Continuous Direction and Inclination Measurements Lead to an Improvement in Wellbore Positioning

Abstract

Continuous Direction and Inclination Measurements Lead to an Improvement in Wellbore Positioning E.J. Stockhausen; E.J. Stockhausen ChevronTexaco Search for other works by this author on: This Site Google Scholar W.G. Lesso, Jr. W.G. Lesso, Jr. Schlumberger Search for other works by this author on: This Site Google Scholar Paper presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, February 2003. Paper Number: SPE-79917-MS https://doi.org/10.2118/79917-MS Published: February 19 2003 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Stockhausen, E.J., and W.G. Lesso. "Continuous Direction and Inclination Measurements Lead to an Improvement in Wellbore Positioning." Paper presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, February 2003. doi: https://doi.org/10.2118/79917-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE/IADC Drilling Conference and Exhibition Search Advanced Search AbstractThe measurement of continuous real-time inclination provides near instantaneous calculations of the build-up rate tendency of a bottom hole assembly in both rotary and slide drilling modes. The addition of an azimuthal measurement now allows for the calculation of wellbore position with this continuous data. The true nature of the wellbore curvature in slide/rotate directional drilling with steerable systems is lost when using the typical 90-foot survey interval. Continuous surveying shows this effect. When wellbore position is calculated with the continuous surveys, a significant positional discrepancy from the stationary surveys can occur.A study was conducted using both stationary and continuous survey data from over 20 wells in Nigeria, Angola, the Gulf of Mexico, the North Sea and Indonesia. The objective was to determine the magnitude and scope of TVD positional error caused by the different slide and rotate curvatures between stationary surveys on a wide range of wells. These curvatures are not reamed out as commonly thought. They can still be seen in continuous gyro surveys taken after drilling has finished. This positional effect is not a function of the sensor accuracy, but it is a result of the environment in which surveys are measured. We show that in a horizontal well the effect can accumulate up to plus/minus 25 ft TVD. The implications of these results are far reaching. Survey positions are used in creating structure and reservoir maps, which are used in determining reserves and recovery efficiencies, and in turn for making field management decisions.This paper highlights the results of the field studies. A review of rotary steerable system operations shows that the effect is much less than with steerable motors, but can still be of concern.A low-cost solution for effectively determining when to slide and rotate with respect to the stationary survey is presented. This procedure results in a positional accuracy that can be maintained without changing survey data management practices.IntroductionFor more than 15 years the directional well surveying industry has settled on a standard method of calculating the position of a wellbore from inclination and azimuth measurements. This method, called minimum curvature, determines the smallest radius curvature between two survey stations1,2. The position coordinates for the second survey, in terms of easting (X), northing (Y) and true vertical depth (Z), can then be calculated. A basic assumption is that there is no appreciable change in the curvature between the surveys.Two things happened in the early 1990's that have altered this assumption. First, positive displacement motors (PDM's) with bent housings made it possible to drill directionally with a high curve rate (5–10 deg/100ft) when slide drilling and then switch to drilling in rotary mode with curve rates usually less than 1 deg/100ft. Second, top drives on offshore and some land rigs made it possible to drill three 30-ft joints of pipe (or a stand) without stopping to make connections. MWD tools usually take a directional survey when the mud pumps are cycled off and then on when a connection is made. This means that surveys gradually came to be taken every 90 feet instead of every 30 feet.These two developments meant that the probability of differing curve rates between survey points increased dramatically; the interpolation between the surveys did not reflect the actual trajectory of the wellbore. It became difficult to model and predict curve rates for various PDM's, and there was speculation that the location of the wellbore at any point may be incorrect. This positional difference would be in addition to the positional uncertainty that results from sensor accuracy and alignment specifications3,4. Directional drillers took extra surveys or check shots to help with trajectory tendency work, but little was done to determine the effect on wellbore position. Keywords: procedure, inclination, calculation, drilling operation, tvd, stationary survey, curvature, curve rate, non-constant curvature, delta tvd Subjects: Drilling Operations, Directional drilling This content is only available via PDF. 2003. SPE/IADC Drilling Conference You can access this article if you purchase or spend a download.