Since the cost of developing a single offshore oil field usually runs in the tens of millions of dollars, savings due to better development policies could be quite significant. This paper presents a general model for developing offshore fields at minimum cost. The model applies to any field developed from fixed platforms, and thus could also be used directly for the development of fields on the north slope of Alaska. The basic limitations and possible utility of the model are discussed. The mathematical programming formulation of the problem is shown to be identical in general structure to the well-known warehouse location problem. Algorithms for solving the problem are developed, whereby the algorithm for a particular problem will depend upon the general form of the platform cost function. The algorithms developed are tested and shown to be computationally practical.

Understanding the behavior of the drill bit, bottomhole assembly (BHA), and drillstring in drilling operations is difficult without accurate measurements of tensile load, torque, pressure, and various vibrations both at surface and downhole. A variety of methods have been employed to compress measurements obtained downhole in order to transmit them to the surface with measurement-while-drilling (MWD) mud-pulse telemetry. During the last ten years, some success has been achieved in making these measurements, recording them, and then retrieving the data at surface upon the end of the bit run. Meanwhile, the comparable measurements at surface have limitations in terms of accuracy, calibration, and dampening.An instrumented surface sub (ISS) has been developed that replaces the saver sub at the bottom of the top drive on a rig's traveling assembly. It measures in real time at the top of the drillstring, using accurate and calibrated sensors, tension/compression, torque, rotational speed in revolutions per minute (RPM), and surface pump pressure, among other parameters. These measurements, made at 400 Hz, are not dampened by the drill line and sheaves. A drilling mechanics module (DMM) sub that is part of the BHA has also been developed, which provides downhole measurements including, but not limited to, tension, torque, RPM, internal and annular pressure, at frequencies between 200 and 2,000 Hz. Additionally, along-string vibration measurements are provided using memory only devices.To evaluate both of these downhole and surface drilling data acquisition tools, a test was conducted in June 2010 at the Schlumberger directional drilling test facility near Cameron, Texas. Four different BHAs were run to evaluate downhole behavior and collect data using milled-tooth and PDC bits while directional drilling in surface rotary mode as well as with steerable motors. This paper presents some of the wide-range findings regarding the use and analysis of the data gathered in terms of static drilling mechanics, as well as dynamic drillstring behaviors and downhole vibrations. IntroductionDrilling operations have historically monitored surface drilling data as a tool to make the necessary adjustments in a drilling activity to maximize performance. The basic measurements are torque, tension or hookload, mud pressure, flow rates, and rotational speed (RPMs). The frequencies at which these data sets are gathered range from 1 to 15 Hz. Modern drilling rigs utilize sensor data obtained using technologies that are hydraulic-based, electronic-based, or a combination of both. The data may be displayed on a simple hydraulic gauge, or conversely, viewed on an electronic human-machine interface (HMI) display. The same measurements are made downhole, but the frequency of the data gathered is limited by bandwidth in mudpulse telemetry. Generally, large quantities of higher frequency data can be post-processed only after the BHA has been brought back to the surface. Experience has shown that data of higher accuracy and frequency is needed to dia...

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPredicting the directional tendency of a bottomhole assembly (BHA) is a key element in improving the efficiency of the directional drilling process. Finite element models attempt to represent the detailed physical interactions between the BHA and wellbore while drilling. However, effective use of such models has been hindered by parameters that are difficult to quantify, particularly the strength of the formation and variations in hole gauge.Details of over 6400 BHA runs made in the Gulf of Mexico from 1994 through 1997 were used in a systematic statistical analysis and combined with intelligent use of the tendency models to yield information that is not readily apparent in single runs of the software. This information can then be used as a predictive tool to minimize the effects of the parameter uncertainties, and to isolate and calibrate those variables to which the models are sensitive. From these studies the most representative values for formation stiffness and hole over-gauge were obtained for various areas within the Gulf region.We describe a methodology using this combination of advanced modeling and statistical analysis to provide more reliable predictions of BHA tendency and to give an indication of the conditions where such predictive techniques can be effectively applied.

fax 01-972-952-9435. 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.