Brian Skeels
FMC Technologies
Improved logging and drilling techniques contribute to the significant and growing success rate of finding deep and subsalt reservoirs around the world. This trend brings to the forefront the need for high-pressure/high-temperature (HP/HT) hardware sooner to access and develop this latest realm of geologic formations.
While the development of HP/HT equipment (rated over 10,000 psi [69 MPa] and/or 250 °F [121 °C]) has been significant, the requirements are piecemeal, project driven and proprietary. Wellhead equipment and trees are approaching standards of 15,000 psi (103.4 MPa) and/or 350 °F (177 °C) service while downhole, logging and isolation equipment are working in environments approaching 30,000 psi (207 MPa) and 500 °F (260 °C).
One reason for the disparity is the growing distance between reservoir and wellhead, and the associated guesswork in predicting flowing wellhead conditions from limited fluid and fluid flow properties at the sand face. Several questions arise over how to define appropriate pressure and temperature ratings along with surface environmental (in air or subsea) pressure and temperature ratings—the latter introducing fatigue-cyclic loading conditions not seen downhole.
This great divide may provide a window on material selection, operating, and maintenance service life (as opposed to overall design life), and corrosion rates at elevated temperatures. Heavy oil production also may hold clues on material performance. Some heavy-oil equipment works at temperatures approaching 650 °F (343 °C). Current downhole and "hot" heavy-oil production reveal clues for design guidelines to help the HP/HT wellhead community keep pace with reservoir advances in extreme and ultra HP/HT environments.
Operator requirements for drilling and completions systems push the boundary of known, proven, and delivered technology and equipment. As these boundaries get pushed further, the need for a new higher pressure, higher temperature, and higher casing capacity subsea wellhead system grows. This need grows as modifications to existing technology are useful in fewer and fewer applications. Additionally, as drilling in the Gulf of Mexico continues to push into deeper, higher pressure formations, the need for increased suspension capacity under the duress of hostile, corrosive environments is equally important. Downhole equipment development and fluid rheology are the tip of the spear for HP/HT technology because of its proximity to the source – the HP/HT reservoir. Unfortunately, reservoirs do not reveal their secrets willingly.
Establishing system requirementsMany HP/HT reservoirs are being found in subsalt (or presalt) locations under abnormal pressure gradients and folds. Depth of the salt play above the reservoir also plays tricks with the estimated reservoir temperature and overburden pressure. Interestingly, thicker salt regions coincide with more remote, deeper water locations, which skew requirement needs. Wellhead equipment manufacturers of subsea and surface hardware are seeing a roughly 5,000 psi and 50 °F disparity in requirements for generally the same reservoir depth, making it more difficult to plan for technology needs and timing.
Another vexing problem for HP/HT requirements is properly defining the equipment's environment. Most oilfield equipment codes, both wellhead and downhole, use "wellbore temperature" to define the equipment's rated temperature class. Later, when equipment migrated to the arctic, operators added a much lower temperature class to equipment requirements as a way to ensure the pressure containing equipment had the appropriate heat treatment and ductility/toughness against cold brittle fracture when the well was not flowing. This practice continues today where "all" equipment is assumed to need to function at both upper and lower defined limits. However, this does not properly address proximity. Some components obviously are closer to the wellbore and so exposed to higher temperatures. Peripheral components, those away from the wellbore, operate at more consistent ambient conditions regardless of wellbore temperature.
This sets up a huge rating conundrum. Does one rate peripheral equipment at one temperature and in-close components at wellbore temperatures? How about when they are adjacent or touching? How do you re-rate peripheral equipment? Should it be insulated to eliminate heat sink outlets? Finally, what do you rate the temperature class for the entire assembly of components? Looking at the system requirements based on the environment and wellbore might establish a different design paradigm. Work with the environment, not against it.
Downhole equipment usually works in a narrower temperature range since it experiences roughly the same rated pressure and temperature both internally and externally. Stability and longevity are keys to downhole success. Typically, the high temperature condition sets the requirements for design and qualifying procedures. These conditions usually remain "high" for extremely long periods of service and usually are the mindset behind an operator's temperature class requirements. Therefore, downhole equipment may not hold too many insights for other production equipment designs. In fact, the narrow focus might restrict how we view the performance of ancillary equipment. A "one-temperature-fits-all" approach may overcomplicate or defeat the possibility of finding a workable mechanism.
Obey or ignore the environment?Early forays into HP/HT reservoirs peaked in 1982 when roughly 1,200 wells were drilled below 15,000 ft (4,570 m) in the United States. Although the number of HP/HT wells drilled decreased, the target depth steadily increased over the next 10 years reaching 22,500 ft (6,860 m) and recently 33,000 ft (10,060 m). This trend was encouraged by the promise that deeper wells offered greater production capability. Deep reservoirs make up less than 1% of the total number of wells, but account for nearly 7% of domestic production.
Conditions were considered well beyond the historical limits of "sour" service set by NACE standards and boiler code conditions had to address the extreme bottomhole temperatures. Conservatism ruled in planning and drilling these wells, calling for the highest grade, strongest materials available. Most notably, wells were designed with high nickel content CRA tubular goods to mitigate well control catastrophes caused by cracked casing succumbing to the environment. Proximity to population centers and local regulations also mandated their use. CRAs were considered the best choice because corrosion rates for carbon steels would be an order of magnitude greater than practical corrosion allowances.
Recent activity in deep gas plays offshore the GoM look at that same well construction philosophy from a completely different perspective – using carbon steel alloys instead of CRAs. How does this happen, given that many HP/HT wells take a year or so to drill and complete? Surface and upper intermediate casing strings feature 55-85 ksi grade material while deeper casing strings are being set as multiple liners using 125 ksi grade materials (the higher grades being down-rated 10-15% for wellbore temperature to achieve the necessary load requirements).
The question is: why is carbon steel surviving? The answer could be theenvironment. Carbon steel pipelines and production tubing in hot, high-sulfur wells in the Kashagan field are surviving 20% hydrogen sulfide conditions because of the high sulfur, low oxygen environment. Pipeline maintenance shows this condition creates a ferrous sulfide coating in the bore, which (if left undisturbed) reduces the corrosive metal loss rate from 40 mpy to 5-10 mpy.
Canadian heavy oil wells exhibit similar equipment survivability using mild service (material class AA), low cost carbon steels for wellhead and completion hardware. Asphaultine-like wellbore fluids produced from these wells constantly coat the bore of the tubing and well control equipment. The well's relatively high-producing temperature "cooks" this coating onto the pipe to give it a protective lining. As with Kashagan, it is a brittle covering, but if left undisturbed, greatly reduces the corrosion rate.
High temperature also may be an ally from another perspective. It is common practice to post-weld heat treat welds for stress relieving and "baking out hydrogen" at temperatures between 400-800 °F (205-425 °C). Work string tubular goods used in workovers routinely are baked at these temperatures after a sour well job to get rid of residual hydrogen. Extreme and ultra HP/HT reservoir temperatures approach this same temperature range, suggesting that high-strength tubular goods may avoid embrittlement problems because the higher ambient temperature allows hydrogen to pass through the steel's molecular lattice structure.
Because of severe requirements and the lack of sufficient data under HP/HT conditions, the industry is limited in its ability to produce oil and gas from these wells. In spite of this, the industry is drilling and logging HP/HT wells with renewed vigor. Drilling these wells has been accomplished using clever techniques which challenge established norms. If current standards and practices are to be upheld, the industry must begin immediately to put HP/HT developments on a scientific footing instead of relying on old rules.
Because it is difficult to accurately define conditions, some companies err on the side of costly and conservative approaches to accessing deep HP/HT reservoirs, or else abandon the attempt altogether. Others choose to ignore the possible hazardous conditions and forged ahead because there is no concrete answer.
The oil industry's continued can-do spirit shows that the HP/HT environment might be used to our advantage rather than treated as a problem. Limiting exposure rather than assuming "last forever – no maintenance" extends conventional designs and makes it possible to use more economical materials and seal technology. The old "20-year design life" mantra has to be replaced with a practical "operating life" philosophy. Lowering the life expectancy of materials to a tolerable obsolescence lessens the design challenge and contradictions (strength versus ductility, years/corrosion allowance versus cycles, near wellbore versus near environment location, high temperature operation versus low temperature shut-in, etc.). Yet, in light of the convention-stretching attitude of the best wildcatters there still is a ways to go. Design methodology appears to be maturing in time to meet HP/HT market needs. Insufficient materials data under HP/HT conditions relegates the industry to educated supposition or technical risk mitigation based only on experience.
More Offshore Issue Articles
Offshore Articles Archives
View Oil and Gas Articles on PennEnergy.com
