The Offshore Technology Conference (OTC), held each year in Houston, Texas, US, is one of the world's leading upstream oil and gas events. Before OTC 2020 was cancelled due to the COVID-19 pandemic, Oilfield Technology contacted a range of key players in the upstream industry and asked for their insight on the latest technologies that were due to be showcased at this year's OTC.
In this submission, Barry Smart, Gyrodata, UK, looks into the applications of a drop gyro surveying system in the oilfield.
The oilfield has changed significantly over the past decade. Once prolific fields are now ageing, technology continues to evolve, and the industry faces increased scrutiny from investors and concurrent reductions in CAPEX and OPEX. The issues of the past have given way to a new set of challenges. Reducing the risk of wellbore collision when drilling is critical in crowded fields involving directionally drilled wells. It also crucial that companies reduce the risk of their well deviating from a planned trajectory, as this could place the well hundreds of feet away from a hydrocarbon-producing target zone. Accordingly, accurate, precise wellbore placement is replacing speed as the primary value driver when drilling a well.
To this end, Gyrodata has introduced its new solid-state gyroscopic technology, SPEAR™, which powers its OmegaX™ drop gyro surveying system. OmegaX is a tandem sensor drop gyro multishot system used to reduce anti-collision risks and the ellipse of uncertainty (EOU), with three axes of the Coriolis vibratory gyroscope sensors allowing gyrocompassing at all inclinations. This means the tool can be utilised in drop mode in any section of the wellbore. The system features an extended memory capacity and battery life, is more reliable and robust than previous systems, and removes the need for a wireline to run the gyro downhole. The new system also has no mass unbalance error on the sensor and collects surveys at connections while tripping out of hole, which results in little to no rig time. Through more than 80 global runs, the system has demonstrated that it is able to prevent non-productive time (NPT) while reducing the EOU, allowing more accurate wellbores to be placed correctly the first time.
An operator in the North Sea was drilling an extended lateral section from a platform. After drilling the wellbore to total depth (TD) at 6544 m, the operator decided to run a gyro survey to verify the accuracy of the data from the measuring while drilling (MWD) and reduce the EOU to improve the final wellbore placement. The operator originally proposed a continuous wireline gyro survey to accomplish these goals but ultimately chose the OmegaX system instead.
Compared to the wireline survey, the survey reduced the EOU by 56% (Figure 1). Compared to the existing survey data in the wellbore, which utilised MWD data with corrections for in-field referencing, multistation analysis, and bottomhole assembly (BHA) sag, the new survey provided a 46% reduction in lateral uncertainty, leading to the final wellbore position being moved 19.8 m laterally. In addition, the system reduced survey time vs an equivalent wireline run, which would have taken approximately 12 hours, including rig-up and rig-down.
Figure 1. The yellow circles show the EOU as calculated with the original MWD survey data. After running the OmegaX system, the EOU shrank by 56%, as shown by the red circles. This meant the well was able to be placed more accurately.
By using the new system, the operator saved rig time, required fewer people onsite, and reduced the risk to heath, safety and the environmenet (HSE) by removing the need for wireline. In addition, using the system reduced the EOU and revealed that the wellbore had not been placed accurately as noted in the original MWD survey. As the industry continues to advance, the advantages of running gyro surveys to help optimise wellbore placement will make the technology increasingly common.
Read the article online at: https://www.oilfieldtechnology.com/offshore-and-subsea/13052020/otc-technology-review-gyrodata/
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The well was drilled by the ‘Deepsea Stavanger’ drilling rig, about 25 km southwest of the Oseberg field in the North Sea and 150 km west of Bergen.