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Liang, Qixuan (China University of Petroleum (East China)) | Zhang, Feng (China University of Petroleum (East China)) | Zhang, Xiaoyang (China University of Petroleum (East China)) | Chen, Qian (China University of Petroleum (East China)) | Fan, Jilin (China University of Petroleum (East China))
Abstract Unconventional oil and gas resources, such as tight oil and gas, have become indispensably succeeding energy sources in nowadays. At the stage of exploration, gas saturation is essential for the evaluation of tight formation, which can provide the key parameters for reserves calculation and development plans making. Conventional logging technologies including acoustic logging and resistivity logging have played a role in gas formation identification and evaluation. Besides, inelastic and capture gamma energy spectrum or time spectrum from pulsed neutron logging tools with NaI, BGO, LaCl3, or LaBr3 detectors are used to realize the quantitative evaluation of gas saturation. With the development of nuclear technology, the new detector, called CLYC (Cs2LiYCl6:Ce), can simultaneously measure the signals of gamma ray and thermal neutron, providing a new mean for gas saturation evaluation use pulsed neutron logging technique. The CLYC scintillation crystal with a density of 3.31g/cm has an energy resolution in the order of 4%-5% (0.662MeV), and its light output efficiency of gamma ray and neutron are 20000 photons/MeV and 70500 photons/MeV. Meanwhile, its excellent temperature characteristics in the range from -30℃ to 180℃ can fit the downhole environment. Consisting of the D-T neutron source and CLYC detector, the pulsed neutron logging system is designed in this paper, in which the burst gate is 0 to 40 microseconds and the capture gate is 50 to 100 microseconds. To evaluate gas saturation, this system combines the inelastic gamma ray and thermal neutron recorded from the burst gate and the capture gate. The new pulsed neutron logging tool consists of two LaBr3 detectors and a CLYC detector, and the spacing of the CLYC detector is 75cm. In addition to the conventional C/O and Sigma measurement functions, the new instrument can also realize the quantitative evaluation of gas saturation by the CLYC detector. The inelastic gamma, capture gamma, and thermal neutron distribution in long-detector are simulated by the Monte Carlo method under the condition of tight gas saturated formation with porosity from 3% to 20%. Based on the spatial flux distribution characteristic of inelastic gamma and thermal neutron, the new parameter (RGTH) is defined as the ratio of inelastic gamma counts to thermal neutron counts from the CLYC detector to calculate gas saturation. The results imply that RGTH is positively correlated with porosity and negatively correlated with gas saturation, and the gas and water dynamic range is about 36% under the condition of a sandstone formation with 10% porosity. Different lithology has different RGTH benchmark values. RGTH is not affected by the yield of the neutron source and water salinity, and the subtract coefficient can be accurately determined by the time spectrum of the thermal neutron to acquire the pure inelastic gamma. A tight lime-bearing sandstone formation with 5% porosity has been set by MCNP to check validity, the absolute error of gas saturation calculated by RGTH is less than 5%.
Abstract Borehole acoustic logging is an acquisition method that is regarded as the most efficient and reliable method to measure subsurface rock elastic property. It plays an important role in both well construction and reservoir evaluation. The acquisition is carried out downhole by firing a transducer and then collecting waveforms at an array of receivers. A signal processing technique such as the slowness-time-coherence method is used to process array waveform data to resolve slownesses from different arrivals. To label these slowness values, a classification algorithm is then required to first determine if a primary (P) or a secondary (S) arrival exists or not, and then label out the existing ones at each depth of the entire logging interval to deliver continuous compressional and shear slowness logs. Such a process is referred as automatic sonic log tracking process. Clearly, it is of great importance to be able to track log as accurately as possible. Traditional approaches either use predefined slowness or arrival time boundary to distinguish them or treats slowness peaks in consecutive depths like “moving particles” and use a particle tracking algorithm to estimate their trace. However, such a tracking algorithm is often challenged by a sudden change in formation types at bed boundary, fine-scale heterogeneity, downhole logging noise, as well as unpredicted signal loss due to bad borehole shape or gas influx. Consequently, the tracking process is often a tricky task that requires heavy manual quality control and relabeling process, which poses significant bottleneck for a timely delivery of sonic logs for downstream petrophysical and geomechanical applications. In this paper, we propose a new physical based multiresolution tracking algorithm that can improve the robustness of the tracking process. The new algorithm is inspired by the fact that different resolution sonic logs can sense different rock volumes and therefore response differently to a thin layer or an interval with bad borehole conditions. It works by grouping slowness-time peaks with different resolutions to form clusters, which are then tracked by the connecting with its neighboring depths. As different resolution slownesses are physically constrained by the convolution response of heterogeneous layers, the cluster-based multi-resolution tracking approach exhibits better logging depth continuity than the traditional single-resolution methods. Outliers due to noise can be confidently avoided. Finally, remaining gaps due to shoulder bed boundary can be patched by a convolution constrained optimization process from coherences from different resolutions. This new approach is therefore referred as a multi-resolution approach and can significantly improve sonic log tracking accuracy than the single resolution approach. This new algorithm has been tested on several sonic logging field data and demonstrates robust tracking performance of sonic P&S logs. Additionally, with the multi-resolution processing, sonic logs with different resolution can be reliably obtained and a high-quality high-resolution sonic log can also be automatically delivered, which can then be used to match resolution of other petrophysical logs for various types of interpretation.
Zhang, Hao (PetroChina Xinjiang Oilfield Company) | Wang, Yue (Schlumberger) | Fang, Tao (PetroChina Xinjiang Oilfield Company) | Wang, Wei (Schlumberger) | Zhao, Xian Ran (Schlumberger) | Zhao, Hai Peng (Schlumberger) | Wu, Jin Long (Schlumberger) | Wei, Guo (Schlumberger) | Liu, Bo (Schlumberger)
The strong domestic need for oil in China requires further exploration in unconventional reservoirs, such as volcanic and shale oil reservoirs. Sweet zone identification is one of the most critical missions in formation evaluation. The complex mineralogy and the low porosity in unconventional reservoirs result in little contrast of resistivities between oil-producing zones and water zones. Reducing uncertainties affecting the type of fluid in the reservoir and its potential movability is key to defining the optimal landing zones for future horizontal drains.
In conventional reservoirs, nuclear magnetic resonance (NMR) logging based on cutoff analysis is the optimum choice for evaluating the porosity and pore geometry of hydrocarbon bearing reservoirs. However, the routine single-dimension T2 measurement is not sufficient for fluid typing in unconventional reservoirs because of the overlap of signals of various fluids in the T2 domain. This contribution presents case studies from a new generation NMR tool providing continuous 2D T1-T2 measurements. The T1-T2 measurements enable separation and quantification of different fluids in the pores. Fluid typing can be done by integration of other wireline logs such as spectroscopy and dielectric.
Case studies are presented from volcanic and shale oil reservoirs in Xinjiang Oilfield of PetroChina. In the volcanic reservoir case, dedicated 2D data analytics technic is used to extract relevant signals from 2D NMR T1-T2 measurements. An integrated workflow combining wireline borehole electrical image, nuclear spectroscopy, dielectric dispersion and NMR T1-T2 gives an insight into the fluid composition in the pore system. Besides accurate measurements of lithology independent porosity and pore geometry from NMR, T1-T2 specific measurement of clay bound water volume and total water volume match well with the same measurements estimated from nuclear spectroscopy and dielectric dispersion logs. It lowers the uncertainties on fluid types in the volcanic reservoir where resistivities fail to differentiate wet zones and oil zones. In the shale oil reservoir case, a reservoir producibility index (RPI) derived from the integration of NMR T1-T2, wireline borehole electrical image, and nuclear spectroscopy is shown to be quite efficient in sweet zone identification and ranking.
This paper discusses a novel application of a new generation NMR T1-T2 logging method in unconventional reservoirs, which helps the operator ascertain the potential of these reservoirs. The oil zones identified by the new method have promising oil productions. The workflow illustrated in the two case studies can be applied and extended to other unconventional plays in China.
Jiang, Li-Wei (PetroChina Zhejiang Oilfield Company) | He, Yong (PetroChina Zhejiang Oilfield Company) | Shu, Dong-Chu (PetroChina Zhejiang Oilfield Company) | Niu, Wei (PetroChina Zhejiang Oilfield Company) | Pan, Feng (Schlumberger) | Wang, Yue (Schlumberger) | Li, Kai-Xuan (Schlumberger) | Zhao, Hai-Peng (Schlumberger) | Tang, Yu (PetroChina Southwest Oil and Gas Company)
Abstract Most bedding-parallel fractures in the WuFengLongMaxi Formation, SiChuan basin, are calcite filled and commonly show slickensides, which features characterize bedding-parallel shear fractures. Such fractures can serve as flow channels and storage spaces in gas shale reservoirs. However, little is known about their size and spatial distribution, the relationship of their permeability to the confining stress, and any relationship with porosity. Knowing these relationships may contribute to understanding the role of bedding-parallel shear fractures in shale gas enrichment. Bedding-parallel shear fractures were measured from core and image logs from the WuFeng-LongMaxi Formation, southern SiChuan basin, supplemented with stress-dependent permeability experimental data and nuclear magnetic resonance (NMR) logs from the same wells. Core and image logs were used to characterize the spatial organization of the fractures. A stress-dependent permeability experiment was proposed to investigate the fracture permeability response to changes in confining stress. The effect of the fractures on porosity was examined in terms of the macroporous component reflected by the NMR T2 relaxation; macropores are more likely to be preserved in gas-rich shale. Study of 27 wells spanning 100 km west-east across the southern SiChuan basin revealed the aperture size of bedding-parallel shear fractures ranges from 1 cm to 50 cm. In most wells, the fractures are much more intense in organic-rich intervals, which have low elastic modulus compared to the overlying nonorganic shale and underlying stiff limestone. The stress-dependent permeability experiment suggests that permeability in samples with the fractures is two to three orders of magnitude larger than in samples without fractures under the same confining stress. Fracture permeability decreases exponentially until the confining stress reaches 25 MPa. NMR analysis indicates that the macroporous component has an inverse relationship with the intensity of bedding-parallel shear fractures.
Izadi, Ghazal (Baker Hughes a GE company) | Barton, Colleen (Baker Hughes a GE company) | Cruz, Leonardo (Baker Hughes a GE company) | Franquet, Javier (Baker Hughes a GE company) | Hoeink, Tobias (Baker Hughes a GE company) | Laer, Pierre Van (ADNOC)
Abstract We use advanced modeling techniques to optimize wellbore landing, completion configuration, and stimulation treatments in a complex carbonate reservoir in the Middle East. The reservoir, where target formations are highly laminated, naturally fractured, and stresses are transitional as a function of depth, presents conditions for which a more sophisticated stimulation design approach is required. A meticulous analysis of wellbore image logs and detailed forward modeling of the geometry of the drilling induced tensile fractures revealed that in situ stresses rapidly transition between strike-slip and reverse faulting as a function of depth. The log-derived geomechanical model was calibrated against wellbore failure observations, laboratory measurements, and mini-frac test results. The stresses and rock properties were mapped to the 3D reservoir volume assuming a horizontally layered formation. Models of hydraulic fracture propagation in the presence of natural fractures and laminations under vertically heterogeneous stress conditions were investigated using a 3D simulator that couples geomechanics, fracture mechanics, fluid behavior, and proppant transport. Modeling results reveal hydraulic fracture propagation is profoundly influenced by the complex stresses and structures in this reservoir. Simulation results indicate that vertical hydraulic fracture propagation (height, growth) is controlled by stress contrasts, stress state, elastic, and strength variations between adjacent formations, and the frictional strength of weak bedding discontinuities that are ubiquitous in tight formations. Results also show limited height growth within a reverse-faulting zone where modeling predicts a tendency for the development of horizontal limbs ("T-shaped" fractures). Hydraulic fracture geometry is significantly different in the presence of weak bedding compared to bedding with sufficient strength to transmit crack tip stresses across the interfaces. Significant amounts of fluid and proppant can be diverted into created horizontal fractures in this reservoir. Increasing fluid viscosity improves the propped surface area and controls the height growth within the zone of interest. Capturing such subsurface complexities and using them to simulate hydraulic fracture propagation helps us to improve treatment designs, reduce operational costs, and ultimately improve hydrocarbon recovery. This study illustrates that for more complex reservoirs where spatial heterogeneities, preexisting natural fractures, or transitional stress states are present, using advanced 3D modeling is essential. Through parametric stimulation modeling, design parameters can be refined to achieve optimal solutions to better manage the controllable drilling, completion, stimulation, and production parameters that present the primary risks to development in tight/unconventional reservoirs.
Gurmen, M. Nihat (Schlumberger) | Fredd, Christopher N. (Schlumberger) | Batmaz, Taner (Schlumberger) | Kurniadi, Stevanus dwi (Schlumberger) | Zeidi, Omar Al (Schlumberger) | Kanneganti, Kousic (Schlumberger) | Nasreldin, Gaisoni (Schlumberger) | Khan, Safdar (Schlumberger) | Tineo, Roberto (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
Abstract Innovation and advances in technology have enabled the industry to exploit lower-permeability and more-complex reservoirs around the world. Approaches such as horizontal drilling and multistage hydraulic fracturing have expanded the envelope for economic viability. However, along with enabling economic viability in new basins come new challenges. Such is the case in the Middle East and North Africa regions, where basin complexity arising from tectonics and complicated geology is creating a difficult geomechanical environment that is impacting the success of hydraulic fracturing operations in tight reservoirs and unconventional resources. The impact has been significant, including the inability to initiate hydraulic fractures, fracture placement issues, fracture connectivity limitations, casing deformation problems, and production impairment challenges. Completion quality (CQ) relates to the ability to generate the required hydraulic fracture surface area and sustained fracture conductivity that will permit hydrocarbon flow from the formation to the wellbore at economic rates. It groups parameters related to the in-situ state of stress (including ordering, orientation, and amount of anisotropy), elastic properties (e.g., Young's modulus and Poisson's ratio), pore pressure, and the presence of natural fractures and faults. Collectively, this group of properties impacts many key aspects determining the geometry of the fracture, particularly lateral extent and vertical containment. Heterogeneity in CQ often necessitates customizing well placement and completion designs based on regional or local variability. This customization is particularly important to address local heterogeneity in the stress state and horizontal features in the rock fabric (e.g., laminations, weak interfaces, and natural fractures) that have been identified as key contributors impacting the success of hydraulic fracture treatments. Given the observation that a wide range of CQ heterogeneity was creating a complex impact on hydraulic fracture performance, CQ classes were introduced to characterize the risk of developing hydraulic fracture complexity in the horizontal plane and the associated impact on well delivery and production performance. They indicate the expected hydraulic fracture geometry at a given location and are analyzed in the context of a wellbore trajectory in a given local stress state. CQ class 1 denotes locations where conditions lead to the formation of vertical hydraulic fractures, CQ class 2 denotes locations where conditions lead to the formation of a T-shaped or twist/turn in the hydraulic fracture, and CQ class 3 denotes locations where conditions lead to the formation of hydraulic fracture with predominantly horizontal components. Wellbore measurements indicate that these CQ classes can vary along the length of the wellbore, and 3D geomechanical studies indicate that they can vary spatially across a basin. By understanding this variability in CQ class, well placement and completion design strategies can be optimized to overcome reservoirheterogeneity and enable successful hydraulic fracturing in more challenging environments. This paper introduces the novel concept of CQ class to characterize basin complexity; shows examples of CQ class variability from around the world; and provides integrated drilling, completion, and stimulation strategies to mitigate the risks to hydraulic fracturing operations and optimize production performance.
Steiner, S.. (ADCO) | Raina, I.. (Schlumberger) | Dasgupta, S.. (Schlumberger) | Lewis, R.. (Schlumberger) | Monson, E. R. (ADCO) | Abu-Snaineh, B. A. (ADCO) | Alharthi, A.. (ADCO) | Lis, G. P. (Schlumberger) | Chertova, A.. (Schlumberger)
Abstract ADCO started its unconventional exploration campaign in 2012 targeting the tight carbonate sequences known as Wasia Group, onshore Abu Dhabi. A front-end loaded data gathering strategy was employed to acquire extensive latest generation logging data tailored for unconventional reservoirs. In a number of wells the entire reservoir section was cored, often up to 800 ft per well, leading to more than 3000 ft of core retrieved to date. ADCO applied unconventional core analysis technologies, such as retort analysis, to generate the optimal core results. Key parameters such as effective porosity, pore size distribution, TOC, source rock maturity, mineral compositions and fluid saturations were determined from logs and core data (where available). This paper will focus on the petrophysical challenges during the evaluation of the Wasia Group. We will demonstrate that conventional core analysis techniques have only limited applicability, whereas core analysis techniques designed specifically for unconventionals provide more relevant results. A log analysis methodology centered on the application and importance of NMR in unconventional liquid plays is presented. Porosity data measured through retort analysis provide an excellent fit to NMR log-based porosity measurements. Conventional core analysis results generated a poor fit to log porosity, and the resulting values exhibited scatter with a large standard deviation. T2 distribution from NMR log data suggests the presence of large pores with good fluid mobility, which requires confirmation through formation testing or production. Log data-derived rock typing was performed. It is based on principal component analysis of the reservoir section. Rock classification may help in selecting suitable zones for hydraulic fracture initiation. Lessons learned from the initial wells for core recovery and analysis techniques are summarized below and have been implemented in later wells: –Preserve part of the core for robust saturation measurements. –Stop acquisition of conventional poro-perm data –Focus on unconventional-specific retort-based techniques for core petrophysics –Focus on pulse decay permeabilities –Use scratch test to aid in core analysis sample selection process, especially for rock mechanics –Add core T1/T2 NMR and MICP to future core analysis programs The complete integration of core and log data has allowed for a thorough assessment of the unconventional hydrocarbon potential within the ADCO concession.
Several wells in the Campamento 1 Field were drilled to target the deeper granitoid basement formations of the Neuquén basin. These wells were evaluated using anisotropic stress modeling to estimate the stress profile and identify suitable intervals to fracture. The effects of lateral tectonic strains are considered in the estimation of the horizontal stress profile, using a vertical borehole acoustic log for stiffness and compliance tensor characterization. The objective of this paper is to show the use of hydraulically induced fracture pressures to calibrate the magnitude of the horizontal stresses in a vertical well. The results show how fracture pressures can help in constraining the magnitude of the lateral tectonic strains. Examples of three wells in the Campamento 1 Field are shown where minifrac data were obtained. A non-constant, depth-dependent tectonic lateral strain model, calibrated with the minifrac data was applied in these wells. This calibration methodology is recommended in formations showing significant anisotropy, as elastic anisotropy in tight formation are important in wellbore completion.
Abstract In Argentina, over the last decade mature field management has been of paramount importance in ensuring economic sustainability for many oil field operators. Success requires solving a specific suite of problems comprising mixed generations of technology (in particular logging tools), long and complex well histories and often the sheer size of the dataset. The field in this case study has been in production since 1964 reaching its maximum production capacity of 32000 bpd during 1969, after which decline began. Consequent depletion from 140kg/cm2 to 20kg/cm2 drove the need for pressure support that was achieved through waterflooding which was implemented in two major campaigns during the 70's and the 80's. A total of 354 wells comprise the historical dataset with recent re-drills, extensions and infills bringing the total well count to 422. Re-evaluation of the remaining target via a series of studies carried out between 2006 and 2009 indicated an attractive opportunity for 7 spot waterflooding and saw the commencement of a massive re-development of the field. Behaviour of recent wells has been worse than predicted. This deviation from expectation initiated a series of studies to better characterize the reservoir with the objective of re-defining targets for incremental development. Associated with these studies new geological and dynamic models were built using re-evaluated historical data integrated with information from 68 new wells and 8 new cores. In particular, the impact of textural variation and thin bed architecture on the meso-scale oil distribution was assessed allied with a range of different techniques to identify macro-scale compartmentalization. The result was an integrated model that enabled comprehensive re-evaluation of the remaining targets. The approach used in this study to identify and characterize thin beds in this type of setting, define the impact on OOIP and determine the remaining oil in place in order to evaluate opportunities can assist many operators who experience various challenges associated with developing mature acreage.
Abstract In the past, only four types of reservoirs were defined to characterize matrix and fracture systems. These definitions based on matrix and fracture systems do not cover all the pore systems present in the real world because a great number of reservoir systems are made up of different lithologies and pore types. The pore types could be matrix, fractures, or vugs or combinations of these. One of the potential problems is that engineers have simplified that complex problem and therefore have erroneously produced the reservoirs. If a complete classification were available in the literature, more effort would have been made to recognize all the pore types present in a specific reservoir for better characterization and production. This paper discusses a new methodology to classify all kind of reservoirs in the real world: fracture, matrix, vugs, or combinations of those. We have developed membership functions using fuzzy logic concepts for the cementation factor m variable. We have identified at least five types of reservoirs according to pore types. All types of unconventional or conventional reservoirs are represented in this new classification system. We used core data from Southern Vietnam, Libya, the United States, Argentina, Iran, Iraq, Saudi Arabia, Colombia, and Venezuela to validate our new classification, and we are certain that it will be of great help to the engineers. Better understanding of the behavior of a specific reservoir will help increase the production and the recovery factor. We also discuss how to increase the oil or gas production as a reservoir moves from one class to another as result of hydraulic fracturing.