In reservoir surveillance, gas saturation is routinely monitored both in gas reservoirs for reservoir performance and in saturated oil reservoirs to prevent gas coning or to optimize infill drilling well placement. This paper presents a new pulsed neutron technology and method that enable the quantitative monitoring of the gas saturation variations to address these reservoir management issues. One of the key features of the newly designed pulsed neutron tool is the new type of Lanthanum Bromide (LaBr3) detectors. The extra-long spacing of the far detectors provides a larger volume of investigation that is more representative of the actual reservoir condition. The quantitative aspect of the measurement is achieved by using the ratios of the detector counts, so that the rock matrix effects are diminished, as opposed to the traditional sigma measurement, which can be influenced significantly by the rock matrix properties. This new tool and data interpretation methodology have been tested in both clastic and carbonate reservoirs with encouraging results. This paper presents an overview of the technology and some field application examples.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents new hardware and analytical methods for determining formation gas saturation behind casing using pulsed neutron instruments. Instrumentation, characterization, algorithms, and limitations are discussed, and log examples are presented that illustrate the application of the methods in limestone and sand/shale formations.

Horizontal wells in ChevronTexaco's Captain Field in the North Sea typically exhibit low temperature and pressure in the produced intervals with highly viscous heavy oil production in 2 and 3-phase flow. The highly viscous oil (88 to 135 cp) has historically presented difficult conditions for most horizontal production logging instrumentation due to the tendency for plugging and coating of sensors. The wells are also screened completions which makes logging and interpretation more complex. Production profiles in three of the Captain Field screened horizontal wells were recently determined utilising an advanced horizontal production logging system. The system combines 2-dimensional parallel-plate capacitance array measurements of 3-phase holdup and velocity profiles, pulsed neutron measurements of 3-phase holdup and water velocity, and conventional production logging measurements to determine the production profile.This paper presents the results of the logging campaign, including several interesting observations relating to production and measurement in the profiles under flowing conditions (and shut-in, with cross-flow).Atypical velocity profiles due to the presence of heavy, highly-viscous oil.Observation of annular flow regime, or "core flow", where oil flow is surrounded by an annular layer of water.Effects due to flow through the gravel pack and the need for both capacitance and pulsed neutron measurements.The importance of simultaneous measurement of holdups and velocities across-the-wellbore for accurate flow rate determination. Introduction In simplest terms, flow profiling in a horizontal well bore requires identifying the cross-sectional area fraction of each phase present, or holdup, and quantifying the velocity associated with each phase. Flowrates are then obtained based on the velocities, hold-ups, and associated flow path geometry. In practice the situation is invariably more complicated than this simple ideal. Obtaining an accurate holdup for each phase in "normal" light oils is generally a challenge, but one which has been addressed. Various technologies have been developed that can provide reasonable holdup data in favourable conditions. Phase velocity determination on the other hand has been rather less well provided for than holdup determination. Various instruments are available which can provide partial answers that are then augmented by modelling to generate a velocity profile. Historically, however, none of these have been capable of generating a result over a sufficiently wide range of flow regimes. To circumvent this limitation various combinations of instruments have been generally operated such that data coverage along the well bore can be maximised. A tough challenge, but one which has historically been met under some of the simpler flow conditions which exist. In the case of the Captain Field this task is further complicated by the high viscosity of the oil (88–135 cp) and the low reservoir temperature. In addition the pressure in some wells is below the bubble point resulting in the presence of three phase flow conditions. This combination of conditions presents a difficult challenge for earlier-generation horizontal logging instruments and has historically resulted in coating and subsequent blinding of some types of holdup sensors, in particular, probe-type measurements. The perforamance of the standard spinner flowmeter measurement can likewise be severely degraded in this environment.

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This paper presents new hardware and analytical methods for determining formation gas saturation behind casing using pulsed neutron instruments. Instrumentation, characterization, algorithms, and limitations are discussed, and log examples are presented that illustrate the application of the methods in limestone and sand/shale formations. Introduction While pulsed neutron measurements have been used successfully for almost three decades to identify gas behind casing, the traditional analysis methods are not as quantitative, nor as transparent, as one would prefer. This paper discusses a new technique for formation gas measurements using pulsed neutron instruments, including the behind casing measurement of formation gas saturation. The technique, referred to as GasViewSM, is based on the confluence of three new technologies---new instrumentation, new response characterization, and a new gas saturation analysis algorithm. Instrumentation The downhole instrumentation employed is a modification of the Reservoir Performance Monitor (RPMSM). The original RPM instrument, designated the RPM-A, consists of a deuterium-tritium pulsed neutron source and three gamma ray detectors. The first two detectors (designated D1, short-space and D2, long-space) are used for traditional neutron capture and carbon-oxygen measurements, and the third, the D3 or extra-long-space detector, was located outside the practical detection field of the inelastic and capture gamma rays and was used for activation water flow measurements. The new instrument, designated the RPM-C, moves the D3 detector nearer the source so that it detects both capture and inelastic gamma rays. In the RPM-C the spacing of the two nearer detectors (D1 and D2) is unchanged from the original design of the RPM-A as described in Gilchrist, et al.(1) New methods for activation water flow measurements that compensate for the movement of D3 closer to the source will be reported separately. The presence of formation gas is identified by observing the behavior of the ratio of the inelastic or capture gamma ray count rates, called RIN and RATO, respectively. Intuitively, one can sense that the removal of the fluid from the porosity results in greater neutron transport. This is the principle involved in the radiation shielding of high energy neutron sources in the laboratory with water tanks. This greater transport will be reflected in the count rates in different detectors. When the liquid is removed from the porosity and replaced by gas the near detector count rate will increase, but due to the increased neutron-gamma transport, the count rate in the farther detectors will increase more, producing a decrease in the count rate ratio of the two detectors. Both neutron and gamma transport are involved in the measurement of gamma rays by the instrument, and both processes may be accounted for in Monte Carlo modeling. Fig. 1 shows the behavior of the three inelastic count rate ratios (RIN12, RIN23, and RIN13) corresponding to the ratios available from three detectors, D1/D2, D2/D3, and D1/D3. The abscissa is the effective porosity of the sand formation and the ordinate is the gas response, defined as the 100% liquid-filled-porosity response minus the 100% gas-filled-porosity response, with the difference quantity normalized to the gas-filled value, i.e., the fractional change in the ratio that would be expected to occur as gas-filled porosity becomes liquid-filled. It is seen in Fig. 1 that the gas response is positive, indicating that the ratios shown decrease as the porosity is changed from liquid to gas, as the farther detectors register a greater increase in counts than the nearer detectors.