Prior art instruments are used for surveying the path of a subterranean wellbore. The instruments are carried by a tool which is moved along the wellbore by a wireline or pipe string. The tool is stopped at locations or stations spaced along the length of the wellbore. Measurements relating to dip angle, azimuth and roll can be taken at the station. The position of the tool along the length of the wellbore is known from measuring the length of wireline or pipe in the well. These measurements provide information with respect to the heading and path of the wellbore for determination of each station's elevation and areal position (its position in the horizontal plane as viewed in plan).
With every measurement taken, there is an associated error. With the prior art tools, each measurement is referenced from the previous measurement. Errors from previous measurements are added to subsequent measurement errors, accumulating and, in a worst case, compounding. This linearly additive error can become significant after a number of stations.
The extent of error can vary between the different types of tools.
The "gyro" tool is one of the most accurate of the tools. Its additive errors are fairly small and are generally acceptable for most applications. The gyro tool utilizes a spinning gyro to measure the rate of change of the tool's dip angle (up and down), azimuth (horizontal left and right) and roll (rotation about the tool's axis). A disadvantage of the gyro tool is its fragility and susceptibility to failure during use, in what is typically a rough handling environment.
Another type of tool, known as a magnetic flux gate and slant tool, combines measurements of the tool's horizontal orientation relative to the earth's magnetic field (azimuth) and dip and roll angles using pendulums and other means. These magnetic tools can be affected by other magnetic influences and must be positioned within a non-magnetic drill collar.
Another commonly used tool is the MAXIBOR tool (MAXIBOR is a registered trademark of Reflex Instrument AB, Sweden). The MAXIBOR tool uses an optical system to measure dip and azimuth by monitoring the extent of bending of the tool along its length. The bending is caused by the curvature of the wellbore. The roll of the tool is determined using a liquid level. The deflection of the drill string and wellbore is calculated from measurements recording the deflected centerline offset of a plurality of normally coincident reflective rings, spaced at known distances along the bore of the tool's length, and establishing the orientation of the rings with respect to gravity. The accuracy achieved with the MAXIBOR tool is markedly affected by the fit of the tool within the wellbore. The tool is provided with centralizers to centralize the tool within the bore of the drill string. A loose fit is often required so as to enable the centralizers to clear drill string joints and pass narrow diametral bore tolerances. A loose fit reduces the net deflection of the tool and understates the wellbore deflection.
All of the above-mentioned tools are relative-measurement tools and, when used, must involve a traverse (survey from station-to-station) of the entire wellbore, from an unknown point to a known point or visa versa. By way of example, if a wellbore is 700 m long and the reference station is at the beginning of the wellbore, then, in seeking a profile of the last 60 m one would have to traverse the entire length of the wellbore to obtain the desired information. One must know the absolute coordinates (elevation and areal position) of at least one point in order to tie, or anchor, the measured coordinates to an absolute location in three dimensional space. This serves the same purpose, though it is not as complete, as closing the loop of a surface survey to see if accumulating errors have prevented one from returning to the same place one started from. If the entire survey is not performed, then the measured data is left "floating" without a correlation to a known point in three dimensional space. Carrying out an entire traverse is time consuming and successive surveys typically demonstrate variable amounts of non-repeatability in the measured survey end-points.
Both the magnetic and the MAXIBOR tools are less accurate than the gyro tool. While the accuracy of these tools may be adequate for some drilling exercises, it is not adequate where close control of the absolute coordinates of the wellbore is required.
The present invention was developed in conjunction with a pilot project that required very accurate control of wellbore locations. This project was referred to as the Underground Test Facility ("UTF"). It was operated in the Athabasca reservoir, which contains immobile, viscous heavy oil or bitumen. The project involved sinking a vertical, concrete-lined shaft from surface, through an oil sand reservoir and into an underlying limestone strata. A horizontal tunnel was mined through the limestone. Wells were drilled upwardly out of the tunnel to the base of the oil sand and then turned to extend generally horizontally through the oil sand, parallel and close to its bottom surface. The wells were provided in pairs: a lower production well and an upper steam injection well. The production well was drilled first. It had some deviation both in profile and plan. The injection well was then drilled with a view to tracking the production well so that it remained directly over the latter in coextensive, parallel, vertically spaced apart relation. An oil recovery process referred to as steam assisted gravity drainage ("SAGD") was then implemented. Initially, steam would be circulated through both wells to create "hot fingers". The viscous oil in the interval between the wells would be heated by conduction and would drain downwardly so that a "fluid communication" zone would be opened between the wells. Then the upper well would be converted to steam injection and the lower well would be converted to fluid production. The injected steam would ascend and heat the upwardly expanding surface of a chamber from which heated oil had drained. The mobilized oil and condensed steam would drain into the lower well and be produced into the tunnel, from whence it was recovered to ground surface.
Now, it is essential that the pair of wells be drilled so that the injection well was directly above the production well and spaced a constant distance from it. If the wells drifted apart too much in profile or plan, an inordinate amount of time would be required to heat the span between them by conduction.
It was thus necessary:
to know accurately the path of the production well, in profile and plan; and PA1 to accurately know and control the path of the injection well during drilling, to cause it to closely track the production well. PA1 positioning a downhole tool in the drill string at the survey point which measures fluid pressure; PA1 providing means for measuring fluid pressure at a reference point of known elevation, said reference measuring means being in pressure sensing communication with the column of fluid; PA1 providing means located outside the wellbore for calculating elevations from differential fluid pressures; PA1 measuring the fluid pressure at the reference point and transmitting a signal indicative of the measurement to the calculating means; PA1 measuring the fluid pressure at the survey point and transmitting a signal indicative of the measurement to the calculating means; and PA1 calculating the elevation of the survey point knowing the pressure measurements, the density of the fluid and the known elevation of the reference point. PA1 providing means for measuring fluid pressure at a second reference point of known elevation different from the elevation of the first reference point, both reference points being in pressure sensing communication with the column of fluid; PA1 measuring the fluid pressure at the second reference point and transmitting a signal indicative of the measurement to the calculating means; and PA1 calculating the density of the fluid knowing the pressure measurements and the known elevations of the first and second reference points. PA1 positioning a downhole tool at a survey point in the bore, said tool carrying means for measuring fluid pressure, means for measuring the traversed distance of the tool along the wellbore, and means for measuring the dip angle of the tool, all measured at the survey point; PA1 providing means for measuring fluid pressure at a reference point of known elevation along the length of the column of fluid; PA1 establishing measures indicative of the elevation of the tool at the survey point using the differential between the fluid pressure at the survey point and the reference point and the fluid density; PA1 establishing measures of the dip-angle of the tool at the survey point; PA1 establishing measures of the traversed distance of the tool to the survey point; PA1 establishing measures of the horizontal location of the tool using the traversed distance and the orientation of the tool at the survey point; PA1 moving the tool and measuring means to a new survey point; and PA1 repeating the measurement and moving steps for determining measures indicative of the profile of the path of the wellbore knowing the elevation, horizontal position and dip angle of the tool, where the azimuthal deviation of the path assumed to be zero. PA1 additionally providing means associated with the tool for measuring the tool's rotational orientation from vertical and means for measuring the bent sub's rotational orientation relative to the tool, also measured at the survey point; PA1 performing the measurement and tool-moving steps for determining the path of the wellbore; and PA1 re-orienting the bent sub's rotation to change the direction of advance of the drilling string knowing the rotational orientation of the bent sub relative to the tool and the tools rotational orientation from vertical.
A wellbore path may be described as laying within two orthogonal planes: the profile, which represents vertical or elevation variations of the wellbore occurring over the wellbore's length; and the plan, which represents horizontal variations occurring over the wellbore's length.
The SAGD process is particularly sensitive to variations in the profile which impact the vertical separation of the injection and production wellbores and adversely affect performance.
This sensitivity may be demonstrated by examining the effect an error can have on a typical horizontal wellbore extending in excess of 600 meters in length. This wellbore, say it is the production well, will not lay in a perfectly straight line but will typically vary somewhat. An acceptable imaginary target envelope would have an injection well positioned somewhere within an upper bounding surface defined by a 90.degree. arc and a horizontal base positioned about 3 to 7 meters above the producer. Ideally, the injection wellbore would remain about 4 to 5 meters directly above the production wellbore. For a wellbore length of over 600 meters, an error in measuring the heading of a wellbore near its start of about 1.degree. will result in an indicated end of the wellbore being skewed over 10 meters from its actual end. Errors of this magnitude do not permit a driller to confidently project that a SAGD injection wellbore will successfully track the production well within the desired envelope.
Thus, a system is required that can accurately determine the path of a wellbore, particularly with respect to its profile. This would better enable one to accurately position the injection wellbore of an SAGD project relative to a production wellbore.
USPTO Backgrounds
USPTO Backgrounds