Rogers john. Coordinated Development Water-Energy Research. The modules are along the central axis of the drill collar. Drilling mud flows in the annular volume between the drill collar and the modules, from left to right in the drawing. The pulser is the left most element of the package top of the downhole string so that pressure pulses are not attenuated by other modules within the drill string bore.
Pulser and telemetry systems were upgraded to HT specifications and successfully tested in the lab and field. Component and module field testing has indicated that system life goals will be substantially exceeded.
System data from the field are consistent with this but are as yet too limited to provide a firm validation. HES is commercially marketing this tool around the world. Four different resistivity readings, sensitive to various radial depths away from the borehole, are produced by waves emitted by the four differently spaced transmitters. The phase difference for each transmitter is measured at the receiver pair.
The electronics inserts not indicated in the figure controlling the transmitters and receivers are located inside the bore of the drill collar immediately to the left and right, respectively, of the transmitter and receiver antennas.
The antennas themselves are wire loops, installed in grooves around the tool and covered by the circumferential bands indicated in the drawing.
A vibration sensor provides information about average g levels and maximum shocks experienced by the tool. The wear bands are carbide rings around the tool that abrade over time as a result of contact with the formation. They significantly extend the life of the tool and drill collar. The neutron source is installed in the source port just prior to the tool going downhole. Neutrons with MeV energies emitted from the AmBe source slow to thermal energies as a result of collisions with atomic nuclei in the formation and borehole.
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On these TAML Level 4 wells, junction isolation was achieved with special cement and a resin squeeze. Junction related production problems were experienced on two of the wells with lumps of resin flowing back and plugging surface equipment.
One well cleaned up rapidly, whereas the other is currently shut down. The MLT operations on these wells had been completed in 22 days, Although all wells were technically successful and the trend was good there would be a lower limit around 12 days due to all the milling operations required establishing the initial exit and the re-entry to the main bore.
In order to further improve the reliability of the junction and the installation time, a new system would be required. After installation of screens in the main bore reservoir section, a whipstock is installed in the latch coupling and the window opened up to drill the lateral.
To complete the well, the whipstock is retrieved and replaced by a deflector; and a multilateral junction system is then installed as an integral part of the lateral bore completion. The main component is a flexible hanger with D-shaped legs. This component is attached to the lateral liner on one leg and has a stinger on the other leg. The stinger is oriented and lands in a seal stack in the main bore deflector.
On Troll Olje, screens are installed in both the main and lateral bore and the lateral liner is not cemented across the junction. The system was then further developed during and the first installation conducted for Norsk Hydro in the Troll Olje field in Norway. The water depth is — m. Troll Olje is part of the Troll gas field in which Norsk Hydro is responsible for development of two areas of a thin oil rim: the Troll Olje Oil Province 22 - 26m oil zone and Troll Olje Gas Province around 13m oil zone.
The combined development is estimated to recover a total 1. By March , a total of 70 wells had been drilled and completed on the Troll Olje Field, including five multilateral wells. The wells are tied-in to one of the two floating production platforms - Troll B and Troll C.
The multilateral well concept has been introduced on Troll Olje primarily to increase the total drainage area from the existing sub-sea template structures. Further development of Troll Olje includes another 20 multilateral wells.
These multilateral wells contribute additional reserves in the region of 75 million barrels of oil. Drilling all these targets with conventional horizontal wells would not be practical. An alternative solution with four wellhead templates 16 slots would contribute about 25 million barrels of oil less than the multilateral solution and also add greatly to the development costs.
Bailey, Ernest C. Marathon Oil Company. Abstract Traditionally, operators have had limited options for conducting remedial work on lateral re-entries through milled-casing windows. This limitation is due to the necessity of using a "bent joint" of pipe to guide tools through the window. If a bent joint of pipe cannot be attached to the end of the assembly e. Setting a conventional whipstock requires the use of orienting tools that add significantly to the wellcost.
This paper describes the world's first applications of unique technology that helps solve these problems by facilitating the exiting of milled-casing windows with service tool assemblies during remedial operations. The system uses the patent-pending "self-locating" lateral re-entry technology as an integral component of the Lateral Re-entry Whipstock to assure the proper orientation and elevation of the whipstock tool face with the casing exit window.
The technology described in this paper has bearing on TAML Level II junction re-entry operations for clean out, production enhancement, increased reservoir drainage, zonal isolation, and re-completion of lateral wellbores in multilateral completions. Introduction The Permian Basin is an area where re-entry style horizontal drilling from existing wellbores has been used extensively.
Drilling horizontal laterals from existing wells is more economical than drilling new wells because the costs of drilling and running casing down to the producing formation is eliminated.
Due to reservoir pressure depletion, many re-entry horizontals require the use of artificial lift. In order to maximize drawdown in a pressure-depleted reservoir, the downhole pump should be set below the lateral's window. Consequently, the whipstock used to mill the casing window and drill the horizontal lateral wellbore must be pulled before installing the pump.
The Challenge. Any remedial work to be conducted inside these re-entry horizontals can be a challenge because the drilling whipstock is not in the well to guide the workover string out through the casing window. Therefore, other means of guiding the string out the window must be devised. The most commonly used method locates the window with a "bent sub" on the end of a workstring.
While this is often sufficient, the "bent sub" limits the assemblies that can be passed through the window. Some assemblies e. The operator of the North Indian Basin Unit wanted to sidetrack an open-hole horizontal lateral in order to reach an untapped area in the reservoir.
Lawrence, L. Dubai Petroleum Company Stymiest, J. Sperry-Sun Drilling Services. OnePetro March, Abstract In high angle wells, control of hole inclination becomes the main concern for directional drilling operations rather than azimuth control.
The use of a conventional steerable system to control inclination can introduce such problems as increased torque and drag due to the doglegs created, and poor hole cleaning when in sliding mode. These problems can in turn limit the amount of horizontal section that can be drilled.
Adjustable gauge stabilisers have the ability to alter the gauge of the stabiliser without the requirement to pull out of hole. This type of stabiliser has been commonly used to assist in controlling inclination either in rotary assemblies or in steerable assemblies when run above a motor. Although positioning the adjustable gauge stabiliser above the motor has been successful in many applications, there are situations where an alternative may be required.
With the stabiliser positioned above the motor, it is relatively far from the bit and thus the effects of its gauge change are limited. This in turn results in the changes of inclination possible being relatively small. It may then be impossible to change the wellbore path quickly enough in geological steering applications.
This can be addressed by placing the adjustable gauge stabiliser below the motor, but reliability of both tool and motor suffer. Stresses on the motor bearing assembly can be high enough to cause problems such as premature bearing and drive shaft failures. By placing an adjustable gauge stabilser within the bearing housing of a steerable motor these problems have been overcome. The adjustable gauge stabiliser is therefore in a near-bit position.
This means that changes in its gauge have the maximum effect on inclination. Stresses on the motor are also significantly reduced. This adjustable gauge motor has been run in the Middle-East in long horizontal sections. It was seen to result in significant improvements in overall drilling rates when compared to conventional steerable motor runs.
The subject of this paper is the design and development of the adjustable gauge motor system. Case histories will presented that demonstrate the improved performance that was achieved. Introduction A wide range of drilling tools are now available to drill increasingly complex and expensive well designs. Long lateral horizontal sections can be drilled with anything from a simple rotary assembly to the latest generation rotary steerable systems depending on the complexity of intended well designs.
Generally in high hole angle zones the main objective is to control the wellbore inclination in response to changes in the reservoir geology. However in certain types of reservoir that exhibit lateral variations in porosity and permeability it may be necessary to maintain some sort of ability to control wellbore direction.
Although this can be done with conventional steerable assemblies there may be problems due to the resultant high induced doglegs and poor hole cleaning when drilling in sliding mode.
Therefore some sort of drilling assembly is required that maximises control of inclination in the rotary mode, retains some ability to control azimuth, minimises induced doglegs, yet doesn't require the use of highly expensive 3D rotary steerable systems.
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