
All surface BOP systems have limitations in both the amount of pressure they can seal off, and in the degradation of the sealing equipment from the flow and composition of the different reservoir fluids and gases over time, regardless of the type of surface BOP control system chosen.
Rotating control heads (passive systems)
Rotating control heads are passive sealing systems (Fig. 8). Rotating control heads have given excellent service for more than 30 years, particularly in the air and air-foam drilling industry. The rotating control head is playing an increasingly important role in UBD, provided that its inherent pressure limitations are not being extended. The conventional, original rotating control head was developed in the 1960s. This is a low-pressure model and has been used on thousands of underbalanced and overbalanced drilled wells. It is designed to operate at 500 psi rotating and 1,000 psi static. It is capable of rotating up to 200 rpm and uses a single stripper rubber. It is currently used in many underbalanced operations in the United States. The current rotating control heads are rated to a static pressure of 5,000 psi and a rotating pressure of 3,000 psi with 100 rpm.
Rotating BOPs (active systems)
The rotating blowout preventer (RBOP) is probably the most significant piece of equipment developed, with the biggest impact being its ability to drill underbalanced with jointed pipe in a variety of different reservoir and wellbore scenarios. The rotating control-head system must be sized and selected on the basis of the expected surface pressures. A well with a reservoir pressure of 1,000 psi does not need a 5,000-psi rotating control-head system. A number of companies offer rotating control-head systems for UBD (Fig. 9).
The separation system has to be tailored to the expected reservoir fluids. A separator for a dry-gas field is significantly different from a separator required for a heavy-oil field. The separation system must be designed to handle the expected influx, and it must be able to separate the drilling fluid from the return well flow so that it can be pumped down the well once again.
The surface separation system in UBD can be compared with a process plant, and there are many similarities with the process industry. Fluid streams while drilling underbalanced are often described as four-phase flow because the return flow comprises of oil, water, gas, and solids.
The challenge of separation equipment for UBD is to effectively and efficiently separate the various phases of the return fluid stream into individual streams. Several approaches in separation technology have emerged recently (Fig. 10). The chosen approach depends largely on the expected reservoir fluids.
Careful design of the surface separation system is required once the reservoir fluids are known. Dry gas is much simpler to separate than a heavy-crude or gas-condensate reservoir. However, the separation system must be tailored to reservoir and surface requirements. This requires a high degree of flexibility, and the use of a modular system helps maintain such flexibility.
The use of a modular system for offshore operations is often recommended because lifting capacity of platform and rig cranes is regularly limited to 15 or 20 tons. To reduce the total footprint of a separation package, vertical separators are generally used offshore as opposed to the horizontal separators used in onshore operations. In a lot of situations, the separator is the first process equipment that receives the return flow out of a well. Separators can be classified, as shown in Table 2. Separation of liquids and gasses is achieved by relying on the density differences between liquid, gas, and solids. The rate at which gasses and solids are separated from a liquid is a function of temperature and pressure.
Horizontal and vertical separators can be used. Vertical separators are more effective when the returns are predominantly liquid, while horizontal separators have higher and more efficient gas handling capacities. In horizontal separators, well returns enter and are slowed by the velocity-reducing baffles (Figs. 11 and 12).
The data acquisition used on the separation system should provide the maximum amount of information about the reservoir obtainable while drilling. It should allow for a degree of well testing during drilling. Furthermore, the safety value of data acquisition should not be overlooked because well control is related directly to the pressures and flow rates seen at surface.
Erosion monitoring and prediction of erosion on pipe work is essential for safe operations. The use of nondestructive testing technology has been found to be insufficient in erosion monitoring. An automated system using erosion probes is currently deployed, and this allows accurate prediction of erosion rates in surface pipe work.