By John Murphy
Historically, mainly for lack of a marketplace, High Pressure-High Temperature (HP-HT) drilling and completion technology has received little attention from either operators or oilfield service companies. By most estimates HP-HT wells, that is well whose shut-in surface pressure exceeds 10,000 psi or with bottom hole temperatures above 350ºF, account for less than 2% of all wells drilled worldwide. As a result, according to B.N. Murali, technology vice president at oil services giant Halliburton Energy Services, solutions to oil and gas HP-HT wells have evolved outside the petroleum industry.
"There is a lot of technology that has been developed over the years," he said from his Houston office. "We have been servicing geothermal wells that go up much higher than 350ºF for some time."
Lab for high temperature applications (back to top)
While geothermal wells have provided a laboratory for high temperature applications, they fall short of a perfect proving ground, as they are not high-pressure and do not account for the effects of hydrocarbons in a heated environment. Now, however, as the petroleum industry moves into increasingly deeper waters, where well total depths consistently exceed 15,000 ft below sea level and both higher pressures and higher temperature environments become more commonplace, oil industry-specific solutions are required. Likewise, as Asian economies revive and spur increased oil and gas drilling on the perimeter of the Pacific Ocean—called the Ring of Fire for its proliferation of volcanic activity—demand for HP-HT oilfield specific technology will also increase.
Weatherford's Steve Norris says his company can responded to anticipated increases in HP-HT tool demand with two specific tools, one a special drilling motor and one a tool to adapt standard inflatable packers to the effects of temperature change common in flowing HP-HT wells.
"We have purchased the exclusive license to the MacDrill Bane downhole motor," he said. "It has no rubber-like seals like those in conventional motors that are affected by temperature. Therefore it can run in temperatures up to 600ºF in total N2 or aeromatics such as diesel and naphtha without breaking down the seals. It can also take up to 15% acid through the tool."
Weatherford also has a license for inflatable packers granted them from HPI. In its most basic form an inflatable packer can be likened to a balloon inflated around tubing to form a seal against the wellbore wall. Commonly, as high temperature wells flow to the surface, the fluid cools. As a result the inflated packer can contract and slide down hole. To combat the situation, Norris reports his company has patented a "thermal compensator" placed below the packer to maintain the packer's pressure and thus its seal.
When high temperatures are added to the dynamics of well completion and production, engineers must turn to chemists. This is particularly true of drilling, completion, and treatment fluids whose temperature-related chemical make-up is critical to their efficacy.
As such, the fluids industry is developing drilling fluids able to maintain necessary weight and viscosity in temperatures to 400ºF and higher. "We are now pushing the envelope for drilling fluids beyond 450ºF," Murali said. "In fact we are trying to formulate new fluids which go up to 500º. The chemistry on the 450º drilling fluids have been performing for the last several months now very effectively."
Treatment fluids used to improve well performance offer their own challenges in high-temperature environments. The large amount of fluids that comprise a massive fracturing job tend to cool the formation sufficiently to nullify the effects of heat but, particularly in offshore applications, hydraulic fractures are significantly smaller affairs mostly used to control sand or remediate drilling damage.
In such cases, the formation is not cooled, and companies have been forced to create special HP-HT fluids systems such as Halliburton's Sand Wedge that can survive temperatures up to 350ºF and still perform the necessary sand carrying and displacement functions.
Possibly the most temperature-sensitive oilfield activity is cementing. Perversely, it is also one of the most critical. Poorly placed cement jobs can result in casing collapse, behind-pipe fluid flow and other associated calamities that can result in expensive workovers or even catastrophic well failure.
Cement retrogression (back to top)
In high temperature situations, cement goes through a retrogression which, says Murali, "tears up the chemistry of the cement so that it won't develop compressive strength, which is what you need." The answer has often been found in flyash-based additives that allow oilfield, or Portland, cement to develop compressive strengths even in wells to 400ºF. Work is underway to raise that ceiling to 500º.
Actually, in the case of high-temperature oil and gas wells, depth adds a second challenge to good cementing jobs. In standard temperature, deep wells an additive is used to retard the cement's gel time so that it can reach its target depth before beginning to gel. In HP-HT wells, which are nearly always extreme-depth wells, standard retarders fail and the cementing industry has responded with special retarders.
One of the most complex fluids problems in HP-HT wells involves acid stimulation. When high temperatures and acids are mixed, an extremely corrosive environment is created. In order to combat that complication, the industry has traditionally used corrosion inhibiting chemicals to "plate out" on and thus protect the exposed tubulars.
Unfortunately, when the spent acid is flowed back from the formation, it carries the metal-based corrosion-inhibiting chemical. The resultant fluid is environmentally hostile. In response the industry has lately developed non-metal-based inhibitors that, in combination with spent acid, create a benign, environmentally friendly fluid.
Once an HP-HT formation has been drilled, it presents several challenges to the normal logging and testing procedures. In terms of deep, high pressure wells, open hole logging tools may be forced to endure hydrostatic pressures greater than 25,000 psi. "In say 10,000 ft of water, the well may be drilled 15,000 ft below the seabed," explained Baker Atlas's Mike Donohue. "With the riser filled with drilling mud you create (bottom hole) pressures above the (standard tool specification of) 20,000 psi. We have basically upgraded our open hole tools to cover everything up to 30,000 psi."
Baker Atlas upgrades (back to top)
The Baker Atlas upgrades are performed on standard open hole logging tools via a kit that includes high-pressure housings and what Donohue calls "better connectors". Logging companies have long had what they call "hot-tools" for logging wells up to 350ºF and most have expressed confidence that increasing their capabilities to 400º or even 500º will present no significant problems.
Even with greatly improved seismic and logging tools, nothing so inspires an operator to develop a new field as a prolonged exploratory well test. To do this, particularly in frontier areas without infrastructure, special well test tools, both downhole and on the surface, must be used to control and monitor the flow. Dealing with the hostile environment itself has presented some problems, mostly solved, but have brought up others.
Challenges of late include the presence, common to deep, HP-HT wells, of such corrosives as carbon dioxide or hydrogen sulfide in solution with produced fluids. When such wells are flowed, particularly offshore where hot reservoir fluids pass through extensive risers bathed in cold seawater, corrosive gases held in solution above about 175ºF drop out below that mark. Over the course of an extended well test the harmful gases can attack test equipment, tubulars, and pressure seals.
Major test companies in the industry have solved the problem through new elastomers for seals and new alloys. And now Halliburton is said to have a metal unaffected by corrosive gases which, with proper seals, can be used in environments up to 20,000 psi and 450ºF.