TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWell testing is important for reservoir formation and fluid characterisation. Well testing is, however, omitted in many instances due to the high cost, risks and environmental restrictions associated with a well test. The Downhole Production Testing (DPT) method 1 will have a significant impact on safety, environment and cost aspects compared to conventional production testing or drill stem testing (DST).The Downhole Production Test method allows all the produced reservoir test fluid to be re-injected into another zone within the well bore while flow rate, pressure and temperature data are monitored and controlled from surface. In situ fluid samples are taken during the flow period. After penetration of a zone of interest, an injection zone is selected at a depth which allows a sufficient injection rate. The drilling fluid acts as the primary pressure barrier during the test. The production and injection zones are isolated from the drilling fluid by a packer arrangement.No fluid flows to surface during the test, so the entire surface processing equipment normally associated with well testing is no longer required. This significantly reduces the onshore and offshore logistics operation. Even more important is that hydrocarbons will not flow to surface under high pressure during the test. This significantly improves the risk and safety aspects of conducting a well test. High-risk operations in deep water related to discharge during emergency disconnect or hydrate formation during testing are also eliminated.A "zero emission" goal is achieved by no burning and no hydrocarbon flows to surface. This paper describes the method and the environmental implications of this new testing method. Included also is a detailed discussion of the safety and risk elements involved in different operating scenarios. Furthermore, this paper discusses some of the preliminary design parameters and possible implementation of the concept. It describes potential cost benefits for various applications and demonstrates that this new technology reduces cost and improves the environment, safety and risk while allowing test objectives to be met.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWellbore position calculations are typically performed by measuring Azimuth and Inclination at 10 -
The drilling of horizontal and extended reach wellbores is being revolutionized by rotary steerable systems such as the AutoTrak™ tool. Typically, advanced directional drilling has been performed with steerable mud-motor systems. However, drilling with a steerable mud-motor results in a rough and tortuous wellbore due to the motor's geometry and operational behavior. A rough wellbore may affect the performance of various logging sensors deployed with the system. Different logging sensors are affected differently, and so the ability to compensate for borehole effects varies from sensor to sensor. The result may be a log that suffers in quality. Rotary steerable systems drill smoother and less tortuous wellbores. As a consequence, typical borehole effects visible on various FE logs may not be apparent when drilling with rotary steerable systems. Knowledge of the logging environment in which the data were obtained is important when analyzing the log. It is believed that the introduction of rotary steerable systems will improve the economics of long horizontal and extended reach wells. As a consequence, there will be an increase in the drilling of these types of wells. It is desirable to log these wells while drilling, as the deployment of wireline-operated logging tools will be costly and risky. The real-time logging information can be used for navigating in the reservoir and optimizing the wellbore position. Also, FE-MWD logging sensors are continuously being developed and improved, so the desire to perform the logging operations while drilling will tend to increase. This paper discusses the differences in logging environment as a result of drilling with a rotary steerable system as opposed to a steerable motor system. The paper also discusses the impact of this new logging environment on the results from various FE-MWD logging sensors. Examples of logs recorded in comparable formations with the two drilling systems are included. This may help log analysts in their interpretation of log results, as rotary steerable systems are more commonly used for horizontal and extended reach drilling (ERD).
Wellbore position calculations are typically performed by measuring Azimuth and Inclination at 10 - 30 m intervals and using interpolation techniques to determine the borehole position between the survey stations. Input parameters are, Measured Depth (MD), Azimuth and Inclination, where the latter two parameters are measured with the MWD tool in a stationary mode (non-rotating). Output parameters are the geometric coordinates; True Vertical Depth (TVD), North and East. To maximize the exposure of a production well to the reservoir, horizontal wellbores are frequently being drilled. Furthermore, to maximize the production of hydrocarbons from these wells, their relative position within the reservoir is critical. Improving the accuracy of the Inclination measurement and thus reducing the uncertainty of the calculated TVD value will increase the confidence in wellbore position. The NaviGator ™ ∗ geosteering tool or the AutoTrak ™ ∗ rotary steerable system are frequently used to optimize the position of horizontal wellbores within the reservoir. Both these geosteering tools use a Near Bit Inclination sensor (NBI) to help the directional driller perform directional changes smoothly and accurately. Unlike traditional directional sensors the NBI sensor is capable of accurately measuring inclination while being rotated. Consequently NBI measurements can be performed continuously during drilling. The measurements can be used to more accurately calculate the wellbore trajectory. Results in the paper demonstrate that the NBI sensor is more accurately measuring inclination than other directional sensors in a horizontal well. Also, by continuously measuring the inclination during rotation, some error sources are reduced, resulting in improved TVD accuracy. Introduction The most common directional module of a Measurement While Drilling (MWD) tool (Figure 1) consists of three uni-axial accelerometers and a tri-axial magnetometers. The axes are orthogonal with respect to one another and are capable of resolving the measured local fields into three dimensional components. The directional module of an MWD tool is located within the MWD collar itself and is typically found between 15 – 20 m behind the drill-bit, depending on the design of the Bottom Hole Assembly (BHA). Due to the geometry of the BHA and the drilling parameters, the MWD collar can be exposed to a bending effect causing the directional sensor package not to be parallel to the axis of the borehole. The effect of the BHA bend on the accelerometers/inclination measurement can be predicted and more or less compensated for. The unfavorable distance between the bit and the directional sensor has led to the development of near-bit survey sensors to enable rapid responses to inclination changes while drilling. FIGURE 1: Directional MWD. (Available in full paper) FIGURE 2: NaviGator. (Available in full paper) FIGURE 3: AutoTrak. (Available in full paper) Geosteering tools such as Baker Hughes INTEQ's Reservoir Navigation Tool (RNT) NaviGator and Rotary Closed Loop System (RCLS) AutoTrak employ near-bit inclination sensors. These sensors are typically located 1 – 4 m behind the bit and provide accurate near-bit inclination measurements in addition to the data from the directional module located further back in the BHA. The NaviGator (Figure 2) is a combination of a steerable mud motor with the following MWD sensors; azimuthal gamma ray, multiple propagation resistivity and inclination.
A large percentage of boreholes drilled in the Mahakam delta area in East Kalimantan are adverselyaffected by tectonic stress. Stress imbalance in the borehole results in enlarged and elongated holes and borehole breakouts in the shales. Pad type logging devices are seriously affected by such borehole conditions. The use of a short axis logging kit enables good logging data to be acqUired in such boreholes. The stress imbalance can be minimized. by optimizing mud weights used in drilling, through estimations ofin-situ stress and mechanical properties obtained from shear sonic logging data.
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