The identification of low-rate leaks along with low annular-pressure buildup rates in any type of completion presents challenges in the well-integrity domain. This paper emphasizes the importance of understanding the well-diagnostic problem to determine feasibility, isolate interest zones, enhance stimulation strategies, and ultimately optimize the acquisition of high-resolution acoustical data from the wellbore with a latest-generation advanced leak-detection tool. This case study discusses the methodology that underlies the successful determination of the depths and the radial locations in the outer casing strings of multiple leaks in an offshore well. In the study presented, emphasis had been placed on the job planning to provide adequate or substantial leak stimulation for the accurate determination of the leak points in terms of radial distance away from the tool axis within the wellbore. Rather than a shut-in and flowing or venting acquisition, it was proposed that the optimal method for the successful determination of an outer casing string leak involved invoking a range of flow rates and, therefore, acoustic levels, across an extended period. The study also demonstrates the advantages of integrating acoustic-based tools with conventional production logging tools. Two outer string casing leaks with annulus to formation communication areas were identified from high-resolution leak-detection logging coupled with conventional pressure and temperature measurements. The interpretation process included the computation of a 2D radial map of the flow activity across each zone of interest. This process resulted in less ambiguity and clearer results obtained in real time during the acquisition. The location of each leak point was triangulated using an error-minimization algorithm from the received acoustic waveforms at the tool receiver array. Further, the optimized stimulation strategy enabled leak-stimulation responses to be tracked in the computed power spectral density (PSD) at each leak. This process enabled the operator to promptly move on with the well abandonment strategy without waiting for further data analysis. Attention to detail from the outset and a complete understanding of the well and its annular pressure and fluid behavior enabled an optimized and focused electric line diagnostic strategy to be used. The use of high-resolution acoustic data from an advanced leak-detection tool with an array of hydrophones ensured that the multiple leak locations were identified and characterized.
This paper introduces and evaluates a next-generation acoustic conformance-monitoring system that helps identify the depth and accurate radial location of undesirable leaks in a well. Determining the leak's flow pattern in and around the wellbore is also used to understand activity within the surrounding wellbore region. The acoustic conformance tool was run employing a memory slickline operation in a well located offshore Sarawak, Malaysia. The tool successfully acquired both low- and high-fidelity data, which were subsequently used for leak characterization analysis. Using an array of acoustic sensors, the tool is capable of detecting undesirable flow throughout the well structure. The vertical accuracy is within inches and estimates the radial location around the wellbore. Before the operation, careful and thorough prejob design is necessary for data acquisition to help reduce uncertainty in post-interpretation. These include detailed operational sequences in terms of leak stimulation of various annuli in the well to obtain optimum results. Subsequently, the signals are analyzed using a beam-forming method to identify leak distances and a flow map to further understand flow characteristics. The study well is a gas producer completed with a 7-in. single string. Post-data processing and interpretation revealed a continuous high-frequency noise spectrum from the bottom of the logging interval to the surface, indicating gas movement, which was further confirmed by two-dimensional (2D) flow map analysis. Results indicated gas movement in Annuli C and B. Based on results, production logging sensors, and well completion statuses, inferences were made regarding this gas movement and its possible sources—a cement window in Annulus C and cement channel in Annulus B. This technology accurately identifies and pinpoints leak sources, assisting the asset owner with planning and designing remedial work to help reduce undesirable fluid, which benefits total production.
During field development, a detailed understanding of reservoir geometry and associated sedimentary features within the sand sequence plays an important role in the effective recovery of hydrocarbon resources. Most aging fields encounter the common problem in well placement for effective production of the remaining hydrocarbon resources. The current example—onshore formation from Late Miocene in East Kalimantan—includes seismic data acquired during the 1970s and 1980s. Considering advancements and breakthroughs provided by current technology, the older information could provide a greater level of subsurface uncertainty. Geological challenges include comprehending geometry prediction and the continuity of the amalgamated distributary reservoir channels and the depositional architecture within a fluvio-deltaic environment in a structurally complex field. High-density borehole microresistivity image data from several wells in the study area were acquired to constrain and reduce the geological uncertainty resulting from poor control of subsurface imaging through the surface seismic data. Microresistivity imaging data were used to identify sedimentary features and to perform electrofacies analysis. The data are used for the structural reconstruction of sequences by decoding a different order of structural deformation and reconstructing the sediment transport direction at the time of deposition. The results are then incorporated within the regional geology context in the basin. The consistent shale/silt beddings in the studied wells indicate an overall structural dip trend of 10° toward the east. The structural deformation within the same section of these wells is identified by the characteristics in the rotation of the structural dips. This suggests the proximity of these wells in relation to the deformation plane of sub seismic features and helps refine the structural maps. During a later phase, the reservoir is correlated within the wells, and careful selection of a palaeocurrent indicator is established from the vertical distribution of the sedimentary beddings for paleogeography reconstruction. Based on this, the channel complex dispersal direction was observed to exhibit an overall easterly direction with complex migration, and the identified mouth bar sequences reveal more widespread geometry. The dispersion or variations observed in the studied wells are then correlated to the overall reservoir architecture within fluvio-deltaic settings. The case study demonstrates the applications of borehole microresistivity data and their importance in providing a high-resolution well-to-well correlation for sand body delineation within the targeted sequences. The results provide details about the structural complexity in the underlying subsurface litho-sequence and illustrate how behaviors change laterally from one well to another. This analysis helps develop a high-resolution geocellular model for the field.
In recent years, the development of frontier areas brings added challenges to formation evaluation, especially thinly bedded reservoirs. It is challenging to evaluate such reservoirs due to the low resistivity values and high shale volume, which masks the contrast between water and hydrocarbon zones. Using conventional approaches in these types of reservoirs will underestimate the hydrocarbon potential and reserves estimates. A study has been carried out of the thin-bed laminated reservoir in B-field using the tensor model technique to assess the hydrocarbon potential. Additional data from borehole imaging and sonic logs are critical for enhancing the evaluation of hydrocarbon potential and complements the result of the tensor model evaluation. The study was conducted to calculate the sand resistivity and sand porosity using a combination of the tensor model and the Thomas-Stieber model. The tensor model uses acquired horizontal and vertical resistivities, while the Thomas-Stieber model uses the calculated shale volume and porosity. One of the main parameters in the tensor model is shale resistivity, which upon analysis, varies across many shale sections in the well. This uncertainty is reduced by picking multiple shale resistivity values based on borehole image facies analysis. The VPVS ratio technique and Brie’s plot using compressional and shear travel time are used as a qualitative analysis that indicates the same gas-bearing interval. The tensor model calculations improve hydrocarbon saturation by a range of 4-21%, depending on sand thickness and shale volume, which increases the net to gross by more than 20%. The borehole image facies analysis helps to objectively pick the shale resistivity parameters to avoid subjective interpretation and underestimating the pay. A qualitative approach using sonic data helps to identify the potential gas-bearing interval and complement the previous tensor model interpretation. Although all interpretation methods indicate a similar gas-bearing interval that correlates with the mudlog total gas reading, the combination of the tensor and Thomas-Stieber method with image constrained shale resistivities gives the most definitive gas saturation and net pay The novelty of this study is to showcase two things. First is the application of combined tensor and Thomas-Stieber model in a laminated reservoir, with image constrained shale resistivity for improved gas saturation and net pay. The second is to highlight the use of gas-sensitive sonic data to confirm the gas saturated interval.
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