Ian Verhappen
Industrial Automation Networks Inc.
As the industry continues to develop reservoirs in more extreme environments - deeper water, higher sour gas concentrations, greater concentration of wells per pad, longer horizontal depths - the need to understand what is happening not only while drilling the hole but also during production continues to increase in importance.
The industry uses gyroscopes, magnetometers and accelerometers, as well as traditional well logging measurements, to determine formation properties (resistivity, natural gamma ray, porosity), wellbore geometry (inclination, azimuth), drilling system orientation (tool face), and mechanical properties of the drilling process. As these measurement tools are part of the drillstring and must provide the data in real time so they can be used to control the steering and direction of the drill bit (hence the name measurement-while-drilling, MWD), the data needs to be transmitted to the surface. The two most commonly used ways are via pulses through the mud column (mud pulse) and electromagnetic telemetry. Technically, the formation property measurements are referred to as logging-while-drilling (LWD) tools; however, many of the communication techniques are the same.
With day rates for offshore drilling near $500,000, minimizing "time on hole" while maintaining a safe operation becomes critical. MWD helps both these criteria by reducing drilling problems as well as risk. Reductions in risk are possible because wear and fatigue on drillstring components will be minimized and downtime caused by bottomhole assembly (BHA) components failures (bits, mud motors, and MWD tools) can be eliminated. It is also possible to improve the actual drilling process with improved rates of penetration by reducing drillstring friction against the side of the wellbore. This results in the right amount of drilling energy being transferred to the bit while also helping the driller appropriately adjust both weight-on-bit and rotation speed as the lithology changes, thus optimizing the performance of bits and mud motors.
Due to the limited "bandwidth" available with pulse communication and the risk that this communication could be lost, these tools will also have on-board memory to store the same information at a higher update rate. This provides increased granularity of measurement, and the data can also be recovered once the tool is removed from the hole.
Due to the limited bandwidth available of approximately 40 bits/second with pulse communication, and the risk that this communication is lost, these sensors also have on-board memory to store the same information at a higher update rate than it is possible to transmit. Increased update rate equates to more and hence better measurements which can be recovered once the tool is removed from the hole.
Three mud-pulse telemetry systems are available: positive-pulse systems create a momentary flow restriction (causing the drilling-mud pressure to rise) in the drillpipe; negative-pulse, as the name implies, uses a pressure pulse lower than that of the mud volume by venting a small amount of mud to the annulus; and continuous-wave systems generate a carrier frequency that is transmitted through the mud, and then encode data using the phase shifts of the carrier. In general, oil-based muds (OBMs) and pseudo-oil-based muds are more compressible than water-based muds, and this compressibility leads to greater signal losses. Attenuation in mud-pulse systems is approximately 150 dB per 1,000 m (3,280 ft) in drilling fluid; though signals can still be detected in wells with depths in excess of 9,000 m (29,520 ft). When air or foam is used as drilling fluid, low-frequency electromagnetic transmission is starting to gain traction.
With the increasing number of horizontal wells being drilled, once a well angle exceeds 60°, the logging tools can no longer be pushed through the well to retrieve information. This provides another incentive to incorporate the above basic measurements into the drilling process.
Though an important part of the process, drilling and completion is only the start of a well's lifecycle. Once the well has been drilled, it is important to confirm that the reservoir has not been damaged to help ensure best return on investment by optimizing the well's production.
In addition to "traditional" wired sensors, fiber optic sensors are well suited for downhole applications because of the high resolution of both measurement and location of sensing element, immunity to EMI, small size, and multiple kilometer sensing capability. Fiber optic sensors are able to achieve 0.1% accuracy with a 0-8,000 psi working range for the pressure sensor with similar results over the 0-600°C working range for the temperature sensor. Wellbore temperature data can be used to calculate flow contributions, evaluate water injection profiles, diagnose the effectiveness of fracture jobs, find cement tops behind casing, and identify crossflow between zones.
Because pressure drop drives a corresponding change in volume of liquid or gas, which is accompanied by a change in temperature, these changes make it possible to use temperature to observe when warming oil or water or in the case of gas cooling (Joule-Thompson effect) enters a wellbore.
One of the historical challenges that impeded practical use of downhole optical sensing systems for many years was the diffusion of hydrogen into the core of the glass sensing fiber-a phenomenon known as hydrogen darkening. Fortunately, modern pure-silica fibers with virtually no darkening and improved hermetic coatings and packaging techniques can allow fiber operation at temperatures up to 700°C. Just as the challenge of fiber optic darkening is being addressed, the sensing systems themselves are also continuing to evolve. These systems can now be multiplexed in a variety of configurations on a single quarter-inch cable, offering permanent deployment of multi-parameter sensors in multiple zones in the harshest of conditions.
Automation technology is an important piece of the production puzzle, because if you do not know what you are doing, how can you take appropriate steps to understand and control it, let alone optimize the results? Fortunately, as industry challenges continue to increase, automation and sensing technology continues to rise to the challenge by providing hardware and software solutions to continue to "push the envelope."
The author
Ian Verhappen, P.Eng. is an ISA Fellow, ISA Certified Automation Professional (CAP), Automation Hall of Fame member, and an authority on process analyzer sample systems and industrial communications technologies. Verhappen provides consulting services in the areas of field level industrial communications, process analytics, and hydrocarbon facility automation. He can be reached at[email protected].
