This paper was prepared for presentation at the 8th Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, U.A.E., 11-14 October 1998.

This paper presents case histories of horizontal wells transient pressure test interpretations conducted in a carbonate reservoir. The development of non-conventional techniques for interpreting some short-time horizontal well test pressure responses are presented.Horizontal well trajectories as well as fluid flow dynamics can introduce complexities into the horizontal well test pressure response data. In many of such cases, horizontal well tests are not amenable to analysis using conventional methods of well test interpretations. However, for those wells where the early radial and the early linear flow regimes are observed, a test interpretation method developed as 'The Gradient Intercept Method' could be used to implement complete test interpretation satisfactorily. The method precludes the need for the development of late radial flow regime, and consequently, the long shut-in time generally associated with horizontal well testing and the attendant loss of oil production can be averted. A numerical model with PEBI grids is also constructed using a well test simulator to confirm the results obtained from oradient . bIntercept method. 745For cases where the primary objective of a well test program is the assessment of wellbore skin effect, the Short Time Skin Test (STST) is introduced. The STST is essentially a wellbore monitoring technique used in a time-lapse fashion to evaluate wellbore damage. Both the Gradient Intercept and the STST methods are illustrated with field examples to demonstrate their applicability.

Production of high salinity formation water with gas presents major operational and reservoir management challenges in gas reservoirs. Early detection of unexpected water production is critical for ensuring prompt action to prevent accelerated corrosion damage in surface pipelines and facilities if they are not designed to handle the produced brine. Several methods exist for detecting water in pipelines which are based on electrical, electromagnetic, and acoustic measurements. While most of the existing methods are intrusive requiring direct contact between the measurement probe and the flow stream, all such methods suffer from low accuracy of measurements and dependence on water composition and salinity. This paper reviews the various technologies that are in use to detect and measure water production. It also describes the theoretical background and the laboratory testing of a new means for detecting presence of formation water in gas flow lines.1–10 This work is part of a joint collaboration between RasGas Company Limited and Texas A&M University at Qatar (TAMUQ) aimed at developing a device which is: non-intrusive, clamp-on externally on the flow-line, accurate, and independent of saline water composition. This technology is based on neutron elastic-scattering and activation interactions. The laboratory testing is performed using simulated field conditions to determine the feasibility and accuracy of the measurement technique. Based on the laboratory results, a prototype device is planned to be constructed for field testing. Safety aspects of the process application both in the lab and in the field have been thoroughly examined and comprehensive safety measures have been developed and implemented per the health and safety regulatory requirements. The paper also presents the findings from a simulation study using the Monte Carlo N-Particle (MCNP5) neutron flux simulator11 to examine the feasibility of the proposed method and to properly design and optimize the experimental setup and procedure. Introduction Produced fluid in gas fields consists, generally, of gas, condensate, and condensed (zero salinity) water. As production progresses, formation saline water (brine) can be produced with the condensed water. This can affect the operation and safety of the production system by accelerating corrosion and scaling potential, especially in the presence of acidic gases such as CO2 and H2S and the inorganic salts dissolved in the brine. Brine can also lead to emulsion and bacteria related problems. Therefore, it is very important to detect the presence of formation brine in the system as soon as it starts to be produced.

In this study, a mathematical model was developed to present pulse and interference testing for multilayered reservoirs. It was found that apparent storage calculated from pulse testing data is always less than or equal to the actual storage of the reservoir and that apparent transmissibility is always greater than or equal to the actual transmissibility. For short cycle intervals, the fractional production rate from a particular layer is not proportional to its transmissibility fraction. The effect of storage variation on fractional production rate is negligible. Wellbore damage affects both apparent transmissibility and storage. Less accurate estimation reservoir characteristics is obtained using pulse-test data as the contrast in reservoir properties increases and vice versa. A new approach is suggested to use data of single well test as well pulse test to estimate properties of individual layers. The approach is demonstrated by a three-layer numerical example.

In the present paper, we introduce an algorithm to classify Hickson's compact groups of galaxies. The algorithm uses the discrimination analysis technique to determine the best set of indicators that can be used to construct the models in which the classification validity of the Hickson's compact groups could be predicted, and thus distinguish between groups that have classification problems. We have concluded that the earlier classifications of the 92 Hickson's compact groups of galaxies are correct.