Vacuum Flask : Down hole, Wireline Logging, Geothermal

Well bore diameters in geothermal wells tend to be larger than in the oilfield to achieve the required flow volume and geothermal wells do not use smaller diameter production tubing like in oilfield. Down hole pressures are considerably lower than in oilfield.

Although the working fluid is water, corrosion can be a significant issue in geothermal wells for the downhole casing and surface plumbing. The corrosion is generated by the combination of high temperature and water's high mineral solubility. The water contains dissolved corrosive gases and solids such as CO2, H2S, NH3 and chloride ions. The dissolved solids can lead to scale build up within the downhole casing and eventually constrict the flow to the point that remedial de-scaling operations have to be performed.

Variations in flow volume creates thermal cycling which causes variations in the casing's thermal expansion along its length. Large amounts of thermal expansion cause large amounts of linear travel for the casing and at times buckles the casing. The combination of casing corrosion, scale build up and casing deformation drives the need for casing integrity logging.

Pressurized fluid is pumped at surface through the injection well and then flows through the fractured zones extracting the thermal energy and then the heated fluid returns to surface through the extraction well.

CO2 has a larger density change in a pumped system than water. It has a higher change in density between when it is pumped down (cold) and when it is circulated up (hot). The large density change means that it becomes more buoyant than water once heated by the reservoir and would require less power (parasitic power) to circulate the system. Although CO2 has lower thermal mass than water which requires higher flow rates to achieve the same mass flow rate as water, supposedly the required circulating power consumption is still less with CO2 than water.

CO2 also has lower mineral solubility than water which reduces the costs of corrosion and scaling remediation.

Although geothermal and oil and gas are similar in that they both extract fluid, they differ on the types of data required to manage the reservoir. The oilfield requires more geological information than geothermal and consequently commissions a larger range of logging tools. The oilfield geologically characterizes new and existing formations to understand the elemental composition, geometric compositional structure and flow characteristics. Hydrothermal geothermal systems traditionally require little geological information other than the knowledge of naturally present fractures.

Eventually, the geothermal industry will require more geological data as Enhanced Geothermal Systems and injected CO2 in Enhanced Geothermal Systems become commercially viable.

Above 500F (250C), tools are deployed downhole on mechanical slickline and the tools are memory based. As the downhole temperature increases, so does the damage to the wireline from corrosion and embrittlement.

The materials being used are FFKM, EPDM and to a less extent FKM. Metal seals are still used reliably beyond 600F (316C).

Corrosion: Corrosion can be a significant issue in geothermal wells. The extent of corrosion increases with the temperature. We have seen some metals literally lose volume (shrink in size) by dissolving in the fluid over years of use.

Thermal expansion: Logging tools are exposed to an extremely high temperature range from ambient to 800F+(430C+). Consideration must be given to the differential in thermal expansion between the various materials in a tool to avoid unforeseen mechanical loads or seal failures.

The temperature sensor is an RTD or thermocouple. Some sensor designs place the sensor in a protective hermetic thermowell while other designs use a sheathed sensor exposed directly to the well bore fluid. RTDs and thermocouples can withstand high well bore temperatures, but the associated electronics are thermally protected within a vacuum flask from high well bore temperatures.

A good tool design maximizes the sensor's exposure to well bore fluid flow (to increase sensitivity to temperature changes) while also mechanically protecting the slender protruding sensor from impact damage within a protective cage. It has sufficient distance between the sensor and the tool body's thermal mass. If the sensor is too close it becomes excessively influenced by the tool body's temperature instead of the well bore fluid's temperature. The sensor in part essentially measures the tool's body temperature response to the well bore fluid instead of the well bore fluid itself which reduces the sensor's temperature response time. Typically, the sensor is at the bottom of the tool although some designs place the sensor mid length in the tool to allow other tools to be connected below the temperature tool section.

The pressure transducer is thermally protected within the flask. Fluid pressure is brought to the transducer via a small diameter buffer tube (oil filled tube). The buffer tube is a conductive heat path into the flask but if the tube is stainless material less heat is transferred than one would think.

Pressure sensor measurements must be temperature compensated and consequently a temperature sensor is required mounted on or near the pressure sensor. Some pressure and temperature logging tools that are not flasked use the well bore temperature sensor's measurement to infer the temperature of the pressure sensor. In order for such a tool to be flasked, the tool requires adding a second temperature sensor (mounted on or near the pressure sensor) since the external well bore temperature and internal flask temperature will be thermally decoupled and have drastically different temperatures.

In the future, EGS might use high speed fast sample rate capture pressure logging tools during perforating operations to capture rebounding pressure return signals from the formation which aid in characterizing formation stresses and structures. EGS might also use high speed pressure logging to manage hydraulic fracturing operations.

The simplest sensor configuration has the sensors placed outside of the vacuum flask (exposed to well bore temperature) with the associated electronics housed within the vacuum flask (thermally protected from the well bore temperature). Alternatively, the sensors can be protected with the flask along with the associated electronics.

The high-resolution measurements are used to identify material loss from corrosion, casing deformation from thermal cycling and scale build up within the casing bore. Induction sensors measure the displacement of each finger and the induction sensors along with the processing electronics, memory section and batteries are housed with a flask.

The reading is general and does not resolve azimuthal variations (like the Multifinger caliper tool does) but can detect metal loss on the exterior of the casing (unlike the Multifinger caliper tool does). Commonly paired with a Multifinger Caliper tool.

The individual explosive shape charges and single explosive detonating cord are integrated into a long carrier body and housed within an outer housing tube, commonly referred as a hollow gun arrangement. The explosive materials are temperature sensitive and loose energy at prolonged exposure to high temperatures. There are 3 commercially used explosive materials with different temperature limits: RDX, HMX, HNS. The temperature exposure is a function of time at temperature. Higher well bore temperatures require short exposure durations. For geothermal wells, a long flask substitutes for the conventional long outer housing serving the dual role of separating the explosives from the well bore fluid and protecting the explosives from the damaging high temperatures. The perforating charges shoot through the walls of the flask just like a traditional hollow gun arrangement. The flask's outer tube can be "scalloped" to reduce the tube's cross section to minimize attenuating the shot and eliminate protruding external burrs.

A primary concern during the fracturing operation of EGS wells will be to avoid extending the fractures outside of the hermetic boundaries of the reservoir otherwise it will not be possible to maintain the required pressure to keep the fractures open. It is possible that in the early years of EGS fracturing, downhole hydrophonic surface and seismic sensors will used to "listen" and aid in managing the fracturing operation. The downhole hydrophones would be flasked to protect them from the high temperatures.

Telemetry to the surface during drilling is required real time to direct the well's path. An existing steering practice in high temperature oilfield is using electric line (rated to 500F) and a flasked directional tool, colloquially known as long line wireline steering. The wireline and tool are run inside the drill pipe during drilling but only when sliding (drilling via the mud motor and while not rotating the drill pipe). The wireline and tool are pulled out of hole at the incremental addition of each stand of drill pipe. A stand of drill pipe is approximately in 90 ft (27 m) long.

The temperature of the directional tool within the flask is known real time via the wireline and when the temperature within the flask rises too high, the directional tool and flask are replaced with a fresh set on the next stand. The steering tools free falls to bottom with a well bore inclination of up to 60 degrees from vertical. The tool is lowered at a rate of about 500 ft (150 m) per minute and pulled out of hole at 700-800 ft (210-245 m) per minute.

Drilling in hot dry rock will probably be slower than in the oilfield which means that the ratio of downtime for wireline tripping to total drilling time will not be as severe as when this method is used in the oilfield with much higher rates of penetration. While not operationally ideal, the tremendous benefit is that, the technology and practice already exist. No new technology is required to develop future EGS reservoirs.