Permeability is the cornerstone to any reservoir-flow modeling, leading to field development and production management. Typical sources of permeability include cores, logs, wireline formation tests or mini-DSTs, and conventional drill-stem tests or DSTs., Integrating various sources of permeability at different scales is problematic. Anchored in mini-DST-derived permeability, this study endeavors to integrate various sources of permeability, leading to reservoir description in a trubidite sandstone reservoir in the Sabah Basin, Malaysia.Pressure-transient test data recorded during a mini-DST operation differ significantly from those gathered during a conventional DST. In the case of this well, although the test quality is excellent, interpretation challenges are numerous. The paper llustrates the planning and integration of Mini-DST data with multidisciplinary information from side-wall cores, MDT, NMR, and FMI image logs. This case study demonstrates that, in this particular setting, the use of mini-DSTs was cost-effective and yielded the necessary subsurface information required to plan field development options.
TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractDownhole sampling in gas condensate reservoir is well known to be challenging due to the nature of near critical fluids. Reservoir fluid properties can change dramatically with slight changes in reservoir pressure and temperature. As a result, accurate and representative PVT data are essential for reservoir fluid modeling and field development planning but difficult to obtain using conventional sampling techniques. This paper presents the first successful downhole gas condensate sampling in a high pressure gas condensate field, offshore East Malaysia. Samples collected from the previous surface tests showed large variation in Condensate Gas Ratio (CGR) from 50 to 200 stb/mmscf. This resulted in large uncertainty in the dew point pressure, condensate yield, well productivity, and reservoir fluid type. There was strong need to acquire high quality downhole samples to reduce these uncertainties, which can potentially affect the entire field development plan. Through the use of new technology and an integrated team approach, it was possible to take representative single phase fluid sample using controlled drawdown and real time fluid analysis of downhole sample.There were several key challenges in this operation. The team had to take single phase gas sample, with minimum contamination in a High pressure High temperature (HPHT) well drilled with Oil Based Mud (OBM), station time had to be as short as possible to avoid tool getting stuck, and have an initial estimate of dew point pressure and Gas Oil ratio (GOR) from downhole measurements. This was achieved using real time data monitoring and control of the entire wellsite operation from PETRONAS Carigali office. The latest downhole fluid identification tool was used along with focused sampling to minimize OBM contamination. This paper will highlight the effective use of various elements of new technology and team work.Fluid density measurement was found useful in answering some of the questions. It allowed comparison with optical fluid analyzer to provide an improved fluid identification. It also allowed to optimize the number of pretests and hence reduce the rig time and cost. By measuring the change in fluid density during clean up, the in-situ density tool also complemented other spectrometer based optical analyzers in determining the contamination level during sampling process.In this complex gas reservoir, there were potential reservoir compartments of different gas composition. Fluid samples from different zones confirmed the presence of such compartmentalization. The deeper zones showed much leaner gas composition compared to the shallower intervals. The knowledge of in-situ dew point pressure from downhole fluid analyzer was used to ensure a single phase gas sample during wireline sampling. This information was later used to design a well test to keep flowing bottom hole pressure above dew point pressure and thus obtain representative surface fluid samples. This paper demonstrates how a proper job planning, r...
Summary Permeability is the cornerstone of any reservoir-flow modeling that leads to field development and production management. Typical sources of permeability include cores, logs, wireline formation tests [or minidrillstem tests (mini-DSTs)], and conventional DSTs. However, integrating various sources of permeability at different scales is problematic. Anchored in mini-DST-derived permeability, this study endeavors to integrate various sources of permeability, leading to reservoir description in a turbidite sandstone reservoir in the Sabah basin, Malaysia. Ordinarily, pressure-transient-test data recorded during a mini-DST operation differ significantly from data gathered during a conventional DST. Even though test quality was excellent, interpretation challenges were numerous in this well. Consequently, multidisciplinary information was brought to bear for integration of data derived from mini-DSTs. Other sources of information included sidewall cores, spot pressure measurements, nuclear magnetic resonance (NMR), and microelectrical imaging logs. This case study demonstrates that, in this particular setting, the use of mini-DSTs was cost-effective and yielded the subsurface information required to plan field-development options.
Large uncertainties in structure and facies had been recognized in a major gas field in Pakistan after early production. The conventional reserve estimation methods had failed in providing a reliable estimate of gas-in-place (GIIP). It was possible to get a good history match of one-year production data using a wide range of GIIP through a slight and acceptable adjustment of porosity and permeability. The resulting possible range of GIIP could easily vary by a factor of 1.5. Structural uncertainties did not warrant volumetric estimates either. Material balance technique was questionable due to non-uniform drainage of the reservoir. Clearly these deterministic techniques of reserve estimation were not applicable at this stage of production considering the complexities of the reservoir. A probabilistic technique was therefore developed that addressed both static and dynamic uncertainties in an integrated approach while honoring the available production history. Combined treatment of static and dynamic uncertainties also ensured a better coverage of the entire sample space, thus making the probabilistic approach more reliable. Latin Hypercube Sampling (LHS) helped minimizing the number of simulation runs while providing a reasonable coverage of the sample space. Yet we ended up with almost 1500 simulation runs. The process of history matching, ranking and keeping track of all these simulation runs demanded an innovative workflow. A number of software tools were used to automate and optimize this process. Out of 1500 simulation runs, the 200 best runs having minimum objective function through history matching were selected. These runs were later used for production forecasting, for providing a range of reserves, and for sensitivity analysis to identify the most influential variables. Structure and NTG were identified as the two most critical variables for *GIIP while residual gas saturation was identified as an additional sensitive variable for reserves. Different geostatistical realizations had little impact on GIIP or reserves.
Conventional production logs; spinner, density, capacitance, temperature, and pressure are routinely used in the Gulf of Suez (GOS) wells for reservoir monitoring and diagnosing production problems. These logs can adequately determine flow profile of fluids inside vertical or moderately deviated holes. However, these were found unsuitable for more complex problems including the following,–Identification of water entries or exits in horizontal wells.–Water flow behind casing in cement channels or behind tubing in dual completion systems. Oxygen activation technique (or Water Flow Log, WFL), was successfully used to diagnose these problems. Subsequent workovers resulted in significant production increase, confirming the answers obtained from these surveys. Unlike some other tools, oxygen activation log is immune to well deviation. It therefore works equally well in vertical or deviated holes. It further reacts to flowing water only. Thus standing water or any non-water fluids are simply neglected by this measurement. Being a nuclear technique its depth of investigation extends behind the pipe. This property allows us to monitor water movement in cement channels or behind tubing in dual completion injectors. This paper explains the principal of oxygen activation log and shows its two important applications. Introduction In traditional production logging, spinner flow-meter measures the average fluid velocity of all phases. This is combined with a holdup measurement, such as density, to determine velocity of each phase. Frequently we come across situations where this procedure cannot be used,The measurement sensors in conventional measurements must be in direct contact with the fluid to be monitored. This is not possible when we want to monitor water movement behind casing, e.g., in cement channels (Fig. 1) or in dual completion wells (Fig. 7).In deviated wells, the spinner is often biased towards the fluid flowing on the low side of the hole. The fluid velocity of this heavy fluid is less than the average fluid velocity in the bore-hole. In extreme cases this fluid can be stagnant or flowing in opposite direction to normal flow. In most of the cases, the spinner will underestimate the fluid velocity in high deviation or horizontal wells.Since the slippage velocity curves cannot be used in horizontal wells, a direct measurement of phase velocity and holdup is needed to solve such multiphase flow problem. This has been the subject of a number of papers presented in the recent past (Ref. 1–4). A special set of tools have been developed to address these needs. This, however, is not the subject of this paper. In GOS wells, we faced the first two limitations of conventional log that were adequately solved with WFL. While oxygen activation log was used standalone in the examples presented in this paper. It is also being used in conjunction with other measurements to solve multi-phase flow problems in horizontal wells. Principle of oxygen activation log The physics of oxygen activation measurement is described in Fig. 2. This measurement is made with a pulse neutron tool by making a series of 2 or 10 second neutron bursts. Some water in the vicinity of minitron is activated every time the neutron burst is made. The activated water is detected by -detectors placed at 1 ft, 2 ft or 15 ft depending on the velocity of water. The travel time of activated water from minitron to the detectors provides water velocity knowing the space between minitron and -detectors. The oxygen in water is activated after absorbing a neutron emitted from the minitron of the pulsed neutron tool. The activated oxygen returns to its stable state by emitting a -ray. The half life of this reaction is about 7.1 seconds. Slow moving water may not be detected by -detectors at 15 ft as most of the water would deactivate before reaching there. The slow moving water is instead detected by -detectors present at 1 ft or 2 ft. Thus by using three different detectors a range of water velocities can be covered. P. 493^
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