The well within the context of this case study consists of reservoirs are sequences of permeable sands interbedded with variable proportions of silt and clay. Gas is the target hydrocarbon type, but light oil / condensate can be present unexpectedly. In these depleted reservoirs, hydrocarbons typing are complicated by their reduced volumes and corresponding diminished effect on conventional logs. Wells are highly deviated and targets don't align in the same direction leading to high trajectories tortuosity. This prevents to plan extensive wireline logging program. Formation evaluation is mainly based on LWD logs. For such challenging condition, fluids identification is traditionally made possible by stationary Nuclear Magnetic Resonance (NMR) from wireline conveyed logging devices, adopting Diffusion— Relaxation maps technique. Through Diffusion—Relaxation maps technique, the contrast on both diffusivity and relaxation time (longitudinal relaxation time T1 or transversal relaxation time T2) allow differentiation of gas, oil and water. Even though high gas diffusivity creates contrast on transversal relaxation time T2 to differ gas from the other fluids, the approach based on T2 domain only is long time neglected. This is because under wireline condition, formation gas is often flushed by mud filtrate and the formation oil can be mixed up with OBM signal. This study proves that LWD NMR, due to its logging while drilling features, enables the simple T2 spectra based method to differ formation fluids in an efficient way. Attentive BHA design and job planning ensure good data quality and reasonably fast logging speed. Because of short time after bit (TAB) while drilling, it probes directly the formation fluids without being affected by mud invasion. For the studied reservoirs, the measured T2 value for water, gas and light oil are well distinguished being approximately of 200 milliseconds, 450 milliseconds and 2000 milliseconds respectively. The intervals with the presence of light oil are revealed directly from T2 spectra and the gas-oil-contacts (GOC) are accurately determined by T2 distribution. The same result is hard to be achieved by triple-combo measurements only. A newly introduced statistical technique "factor analysis" is used to determine poro—fluid distributions and associated porosities. It automatically searches for the dominant T2 modes through T2 depth log and identify repeated T2 distribution patterns to provide a continuous fluid facies analysis. Density Magnetic Resonance Porosity (DMRP) method is used to estimate the total porosity and gas saturation. It provides a resistivity independent method to address the gas saturation. Considering the fresh formation water, the uncertainty on the petro—physical parameters is significantly reduced. This paper divulges the value of T2 based fluid typing method with LWD NMR tool. It provides a simple but efficient way to identify gas from light oil. The fluid information offered is essential for field completion decision making.
Wellbore instability remains a leading threat to oil operators as one of the main causes of non-productive time worldwide. As drilling technology advances, logging-while-drilling (LWD) measurements contribute valuable information to help identify instability problems in real time. One of the important measurements is the LWD ultrasonic caliper measurement, which makes it possible to identify borehole washout, breakout, keyseating, and spiral-hole conditions. Having this measurement enables diagnosis of wellbore stability problems while drilling without the need for an additional logging run, which is especially critical in an unstable wellbore. In the industry, breakout identification using image data can be a significantly user-dependent process and requires appropriate skills. The process is time consuming, and the final result can still be subjective. Further complication comes when considering a highly deviated well path or when the field stress regime is abnormal. As a consequence, drillers face difficulties using the LWD ultrasonic caliper data directly for wellbore stability diagnosis. We propose a methodology to overcome the limitation of conventional method and produce reliable quantitative breakout data to be used in real time, in an automated, systematic, and consistent way. An engineering-based workflow is introduced to distinguish zones of stress-induced breakouts from other borehole enlargement types with improved consistency and which can be easily translated into programming language. Instead of image data, this solution uses sector data to extract the borehole shape information using the cubic spline method. Six stringent LWD ultrasonic caliper-specific breakout criteria are introduced and used to identify breakout intervals from the borehole shape data. Adopting the idea from the World Stress Map (WSM) project, a data quality ranking was also performed using the result of the workflow. The quality ranking criteria (defined by WSM project) segregate the breakout results into five categories to infer the reliability of the breakout intervals identified. This quality ranking procedure will greatly improve the reliability of the output data in the workflow prior to quantitative usage. The result of the breakout identification is then used to determine the principle stress direction and the stress regime, using a 3D stress analysis method for deviated wells.
The Alpha field is located offshore of East Malaysia and operated by PETRONAS. Alpha-C development wells were often completed with the wire-wrap screens (WWS) for sand control over multiple zones separated by packers. This completion design was deployed in more than 20 wells which include the oil or gas producers and water injectors. Some producers were converted to injectors for reservoir pressure maintenance with several attempts to convert producers to injectors hampered by poor or no injectivity. Remedial efforts to restore injectivity, including stimulation, proved unsuccessful. This prompted the Alpha production team to look for a way to investigate the possible causes of inadequate injectivity, without the expense of retrieving the completion string. PETRONAS suspected that fines migration was either plugging the outer WWS or filling the annulus between the screen and the tubing, thus reducing the injectivity. A series of pulsed-neutron logs were recorded in five (5) problematic wells. The objective was to determine if fines migration was the cause of the blockage, using silicon activation and neutron-gamma ray spectroscopy. Silicon activation, also known as Gravel Pack (GP) logging is a technique traditionally used to evaluate the quality of the gravel distribution in a gravel pack. The measurement is sensitive to silicon around the borehole, hence a technique was adapted to detect sand blockage in the wellbore by logging the pulsed neutron tool inside the tubing. The technique is sensitive to silicon both outside the screen and inside the annulus between the screen and tubing. The inelastic and capture spectra measured by the near and far detectors of the tool were used to derive further details on the sand distribution in the wellbore. The difference in depth of individual measurements, with GP logging "seeing" deeper than the inelastic and capture spectra, has allowed for varying degree of sand buildup outside and inside the screen. The proposed method has helped to detect sand blockage around the wellbore, computing the height of the sand fill and inferring the depth of any damage to the screen. This paper discusses the innovative application of pulsed-neutron inelastic and capture spectra for detecting sand fill. The results successfully identified the location of the sand blockage in all five (5) wells. This has helped PETRONAS to decide on the ideal way to remove the sand blockage in the borehole before performing the next injectivity test. The remedial plans are to focus on removing the sand fill, rather than trying to treat plugged screens. This will include attempting to perform sand clean out operations (via coiled tubing), selectively performing tubing punches or opening sliding sleeves as appropriate and circulating out as much of the sand as possible. Obviously, the restoration of the injectivity rates will be highly dependent on the success of these attempts.
Pulsed neutron spectroscopy (PNS) is a well-established technology for characterizing reservoir saturation through cased hole, using either sigma (Σ) or carbon/oxygen (C/O) ratio measurements. However, the current technologies struggle to deliver reliable answers in complex completions. Tubing and casing, with varying tubing and annulus fluids, or dual tubing completions with changing annulus and tubing fluids represent cases in which it becomes difficult to identify fluid contacts in the formation and calculate remaining saturations. A new-generation slim pulsed neutron logging tool has been developed to deliver reliable answers in conditions that challenged existing technologies. It introduces the new petrophysical measurement, fast neutron crosssection. This measurement is highly sensitive to variations in gas volume and insensitive to variations in water volume, independent of neutron porosity and formation Σ properties. It provides high-resolution spectroscopy with a much-improved accuracy and precision of all elements measured, including the key element for oil saturation, carbon. The carbon measurement is used conventionally for C/O, and it is used directly to derive total organic carbon (TOC), which is then converted to oil saturation. This tool delivers the self-compensated Σ and neutron porosity measurements in a wide range of conditions, including complex completions and varying amount of gas in the wellbore or annulus. The field test results in this paper demonstrate the performance of this new tool in a few wells from Malaysia. All present some complex completions, from single tubing inside 7-in. casing and 8.5-in. hole to dual 3.5-in. tubing in 95/8-in. casing and 12 ¼-in. hole. Additional challenges include gas-filled annulus, multizone completion with sliding side doors (SSD) and wire-wrapped screens (WWS), and environments in which there are no water sands for C/O measurement calibration. The logging objectives include determining theoil/water contact (OWC) and the gas/water contact (GWC),quantifying the current saturation, confirming the source of water for water shutoff determination and anticipated gain, and verifying sand-filled annulus. A back-to-back comparison with the previous technology was also run in the first well, allowing a directcomparison of the measurements from the new and the existing tools in the same conditions.
Permeability determination is critical in understanding the viability of a project as it is often used as an economic indicator in the infill well placement, production strategy and enhanced oil recovery strategies. Often, well tests are planned, and core analysis are performed to evaluate the flow capability of the reservoir, but it may not be sufficient for heterogenous and complex carbonate formation. Hence, to determine the permeability, we often employ correlations such as resistivity-permeability relationship, intrinsic permeability estimation from geochemical data and most common and widely used is the porosity-permeability (poro-perm) relationship. Poro-perm relationship relies on the basis that all pores contribute to fluid flow. However, any heterogeneity, such as presence of isolated pores could cause this poro-perm relationship to fail. Hence, this paper aims to address the challenges associated with the quantification of the isolated pores in the formation. The case study gas well, Well M, is in offshore of Sarawak, Malaysia. The nuclear magnetic resonance (NMR) logs are acquired to quantify porosity and permeability in addition to basic quad-combo and wireline formation tester (WFT) sampling. The direct porosity-permeability transform obtained from NMR Timur-Coates equation shows distinct disagreement by a factor of up to 100 with the mobility obtained from WFT. This discrepancy could be due to the incorrect assumption that all pores are interconnected, but in reality, some of the pores might be isolated porosity. To unravel this complex problem, an advanced analysis incorporating the quad-combo data and NMR data is carried out in the volumetric solver. Since sonic is generally less sensitive to spherical pores, deviation seen between sonic porosity and total porosity is interpreted as the presence of spherical pore. After analyzing the core, it was found that these spherical pores are isolated in nature, hence sonic could be used as a quantification of isolated pores inside the formation. In addition, an unsupervised machine learning algorithm, NMR factor analysis (NMR FA) was performed on the NMR T2 Distribution to fully characterize the formation by analyzing the fluid residing in the pores. This was done via concurrent analysis of the NMR signal modelling. By leveraging machine learning of the NMR data, many of the critical information that would otherwise go undetected were extracted successfully. Lastly, the factor analysis result was blindly compared to advanced volumetric analysis, and both methodologies yield the approximate the same volumes of isolated porosity in the formation of interest (R2 = 0.886). After the quantification of the isolated pores were successfully carried out and confirmed, a reliable poro-perm transform was established. To conclude, poro-perm estimate in this field was enhanced and the permeability uncertainty is greatly reduced. Subsequently, the result from this workflow can be used as a quick preliminary justification on the reservoir flow capability derived from NMR on the new play zone. This will ultimately lead to an earlier input to the production strategy decision and the net present value (NPV) can be maximized accordingly.
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