FMC Kongsberg Subsea
PART II: This is part two of a two-part series on selected areas of concern when dealing with high-pressure, high-temperature (HP/HT) wells. Part one appeared in our February 2002 issue and focused on wellheads and downhole space limitations for HP/HT wells.
There are a number of considerations when designing for HP/HT. A variety of factors relating to the deepwater, subsea environment, and the nature of the HP/HT reservoir drive these decisions. But it would seem that no choice stands alone, as each decision has far-reaching consequences for other areas of the project.
HP/HT is not new to the oil industry. Tech-nology designs and material usages exist for HP/HT service, but not to the extent required in subsea designs. Subsea design codes and industry standards and practices are lagging behind, making it more difficult to design or verify that hardware is fit-for-purpose. In addition, many classic calculation techniques have used thin-wall pressure vessel assumptions that may have to give way to thick-walled calculation assumptions for HP/HT applications. Therefore, future hardware development and refinement may be slowed by novel qualification programs and sophisticated design practices until the subsea HP/HT market gains maturity.
Another trend is to minimize the seal diameter of components to minimize mechanical end-load effects as HP/HT requirements grow. However, this becomes another aspect of the hourglass paradigm - a process that acts as a bottleneck. Selecting special materials for HP/HT applications provides the needed high mechanical strength and added corrosion resistance for current hardware geometries, but at the expense of more costly raw material and more difficult machining and fabrication. Smaller seal diameters and locking locations allow for more conventional material usage, but at the expense of production throughput sizes.
Downhole equipment reflects the hourglass paradigm for HP/HT applications where subsea designers want to limit wellhead size while downhole interests favor fewer wells with greater production capacity. Downhole equipment tends to be either an internal bore restriction in order to comply with its corresponding tubing size, or it has to be larger to accommodate the production tubing drift. Either way, it becomes a bottleneck focal point for well completion design with respect to drift diameter and erosional velocity.
Tubing plugs and mandrels face similar design issues as tubing suspension equipment. Landing shoulders, locking rings, and seals all pose trade-offs between higher-end loads requiring higher strength materials and conventional materials with reduced seal and locking diameters, which keep design stresses low. Surface controlled subsea safety valves (SCSSVs) have the same issues, where the valve operating and closure devices must be designed with stronger materials to meet throughbore requirements. Even with premium materials, most SCSSV designs for HP/HT service will be roughly 1 1/2 to 1 3/4 times larger in diameter than the nominal tubing string it serves.
Well bore sealing technology also has an extensive industry history. It has particularly benefited from development and growth in fire-safe technology over the last 20-30 years. It can now better cope with HP/HT issues.
Metal seal technology comes in many proprietary forms. Designers have adapted these to HP/HT applications with specialized material usage, material finishes, and geometry arrangements. Metal seals have shown to be more tolerant of thermal effects and less prone to Poisson strain effects.
Non-metallic seals come in two versions - elastomeric and non-elastomeric. Elastomeric seals are far more prevalent in most designs, and their relatively soft construction makes assembly easy. Their ability to adapt to surface imperfections and minor changes in sealing geometry is superior to other methods. Elastomers usually have good design life at operating temperatures up to 250
Above 250°, other non-metallic materials, such as PEEK, graphite composites, PTFE composites, and ceramics, come into use. These have much more thermal stability but have far less elasticity or stretch. They are much harder and more resistant to flow into surface imperfections. They are also much harder to install in hardware components, often requiring special hardware seal grove and seal retention designs to compensate for their rigidity.
Subsea applications pose an interesting wrinkle to seal design and performance. Just as external hydrostatic pressure is always present for pressure vessel calculations, the cold seawater environment (40° F) in most deepwater environments) is an ideal heat sink, keeping hardware near its ambient temperature regardless of well bore temperatures. Many elastomeric seals may be used in HP/HT applications simply by locating the seals sufficiently away from the well bore into an area that is more thermally suited. Thermal FEA and traditional conductivity heat transfer calculations can easily identify these cool spots.
Insulation has been a growing phenomenon in deepwater subsea hardware and pipeline design due to the cold seawater temperatures mentioned above. Insulation is used primarily to delay the effects of hydrate or deposit (wax, asphaltenes, etc.) formation by keeping in the wellbore fluid's latent heat during shut-down situations until other forms of remediation can be implemented. High-temperature insulation materials have a lower thermal conductivity (k) value than their lower high-temperature counterparts in use today.
These less efficient insulation materials may require almost twice the thickness to achieve the desired heat retention. For complicated geometries, such as subsea manifolds and trees, the added thickness may be too difficult to apply properly. Alternatively, combinations of ceramic paints with standard low-temperature insulations are being combined in laminated coating processes to reduce the skin temperature at the component/insulation interface so that the insulation can be satisfactorily used in HP/HT applications.
Insulating materials tend to be brittle, similar to some syntactic foams used for hyperbaric floatation devices. Applying insulation to components that will flex under induced loads (flowline jumpers and flowloop piping) or thermal expansion (steel has a higher thermal expansion coefficient) could induce cracking in the insulation layer. This would allow seawater intrusion, ruining the insulation's thermal resistivity. Pliable moldable insulating materials are being developed and refined to address this issue.
Another aspect of insulation is the component's higher working temperature. As stated earlier, many seals are located well away from wellbore fluids and closer to the ambient surroundings of the seawater in order to keep seal temperatures within their operating region. However, insulation traps the heat, possibly raising the component's body temperature above the seal's temperature range. In addition, many subsea components are operated by hydraulics. Hydraulic cavities encased by insulation need some sort of vent or expansion chamber so that trapped hydraulic fluid can expand without adversely building up pressure.
The use of optical sensors for downhole monitoring is becoming more widely adopted in several HP/HT applications, such as steamflood operations. Optical sensors are finding their way subsea to offer permanent pressure and temperature measurement and address perceived shortcomings in reliability that conventional electrical downhole sensors encounter at temperatures above 250-300° F.
However, this adds a "third" input to current electro-hydraulic control systems and wellbore access downhole through the subsea tree and tubing hanger. Wet-mate fiber optic connectors will have to be sized to be just as small as current electrical and hydraulic connectors. In addition, fiber optic connectors must be able to wipe away the opaque completion brines in use in HP/HT wells during make-up with tools and the subsea tree.
Afterwards, the connector(s) will be subjected to the same HP/HT environment in a confined space where the tubing hanger sits. Other issues include where to route the fiber optic cable as it exits the subsea tree. If it is routed through the electro-hydraulic control pod, a light source must be "marinized" and made small enough to reside within the confines of the control pod housing.
In addition, some fiber optic pressure and distributed temperature measurement sensors could require separate light sources, further complicating the issue. Alternately, independently routing the fiber optic line could simplify control system interfaces, but its own ROV flying lead and connection could add to the "clutter" associated with dealing with several separate hydraulic, electric, and now fiber optic flying leads between the tree and umbilical terminations.
One recent problem arising from HP/HT is dealing with thermal expansion effects in the various annuli between well casing strings. Up to now, subsea equipment provides annular access between the well's production casing and the production tubing (A annulus). During well start-up or shut-in, pressure access to the A annulus allows for the venting or injection of annular fluids in and out of the well to control the fluid pressure associated with wellbore heating or cool-down (one of the reasons most subsea trees are dual bore - with production and annulus access runs). Now there is concern that the annular space between production and the last intermediate casing string (B annulus) or between two intermediate casing strings (C annulus) may be undergoing similar pressure changes. If the pressure change is extreme enough, it could collapse the inner casing string or compromise formation isolation at the casing shoe. However, there is no way currently to access and vent these cavities in a subsea well, since a subsea wellhead is configured to seal off and stack the next casing string over and above the previous casing string and annulus within the subsea wellhead's high-pressure housing.
Many argue that casing programs for HP/HT wells should be made stout enough to resist external pressure from these annuli and leave the subsea well design alone. But this could exacerbate the hourglass problem between well size and production tubing. Another approach introduces access porting and valves to the side of the high-pressure housing for access to B and C annuli. However this goes against American Petroleum Institute-recommended design practice not to introduce any access points below a subsea BOP while drilling the well.
Other approaches involve installing subsea wellhead packoffs while drilling, then removing the packoffs in some way later while subsea completion equipment is installed to gain access to the extra-annular cavities. This approach, however, requires a departure from traditional subsea hardware designs and/or well completion and control procedures.
High integrity pipeline protection systems (HIPPS) are an important facet of the delivery system for HP/HT pipelines. Pipelines and flowlines are usually designed to withstand the highest pressure they will see in production. Typically, this would be the well's shut-in pressure.
In HP/HT designs, the wall thickness could grow to 1 1/2 in. to deal with the hoop and longitudinal stresses in the pipe. However, there is a wide difference between a shut-in (design) pressure of an HP/HT field and the pipeline pressure when the well is in production. The flowing pressure allows for a more economical wall thickness and pressure rating of pipelines and flowlines. HIPPS is an autonomous valve and control system that monitors the pressure in the trees, manifold, or flowlines of HP/HT equipment and automatically closes in on any transient increases in flow or pressure beyond a pre-defined pressure.
The purpose of HIPPS is to decrease the pressure rating in the spools and flowlines to reduce costs and ease fabrication/installation. In addition, keeping the pipeline's design pressure down keeps the design partial pressures of H2S and CO2 in check, which would otherwise force the use of corrosion-resistant alloy pipe materials.
HIPPS are placed at or near the source of HP/HT wellbores and fitted with two or more valves and three or more pressure sensors to achieve a high reliability through redundancy of components. These monitor for pressure spikes caused by operator error, unexpected valve closure or blockage downstream, choke component failures, or pipeline plugging from wax or hydrates.
All piping upstream of the HIPPS valve must be designed for the full rated shut-in pressure of the HP/HT environment. Immediately downstream is a pipeline region known as the "fortified zone." It is built in to the pipeline design that is rated for a slightly higher pressure than the rest of the pipeline. This zone's pressure rating and the length needed is tied to the maximum transient pressure wellbore fluids might reach before the HIPPS has time to sense the imbalance and initiate a closure. The rest of the pipeline is rated for the lower flowing pressure.
Although the application of HIPPS is straightforward, the cold seawater environment combined with the higher hydrate formation temperatures of HP/HT fluids increase the likelihood of a hydrate plug forming fairly close to trees or manifolds. Avoiding this risk requires an extremely fast response, often needing a relatively low (just above the flowing pressure) trigger pressure that activates valve closure.
Hydrates and wax formation usually occur some distance from the HP/HT well source, where cooling effects are greater. However, the further HIPPS are located from the source of potential blockages, the lower the trigger pressure must be to sense the problem. However, lower trigger points increase the likelihood of "false alarms" making it hard to keep the pipeline up and running. Therefore, HIPPS and the associated pipeline must be designed in concert with a detailed flow assurance analysis to define fortified lengths and meaningful trigger pressures.
Another challenge to HIPPS will be the development of large-bore valving associated with large delivery pipelines. HIPPS valves are usually designed with oversized stems to augment its fast closure characteristic. However, the larger stem means a more powerful actuator to open the valve under internal pressure. The key challenge is to design an actuator for the valve that is powerful enough to open the valve, but able to vent fast enough to allow the valve mechanism to close quickly (using the pipeline's bore pressure to assist in the valve's closure).
Hydraulic actuators of large-bore subsea valves require several gallons of fluid to operate the valve through one stroke. HIPPS controls need very large hydraulic piping, 1-in., and secondary control valves to allow the quick venting of actuator hydraulic fluids for fast closure. The resulting hardware package size and weight of a large-bore HIPPS could be as large as a subsea tree. This size makes installation and connection to a pipeline and maintenance/recovery more challenging.
An alternative to large-bore pipeline HIPPS may be a different field architecture dubbed "simple HIPPS." Here the HIPPS valve is tied into one of the downstream valves on a subsea tree. One of these tree valves is converted to a HIPPS configuration, with the rest of the tree valves acting as a "slower" back-up valve (to maintain HIPPS' high reliability through dual-valve redundancy). In this design, the HIPPS valve can be the smaller size of the tree rather than the large bore needed for the pipeline. More HIPPS valves are needed, one for each tree. A secondary benefit of "simple HIPPS" is that high-pressure upstream piping is eliminated and the fortified zone can include gathering manifolds and infrastructure.
Three basic criteria need to be accommodated by an HP/HT choke:
- High controllability under high-pressure drop in early field life
- High-flow/low-pressure drop in later field life
- High resistance to erosion/abrasives throughout field life.
Early in the life of an HP/HT field, choke settings must be precise and minute to harness flow rates under a great deal of pressure drop. Often, a multi-stage pressure drop is preferred to single stage to reduce velocities and, subsequently, wear at each stage. Even so, to combine these stages in a single valve is not advisable, due to the possibility of flashing between stages. The stages should therefore be physically separated in two bodies to allow for full fluid expansion between stages. The result is two choke systems, remotely retrievable.
The upstream choke is a fixed-choke design, and the downstream choke is an adjustable design. The upstream stage takes an initial pressure drop to reduce flow velocity and improve low-end control for the downstream adjustable choke, and filters out well debris from the upstream flow, thereby minimizing potential for damage to the adjustable choke.
Later, the upstream fixed choke may be replaced with a non-restrictive insert, allowing the downstream adjustable choke to continue to operate at a lower pressure drop - higher flow rates when the wellhead flowing pressure is low. However, a two-choke solution necessitates planned intervention after two to three years to remove the restrictive element in the fixed choke. Still this design could greatly extend the life of the adjustable choke and simplify its plug/cage design.
The presence of chokes in HP/HT systems also creates an interesting paradox with respect to seals and insulation. The Joule-Thompson (J-T) cooling effect can create an extremely cold situation in downstream piping later in field life. Temporary conditions of -50° to -80° F pose a real challenge to the selection of materials and non-metallic seals. Many such seals are rated for either very cold or very hot service temperatures.
This also raises an interesting problem with respect to the temperature rating of the equipment. Usually the lower end of the temperature rating applies to the coldest environmental temperature to which equipment may be exposed. For the subsea environment, this is 40° F. However, the J-T effect can exist for 20 minutes to an hour before equalizing to ambient flow conditions. Therefore, fracture toughness and ductility of materials and seals must be reviewed in this light to make sure that equipment retains its integrity.
Insulation further augments the J-T paradox. In uninsulated equipment, the surrounding seawater acts as a heat source, minimizing the J-T effect on hardware downstream of the choke. However, fully insulated equipment may not benefit from the external warming effects. In extreme cases, insulation can promote isolated "cold spots" in the flow stream piping, which could cause hydrates to form. Again, thermal FEA will have to be rigorously applied to identify these areas.
Future of subsea HP/HT
The oil industry has a good experience record in understanding and dealing with HP/HT and subsea environments separately. The technical challenge now is to address these issues as they apply jointly in a subsea HP/HT project. Just as deepwater was the technical challenge of the '80s and '90s, HP/HT is becoming the technical challenge for the next decade of projects.
Two recent subsea projects have ushered in subsea HP/HT, with several more projects planned for start-up within the next couple of years. Subsea HP/HT components are largely qualified, but lack the actual field experience performance reliability database from which to build and gain confidence. This will come as more projects come to fruition. The main emphasis for subsea HP/HT will be on well design, addressing the hourglass paradigm, and developing new materials that can better handle current space limitations and performance restrictions.
Contact authors at FMC Kongsberg Subsea for a full list of references.
The staff and management of FMC Kongsberg Subsea provided critical review and support in developing this paper.