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Abstract Due to the volumetric nature of the physics and the measurement, traditional gamma-gamma density tools measure an average bulk density of the formation. However, a bulk measurement is not adequate for certain applications where a more detailed resolution of a radial density profile is necessary. In this paper, a new approach of gamma spectral analysis is introduced focusing on the main Compton scattering angles. Several energy windows are linked to the unique radial layers based on scattering angles and location of interaction. As a result, the density of multiple layers can be calculated. The paper first outlines the main principles and analytical structures to formulate two methods to measure layer densities. Then computer simulation tools are used to simulate realistic tool configuration and measurement response to validate and benchmark efficacies of the outlined methods. Finally, a case study is presented to demonstrate the applicability of these methods using laboratory data. The paper is concluded with a list of other possible applications such as open-hole density and behind-pipe evaluation where layer density can provide more details for the analysis.
Abstract Whereas matrix density is known from core analysis or spectroscopy logging, so far no technique is available to estimate the apparent fluid density that the density log measures. In wells drilled with OBM, the near-wellbore fluids composition and distribution can be very complex. Yet, the current practice to compute density porosity is to use an ad hoc constant fluid density. This could lead to erroneous estimation of porosity. For example, in a 30 pu sandstone drilled with OBM, every 0.1 g/cm3 error in fluid density leads to 1.5 pu error in porosity. Numerous studies of near-wellbore fluids with 3D NMR (T1, T2, D) maps from NMR logging tools have shown a very complex fluids mixture that can include water, oil, OBM, and condensate/gas. However, the map acquired at a single depth of investigation (DOI) might not represent the fluids mixture that the density tool measures. The advent of radial fluid profiling with advanced magnetic resonance tools provides the needed fourth dimension—radial information that can be inverted jointly with conventional 3D NMR to unravel both fluids mixture and radial distribution. Because the near-wellbore NMR region closely matches the density region in both radial and axial directions, the two sets of data form "perfect" consonant volumes. Continuous 4D NMR maps are thus ideal to estimate the variable mixed fluids density. This value can be expressed as the double integration of all individual fluids detected by NMR weighted by the geometrical radial response function of the density log. The inner integration estimates the mixed fluids density. The outer integration computes it at 95% radial response of the density log. Examples are shown in which variable fluid density confirms subtle fluid changes recorded by density-neutron logs in sandstone formations offshore West Africa. These sands have variations in grain size and shaliness that control permeability and therefore the OBM invasion. Another example shows large porosity deficits when the contrasting fluids density is large, such as gas invaded by OBM. In all cases, density porosity computed with the variable fluid density agrees with local field knowledge and other methods. A side benefit is the reconciliation of NMR and density porosity discrepancy, because density porosity is often the reference to which NMR logs are judged. Introduction Gaymard and Poupon (1962) were first to propose a scheme to compute total porosity corrected for hydrocarbon effect from density-neutron logs. 1 The technique also gives an estimate of the hydrocarbon density when the matrix density is known. It assumes that the fluids are distributed uniformly within the investigation zones of the logging tools. Noting that near-wellbore fluids can vary radially, Suau (1981) took into account the different depths of investigation of the density and neutron logs to compute total porosity in gas-bearing formations. 2 Freedman et al. (1998) combined NMR and density to estimate total porosity in gas-bearing formations in the socalled DMR technique. 3 However, the assumption remains the same as with Gaymard and Poupon, i.e. the various sensors see the same fluids. In spite of their shallow depth of investigation, each sensor has a distinct DOI and fluids averaging scheme. For example, NMR has a shallow DOI in the order of an inch to a few inches and a narrow sensitivity zone in the formation; whereas classical nuclear tools have deeper DOIs ranging from a few inches for the density to a foot for the neutron and much broader investigation zones than NMR. Even though NMR and density logs might be "consonant" (Casu et al., 1998), 4 in many circumstances there is no guarantee that they will see the same fluids. 3D NMR is a stand-alone technique to evaluate nearwellbore fluids at a fixed DOI. In some cases, complex fluids mixtures including water, oil, OBM filtrate and gas are observed as shown in Fig. 1. (Cao Minh et al., 2004). 5 Individual fluids volume, saturation can be estimated from the map, and thus total porosity. However, slow logging speed and unfavorable vertical resolution prevent the routine use of the technique to estimate total porosity.
Jin, Ya (China Oilfield Services Limited) | Jie, Shang (China Oilfield Services Limited) | Huang, Lin (China Oilfield Services Limited) | Yu, Zenghui (China Oilfield Services Limited) | Li, Min (China Oilfield Services Limited) | ZengHai, Chen (CNOOC China Limited Pengbo Operating Company) | Li, Yulian (University of Electronic Science and Technology of China) | Tang, Wei (University of Electronic Science and Technology of China) | Hu, Yating (University of Electronic Science and Technology of China) | Lin, Lvlin (University of Electronic Science and Technology of China) | Zhang, Qinzhong (University of Electronic Science and Technology of China) | Zhang, Qiong (University of Electronic Science and Technology of China)
Abstract In most parts of the world, open hole logging with conventional gamma density tool remains the only option available, which is, though, not practical under complex well conditions when it is difficult to obtain formation parameters and control the operational risks. Therefore, the application of through-casing density logging is essential. However, through-casing gamma density measurement could be challenging due to gamma’s weak penetrating power. To better overcome these challenges, a new four-detector gamma density tool is designed and presented in this work together with a novel interpretation algorithm for through-casing density measurements. In order to identify the relationship between the four detectors, a significant amount of Monte Carlo models is constructed and executed to quantitatively evaluate the response of tool under various environmental conditions such as lithology, fluid, salinity, casing and cement. It is proven through open-hole benchmarking and extensive modelling that the four-detector design is capable to pro-vide sufficient information for removal of diverse environmental effects via an inversion algorithm developed by obtaining a formula that correlates the four-detector responses. This algorithm is validated against actual logging data and show a better though-casing evaluation than when using three or two detectors. In this work a case story using the four-detector tool to obtain through-casing formation density and using the algorithm mentioned above for correction is presented. The final results are analyzed and compared against open hole measurements, a very good consistency is achieved which demonstrates the correctness of the inversion algorithm.
Abstract Growth in the coal seam gas industry in Queensland, Australia, has been rapid over the past fifteen years, with greater than USD 70 billion invested in three liquified natural gas export projects supplied by produced coal seam gas. Annual production is of the order of 40 Bscm or 1,500 PJ, with approximately 80% of this coming from the Jurassic Walloon Coal Measures of the Surat Basin and 20% from Permian coal measures of the Bowen Basin. The Walloon Coal Measures are characterized by multiple thin coal seams making up approximately 10% of the total thickness of the unit. A typical well intersects 10 to 20 m of net coal over a 200 to 300 m interval, interbedded with lithic-rich sandstones, siltstones, and carbonaceous mudstones. The presence of such a significant section of lithic interburden within the primary production section has led to a somewhat unusual completion strategy. To maximize connection to the gas-bearing coals, uncemented slotted liners are used; however, this leaves fluid-sensitive interburden exposed to drilling, completion, and produced formation fluids over the life of a well. External swellable packers and blank joints are therefore used to isolate larger intervals of interburden and hence minimize fines production. Despite these efforts, significant fines production still occurs, which leads to failure of artificial lift systems and the need for expensive workovers or lost wells. Fines production has major economic implications, with anecdotal reports suggesting up to 40% of progressive cavity pump artificial lift systems in Walloon Coal Measures producers may be down at any one time. The first step in solving this problem is to identify the extent and distribution of fines production. The wellbore completion strategy above, however, precludes use of mechanical calipers to identify fines production-related wellbore enlargement. A new caliper-behind-liner technique has therefore been developed using a multiple-detector density tool. Data from the shorter spacing detectors is used to characterize the properties of the liner as well as the density of the annular material. This is particularly important to evaluate as the annulus fill varies between gas, formation water, drilling and completion fluids, and accumulated fines. The longer spacing detector measurements are then used in conjunction with pre-existing open-hole formation density measurement to determine the thickness of the annulus, and hence hole size, compensating for liner and annulus properties. This methodology has been applied to several wells completed in the Walloon Coal Measures. Results have demonstrated the ability to identify zones of borehole enlargement behind slotted liner, as well as intervals of either gas or fines accumulation in the annulus. In addition, the technique has been successful in verifying the placement of swellable packers and their integrity. The application of this solution has been used to drive improvements in the design of in-wellbore completion programs and in the future will help drive recompletion decisions and trigger proactive workovers.