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One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.
ABSTRACT Years and years of huge hydrocarbon exploitation from a giant field results in a not efficient production optimization strategy due to the high uncertainty in current reservoir fluid distribution. This scenario can be even more challenging in case of old and complex well completions and areal field compartmentalization. This paper discusses design, interpretation workflow and results of a massive cased-hole pulsed neutron campaign performed in such conditions. The outcomes have driven several targeted well interventions for additional hydrocarbon production. The presented case study deals with extensive pulsed neutron use in a reservoir characterized by more than three thousand meters of gas, oil and water bearing terrigenous sequence. An integrated capture (sigma mode) and inelastic (carbon/oxygen mode) approach overcomes the criticality of a strong changing in formation water salinity (one order of magnitude from hundreds to tens ppk). Small tubing in large casing environments, long perforated sections, different fluids in completion make the interpretation even more complicated. The available open-hole formation evaluation represents the input for the pulsed neutron modeling while a standalone cased-hole formation evaluation has been deployed in the oldest wells characterized by a limited open-hole log dataset. Actual water saturation and hydrocarbon type from the described approach have been used for water shut-off interventions and new perforations in front of bypassed oil bearing levels avoiding undesired gas production. The aforementioned production optimization activities for all the analyzed and treated wells resulted in an overall increase in oil rate of about 650% and a watercut reduction of about 40% respect to the previous performances. INTRODUCTION The onshore field described in this paper (from now on called Alpha) is characterized by a Plio-Pleistocene clastic sequence and by a complex structural setting. The main reservoir is represented by a terrigenous series, including more than three thousand meters of gas, oil and water bearing of sandstones. Alpha is densely populated with many explorative, appraisal and development wells. It was put on production almost four decades ago, and it is still producing from several reservoir layers. Faulting plays a key role in the trapping mechanism, with many of the faults sealing thick sand units. It is also known that there is an element of stratigraphic trapping to some reservoirs. Hence, the presence of an intricate fault framework (see Figure 1) has strongly influenced the reservoir performance in terms of oil, gas and water production.
Abstract In the Mahakam delta in East Kalimantan, TotalFinaElf E&P Indonésieoperates fields with numerous multi-layer reservoirs deposited within a deltaicenvironment. Formation waters in these reservoirs have very low salinities, which vary with depth and from reservoir to reservoir. When a field is inproduction, the evaluation and update of initial hydrocarbon net-pay is mademore difficult by depletion and fluid level changes, which are related tochannel reservoirs connectivity, both laterally and vertically. A new methodhas been developed, based on acoustic measurements, to help identify theoriginal gas net-pay. This method uses the fact that compressional acoustic waves travel slower ingas than in liquid whereas shear waves are not affected by fluids in the porespace. An empirical correlation is established between Vp/Vs ratio and shearslowness in known liquid-bearing sands. This correlation is used to predictVp/Vs over the whole logged interval. A large difference between predicted andmeasured Vp/Vs indicates the presence of gas. Since gas is very compressible, the effect is noticeable even at very low gas saturations, i.e., in gasreservoirs that have already been depleted, or even swept by water. The method was first tried in a mature oil field in order to distinguish gasfrom liquid and gave encouraging results. It was then applied in a gas fieldwhere a 3000-meter interval of dipole sonic log had been recorded in one well. Fluid status identified by this method was crosschecked against all other data(wireline logs, mud logs, wireline fluid samples) and against the geologicalmodel. The results helped confirm (or revise) the model, which, in turn, improves mapping, material balance calculations and optimization ofproduction. Based on numerous examples, the conclusion is that very good results areobtained in clean sands, especially where known water and gas bearing intervalsare available for calibration. The article also states the limitations of themethod, which can give ambiguous results in very shaly reservoirs and alsofails in deep reservoirs where porosity falls significantly below 15percent. Introduction In the Mahakam delta in East Kalimantan, several oil and gas fields werediscovered and are being developed, which contain numerous reservoirs depositedwithin a deltaic environment. Due to the complexity of such geologicalenvironment and the large number of reservoirs, the geological modeling is atricky process. When a field is in production, the evaluation and update ofinitial hydrocarbon in place is made more difficult by depletion and fluidlevel changes in wells and reservoirs, also in relation with complex reservoirgeometry and connectivity, both laterally and vertically. For each new infillwell the identification of the fluid status of each individual reservoir is ofprime importance for both initial static volumetrics review and reservoirproduction policy. Additionally, since formation waters in these reservoirshave varying salinities, which change with depth and from reservoir toreservoir, the definition of current fluid status is difficult. As aconsequence of all these factors the correlation and mapping process is evenmore complex and requires several levels of data integration. First, all geological and log data are integrated in order to provide ageological model, leading to volumetric estimation. The last stage ofintegration is the validation, with pressure and production data throughmaterial balance and/or reservoir simulation models (see Moge and Febvre,2001). Since in the present context commingled production in wells is common, production allocations are less accurate, and, even if the knowledge of thefield is improved with such an integrated process, uncertainty remains withinthe model. Therefore, any new data or method to better evaluate the status ofreservoir fluids - be it the initial or the current status - is useful tobetter position infill wells and manage a more efficient reservoir productionpolicy. Amongst many available tools, a new method has been developed, based onacoustic measurements, to help identify the original gas net-pay, to becompared with the current fluid status in the reservoir and help in the fieldreview.
Summary Geostatistics techniques are being used increasingly to model reservoir heterogeneity at a wide range of scales. A variety of techniques are now available which differ in their underlying assumptions, complexity and applications. This paper introduces a novel methodology of geostatistics to model dynamic gas-oil contacts and shales in the Prudhoe Bay reservoir. The proposed methodology integrates the reservoir description and surveillance data within the same geostatistical framework. The methodology transforms surveillance logs and shale data to indicator variables. These variables are then utilized to analyze the vertical and horizontal spatial correlation and cross-correlation of gas and shale at different times and to develop variogram models. Conditional simulation methods are used to generate three-dimensional distributions of gas and shales in the reservoir. Both methods provide a measure of uncertainty in the resulting descriptions. These conditional simulation methods capture the complex three-dimensional distribution of gas-oil contacts through time. The results of the geostatistical methodology are compared with conventional techniques as well as with the infill wells drilled after the study. The predicted gas-oil contacts and shale distributions are in close agreement with the gas-oil contacts observed at the infill wells. Introduction Geostatistical techniques provide a framework to integrate and model several sources of reservoir data at different scales. With the recent development of high-speed and large-memory computer workstations, geostatistics has become a powerful tool for detailed reservoir analysis, description and evaluation. These technologies make it possible to integrate geological, geophysical and petrophysical data for building more realistic reservoir models. In the Prudhoe Bay field, reservoir description and monitoring fluids in- place through time are the key elements for field development, reservoir management, and predicting performance for different reservoir mechanisms. The stakes include reduction of gas and water handling costs, selection of completion and recompletion intervals, selection of better infill well locations, development of better reservoir simulation models and reduction of the effort required for fluid mapping. Prudhoe Bay is the largest field in North America. During the 16 years of operations, the field has produced more than 7 billion barrels of oil. The major producing mechanisms in Prudhoe Bay are gravity drainage, waterflood and miscible gas flood. The interactions between these mechanisms, the reservoir architecture and heterogeneities (shales, faults and fractures of different shapes and sizes) result in complex gas and water movement through time. Fig. 1 illustrates the gas movement in a cross-section along the main dip direction in a gravity drainage region of the reservoir. Gas movement is affected significantly by shales of varying sizes which may not be continuous between wells. The gas tends to move underneath the shales resulting in isolated gas tongues or fingers which breakthrough at different times at the wells (gas underruns) and oil regions which are bypassed (oil lenses). For a given well, the cased-hole logs at different times show multiple gas-oil contacts (Fig. 1). Under these conditions, it is difficult to interpret and visualize the inter-well distribution of gas in three-dimensions.
Sands in the Morrow formation in the Anadarko basin vary in local properties, significantly affecting is in itself a gas indicator, and that is why it is multiplied by the expected AVO response observed on seismic data. The the estimated to produce a combination gas indicator in reflection from the top of gas-charged Woodbine sands shows low-impedance sands. In high-impedance sands, the presence of gas has a much smaller effect on Vp, and thus, high values a strong gas effect that is observed at four well locations along a seismic line. Aspects of rock properties as they relate to AV0 for the NI reflection coefficients are no longer a gas indicator.
More information about formation properties than is commonly utilized is available in the acoustic signal. The objective of full-wave acoustic logging is to use more of this information to determine formation properties. properties. Full-wave acoustic tools generally have transmitter-to-receiver spacings greater than about eight feet. This provides deeper penetration and facilitates signal analysis. Full-wave acoustic signals are briefly discussed.
Shear wave slowness, or is one of the most important new acoustic logging measurements. Used with , provides basic log quantities for lithology identification, gas zone identification, estimation of lithology and porosity with acoustic logs only, and improved formation elastic property estimation. property estimation
More information about formation properties than is commonly utilized is available in the acoustic signal propagated down a borehole. In fact, present logs, the most common open hole acoustic logs, represent only a present logs, the most common open hole acoustic logs, represent only a small fraction of the potential information in the acoustic signal. The objective of full-wave acoustic logging is to use more of the information to determine formation properties. Such properties include , , / , lithology, rock elastic moduli, compressional and shear attenuation and reflection coefficients.
Shear wave slowness, or , is one of the most important of the new logging measurements provided by the analysis of full-wave acoustic signals. The main objective of this paper is to present several examples of the use of shear and compressional wave slowness logs. Characteristics of full-wave acoustic signals are briefly discussed for background.
FULL-WAVE ACOUSTIC SIGNALS
The full-wove acoustic signal is composed of four main types of waves: compressional, shear, pseudo-Rayleigh and Stoneley. Compressional and shear waves are often referred to as P and S waves respectively.
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