The well decommissioning and abandonment is not only complex, costly, and critical for environment but is also a quickly growing problem for the entire oil and gas industry as the number of wells approaching end of field life is rapidly increasing. All that generates a massive assets management problem. Worse yet, in some of the wells considered as properly abandoned oil leaks are discovered many years later, sometimes polluting the drinking water aquifer or sea water. The well decommissioning procedures require a passive monitoring tool, helping to identify poor cement jobs and leaks.
Rock deformation and fracturing is an important causal mechanism that can compromise well integrity. Geomechanical simulation is a valuable tool to investigate this mechanism and connect well tubular designs with reservoir development strategies. Utilizing relevant field examples, this paper describes a work flow in these regards.
Two example simulation approaches are described. One is to use a composite casing/cement/rock model in a reservoir of complex geology to compute maximum strain, dogleg severity, and ovality/restriction in the casing along the well trajectory. Different well design parameters, such as casing size, grade, and cement thickness, can be iterated against different reservoir production strategies. All these efforts are to arrive at an optimized design. The other approach is to calculate localized shear displacement along a weak plane that will be imposed on well tubulars during reservoir activities. The resulting design is optimized by altering well placement and stimulation/production schedules.
The above workflow has been proven in various field applications. Experience is shared in this paper. It is hoped this work can demonstrate that the optimal management of well integrity can be achieved by an integrated approach that designs appropriate tubulars and adjusts reservoir activities. Placing well tubulars in the context of rock deformation, geomechanical simulation is the best tool to connect the reservoir activities with the well tubular designs and therefore, can potentially offer a cost-effective well integrity management program.
Phi, Thai (University of Oklahoma) | Elgaddafi, Rida (University of Oklahoma) | Al Ramadan, Mustafa (University of Oklahoma) | Ahmed, Ramadan (King Fahd University of Petroleum & Minerals) | Teodoriu, Catalin (University of Oklahoma)
Most untapped promising energy resources in the world are associated with extreme downhole environment conditions. Applying the conventional method of well construction and operation for extreme downhole conditions poses severe challenges for the safety and longevity of the well. Governments and independent standardization organizations have developed several regulations regarding maintaining well integrity. Nevertheless, methods of completing and operating Extreme High-Pressure-High-Temperature (XHPHT) wells as well as geothermal wells have not yet been standardized. Preserving well integrity throughout the life cycle of a well is very crucial. Failure in well integrity can lead to huge operational and environmental risk and increase the energy cost.
This paper critically reviews the causes and solutions of well integrity issues in XHPHT and geothermal wells. After giving an overview of these wells, the paper discusses the well barriers at different ages. It also presents the conditions that lead to well integrity issues. Furthermore, the article discusses comprehensively the influence of acidic environment on cement and casing degradation at HPHT and summarizes the most recent research findings and development strategies in mitigating the integrity issues.
Previous studies revealed that the integrity of well barriers is highly affected by the degradation of drilling and completion fluids, cement, and tubular materials. The main causes of the well integrity loss are the lack of understanding of downhole conditions, inappropriate well construction practices, poor selection of the casing material and cementing type as well as inadequate design verification and validation on the downhole specimen. The well barriers are inter-related to each other as the destruction of one barrier may lead to the dismantling of the entire well barrier envelope. The XHPHT and geothermal wells share numerous similar barrier integrity issues, but they also have some unique problems due to the nature of their own operations. Although there is a significant advancement in solving the well integrity issues for the extreme downhole conditions, a sizable technology gap still exists in constructing and operating XHPHT and geothermal wells.
The current market conditions and the advancement in technologies are making the development of XHPHT wells more economically feasible. This paper serves as a review of the current research and development regarding well integrity issues for XHPHT and geothermal wells.
Soroush, Mohammad (RGL Reservoir Management, University of Alberta) | Roostaei, Morteza (RGL Reservoir Management) | Fattahpour, Vahidoddin (RGL Reservoir Management) | Mahmoudi, Mahdi (RGL Reservoir Management) | Keough, Daniel (Precise Downhole Services Ltd) | Cheng, Li (University of Alberta) | Moez, Kambiz (University of Alberta)
Accurate prediction of flow regime and flow profile in wellbore is among the main interests of production engineers in the quest of optimizing wellbore production and increasing reliability of downhole completion tools especially in SAGD projects. This study introduces a methodology for wellbore monitoring by detecting flow phase and flow regime. In order to develop this method, an advanced multi-phase flow injection experiment was designed and commissioned.
A flow injection setup was developed to test distributed fiber optic sensor installation under different operating conditions, including multi-phase flow (oil, brine and gas), and flow fraction scenarios. Different signal processing methods were applied to extract meaningful features and filter the noise from the raw signals. A statistical analysis was performed to assess the trend of the driven data. Then, typical SAGD models were simulated to assess the results of experimental setup for scale-up purpose and determination of local breakthrough of steam along the well.
Results showed that the Distributed Acoustic Sensing (DAS) data contains different levels of signals for each phase and flow regime. We also found that some level of uncertainties is involved in relating the flow regime and DAS information which could be resolved by improving the sensor installation procedure. In addition, the application of data-driven machine learning methods was found necessary to interpret the signal patterns. Initial results have shown that steam breakthrough along the well can be detected using real time DAS high energy/frequency signals. It can be concluded that including the DAS along with Distributed Temperature Sensing (DTS) is necessary to provide a better picture of steam conformance and SAGD wellbore monitoring. The limitations of the current experimental setup restricted further conclusions regarding the hybrid DAS and DTS application.
This paper is a part of an ongoing project to address the application of the combined DAS and DTS in SAGD projects. The ultimate goal is a downhole monitoring system to oversee the flow phase, flow regime and sand ingress in thermal application. The next phase will address the required improvements for developing a flow loop to handle high temperatures, include sand production and mimic thermal operation conditions.
Deisman, Nathan (University of Alberta, Edmonton, CANADA) | Flottmann, Thomas (Origin Energy, Brisbane, AUSTRALIA) | Guo, Yujia (University of Alberta, Edmonton, CANADA) | Hodder, Kevin (University of Alberta, Edmonton, CANADA) | Chalaturnyk, Richard (University of Alberta, Edmonton, CANADA) | Leonardi, Christopher (University of Queensland, AUSTRALIA)
Establishing bulk rock properties in friable material such as coal is difficult simply because retrieval of a sufficient sample is challenging particularly because fractured/cleated coal disintegrates in the coring process. This paper describes the use of synthetic rock with embedded simple discrete natural fracture (DFN) systems to establish key rock mechanical properties in synthetic rocks with varying DFN complexity and varying degrees of depletion. The ultimate goal of the work aims to inform late-life technology choices in the depleted CSG reservoirs.
To achieve this, we measured the deformation behaviour of the printed intact matrix and the printed interface (fracture) and expanded the rock mass equivalent continuum theory by
Five horizontally printed specimens were not reproducible and had an average Young’s Modulus of 4.95 GPa. The horizontally printed specimens with the same one and two fracture system, were not repeatable, and had measured fractured stiffness of 181.2 and 81.5 MPa/m for one fracture specimens and 114.8 and 142.9 MPa/m for two fracture specimens. The five vertically printed specimens were reproducible, with an average Young’s Modulus of 5.37 GPa. The one fracture system had a fracture stiffness of 86.6 and 97.8 MPa/m and the two fracture had a fracture stiffness of 58.3 and 63.8 MPa/m. The equivalent continuum theory suggests that the joint stiffness should be fracture intensity (P32) independent, therefore equal, which was not the case. The change in volumetric strain due to change in isotropic stress was also measured to calculate the bulk modulus of a specimen with zero, one and two persistent vertical fractures. Results from the testing showed that as the fracture area increased, the volumetric strain behaviour was increasingly nonlinear, until a stress magnitude where the bulk modulus became linear and equal for zero, one, and two fracture specimens (3.68, 3.68, 3.51 GPa).
Results show reduction in modulus as a function of P32i and P32 which, however, does not fit the developed theory but is promising to continue the work with the 3D printed specimens. Adjustments to the controls on the printing process may be made to reduce the specimen variability and improve repeatability. In all fractured cases, the synthetic rocks showed initial non-linear behaviour, which was expected, and important for future work and analysis. Therefore, the results of this program are sufficient to formulate a broader test matrix that will be conducted to establish fundamental rock physical parameters and in particular bulk compressibility of coals of varying permeability related to P32/P33 characteristics.
Bailey, Adam H.E. (Geoscience Australia) | Jarrett, Amber J.M. (Geoscience Australia) | Bradshaw, Barry (Geoscience Australia) | Hall, Lisa S. (Geoscience Australia) | Wang, Liuqi (Geoscience Australia) | Palu, Tehani J. (Geoscience Australia) | Orr, Meredith (Geoscience Australia) | Carr, Lidena K. (Geoscience Australia) | Henson, Paul (Geoscience Australia)
The Isa Superbasin is a Paleoproterozoic to Mesoproterozoic succession (approximately 1670-1575 Ma), primarily described in north-west Queensland. Despite the basin's frontier status, recent exploration in the northern Lawn Hill Platform has demonstrated shale gas potential in the Lawn and River supersequences. Here, we characterise the unconventional reservoir properties of these supersequences, providing new insights into regional shale gas prospectivity.
The depths, thicknesses and mappable extents of the Lawn and River supersequences are based on the 3D geological model of Bradshaw et al. (2018). Source rock net thickness, total organic carbon (TOC), kerogen type and maturity are characterised based on new and existing Rock-Eval and organic petrology data, integrated with petroleum systems modelling. Petrophysical properties, including porosity, permeability and gas saturation, are evaluated based on well logs. Mineralogy is used to calculate brittleness (see also
Abundant source rocks are present in the Isa Superbasin succession. Overall, shale rock characteristics were found to be favourable for both sequences assessed; both the Lawn and River supersequences host thick, extensive, and organically rich source rocks with up to 7.1 wt% total organic carbon (TOC) in the Lawn Supersequence and up to 11.3 wt% TOC in the River Supersequence. Net shale thicknesses demonstrate an abundance of potential shale gas reservoir units across the Lawn Hill Platform.
With average brittleness indices of greater than 0.5, both the Lawn and River supersequences are interpreted as likely to be favourable for fracture stimulation. As-received total gas content from air-dried samples is favourable, with average values of 0.909 scc/g for the Lawn Supersequence and 1.143 scc/g for the River Supersequence
The stress regime in the Isa Superbasin and the surrounding region is poorly defined; however, it is likely dominated by strike-slip faulting. Modelling demonstrates limited stress variations based on both lithology and the thickness of the overlying Phanerozoic basins, resulting in likely inter- and intra-formational controls over fracture propagation. No evidence of overpressure has been observed to date, however, it is possible that overpressures may exist deeper in the basin where less permeable sediments exist.
This review of the shale reservoir properties of the Lawn and River supersequences of the Isa Superbasin significantly improves our understanding of the distribution of potentially prospective shale gas plays across the Lawn Hill Platform and more broadly across this region of northern Australia.
Li, Shi Zhen (China Geological Survey) | Wang, Yue (Schlumberger) | Liu, Xu Feng (China Geological Survey) | Zhao, Xian Ran (Schlumberger) | Zhao, Hai Peng (Schlumberger) | Xu, Lei (GeoReservoir Research)
Production from the Lower Silurian Longmaxi formation shale gas reservoir in Fuling, Changning, and Weiyuan fields in the Upper Yangtze area has reached over 10 billion cubic meters. The Wufeng-Gaojiabian formation of the Lower Yangtze area is a new area of shale gas exploration in China. The objective of this study was to evaluate the potential of the shale gas reservoir in this area.
An innovated lithofacies classification method was developed that incorporates total organic carbon (TOC), grain size, matrix mineralogy, and lithology. An integrated workflow with input derived from microscopic observation, thin section analysis, ion-milled backscatter scanning electron microscope (BSE), X-ray diffraction, X-ray fluorescence (XRF) element analysis, gas adsorption test, and other organic geochemical experiments provides significant advantages for lithofacies classification. This paper applies an advanced technology in pore geometry analysis of various lithofacies, which has demonstrable value in guiding the shale gas exploration in new areas such as the Lower Yangtze area.
Reservoir characterization was performed on an exploration well in the Tangshan area of China. The lithofacies of the Wufeng–Gaojiabian formation shale can be classified into four types: organic-rich argillaceous/siliceous shale, organic-rich/clay-rich siliceous shale, organic-rich siliceous shale, and organic-lean micritic dolomitic mudstone. The first three lithofacies types have potential for shale gas accumulation, and the organic-rich siliceous shale has the best potential. Careful BSE analyses were done on different shale samples, and an interactive algorithm was used to determine the porosity of the organic-rich siliceous shale, which ranges from 5% to 7%. The shale shows heterogeneity in pore geometry; intergranular pores and intragranular pores dominate the pore spaces. The pores are well connected, but organic pores are rarely seen under microscope. Nutrition adsorption tests performed on organic-rich siliceous shale samples show dual pore size distribution characteristics; one set ranges from 2 to 60 nm, and the other ranges from 85 to 125 nm. Macropores dominate the pore space and account for 53% of the total porosity. Mesopores account for 28%, and micropores account for 19%. The percentage of various pore size gives insight into the potential shale reservoir.
The comprehensive reservoir characterization of the shale gas reservoir of the Wufeng-Gaojiabian formation in the Lower Yangtze area, which investigated depositional settings, organic geochemical features, lithofacies, and reservoir properties, suggests that the Lower Yangtze area may have potential as a shale gas exploration frontier. The workflow can also be applied to other shale gas plays in China.
Shale has been a major destination for unconventional hydrocarbon resources for its wide stratigraphic coverage as well as high volumetric hydrocarbon potential. Contemporary success in North American shale plays has intrigued operators worldwide in shale exploration. Organic richness has been a key factor to determine the potential of shale as it is proportional to the amount of hydrocarbon likely to be generated and stored in available spaces within the shale. The other important factor in this context is shale brittleness as it indicates how fracable the potential shale is. Attempts are made here by strategically using standard wireline logs in order to evaluate potential of Eocene Vadaparru Shale in Krishna Godavari Basin, India qualitatively and quantitatively.
The technique used in this study involves identification of organic lean ‘clean shale’ interval and establishing a ‘clean shale’ relation of resistivity as a function of compressional sonic transit time in the study wells, as both the logs respond comparably to shale and its organic content. Using this relation a proxy ‘clean shale’ resistivity log is generated in shale and compared with measured wireline resistivity. A positive separation between calculated and measured resistivity is then assessed as proportionate shale organic richness, owing to the presence of relatively less dense (corresponding to longer sonic transit time) and more resistive organic content. Shale brittleness is predicted from Young's modulus and Poisson's ratio using compressional, shear and Stoneley wave velocities obtained from sonic measurements, assuming transversely isotropic nature of Vadaparru Shale.
The Eocene marine transgressive Vadaparru Shale is a dominant stratigraphy in KG basin as evident from seismics and drilling. Petrophysical analyses in study wells indicated appreciable brittleness within Vadaparru Shale. The organic richness i.e. amount of positive separation between calculated and measured resistivity combined with brittleness quantitatively indicate fair to excellent unconventional potential of Vadaparru Shale. Considerable thickness, Type-II, III kerogen content and geochemical measurements support the study and highlight it as a promising ‘shale reservoir’ destination. In the context of rapidly growing energy demand of India Vadaparru Shale can be considered as serious unconventional player.
Overall this study presents quick strategy for shale potential quantification, thus allowing operators to focus spatially in the quest of unconventional hydrocarbon resources.
Undershultz, Jim (University of Queensland) | Mukherjee, Saswata (University of Queensland) | Wolhuter, Alexandra (University of Queensland) | Xu, Huan (China University of Petroleum, East China and The University of Queensland) | Banks, Eddie (Flinders University) | Noorduijn, Saskia (Flinders University) | McCallum, Jim (University of Western Australia)
There is an increasing need to understand the influence of faults in both gas production performance and the resulting potential impact on adjacent groundwater resources.Faults can exhibit a wide variety of hydraulic properties. Where resource development induces changes in pore pressure, the effective stress and thus the permeability can be transient. In this study, w explored strategies for characterizing fault zone properties for the initial purpose of evaluating gas production performance. The same fault characterization can then be incorporated into regional groundwater flow models to more accurately represent stress, strain and the resulting transmissivities when assessing the impact of gas development on adjacent aquifers.
Conventional fault zone analysis (juxtaposition, fault gouge or shale smear, fault reactivation) is combined with hydrodynamic analysis (distribution of hydraulic head and hydrochemistry) and surface water hydrology and hydrochemistry to evaluate across fault or up fault locations of enhanced hydraulic conductivity at specific locations of complex fault systems.
The locations of identified vertical hydraulic communication from the hydraulic analysis are compared with the fault zone architecture derived from the 3D seismic volume overlain with the
Bian, Changrong (Sinopec Exploration & Production Research Institute) | Zhang, Dianwei (Sinopec Exploration & Production Research Institute) | Shen, Feng (GeoReservoir Research) | Wo, Yujin (Sinopec Exploration & Production Research Institute) | Sun, Wei (Sinopec Exploration & Production Research Institute) | Li, Jingliang (GeoReservoir Research) | Han, Juan (GeoReservoir Research) | Li, Shuiquan (GeoReservoir Research) | Ma, Qiang (Sinopec Exploration & Production Research Institute)
Delineating geometry of natural fractures realistically and understanding fracture stress sensitivity help to optimize well placement and well spacing design in shale gas reservoirs. This paper presents a methodology for building 3D hybrid discrete natural fracture network (DFN) models and using an analytical model to assess reactivation potential of natural fracture in the Longmaxi shale, Sichuan Basin.
Small-throw faults and natural fractures ranging from seismic scale to well scale in shale reservoirs have important effects on the success of horizontal drilling and hydraulic fracturing. Seismic geometric multi-attributes at different resolution scales are used to classify seismic facies according to the degree of fracturing. Small-throw faults are delineated using seismic facies and validated against drilling data. We develop a discrete natural fracture network (DFN) model at the seismic scale by meshing fracture lineaments tracked from an enhanced curvature attribute. Fracture topologies are used for fracture connectivity analysis to build local fracture networks along and around the horizontal wellbores. Diffuse fractures at the small scale are modeled with curvature attributes and well data analysis under the constraint of the seismic facies. The analytical model incorporates fracture properties and geomechanical model to describe the deformation of natural fractures due to hydraulic fracturing. Fracture stress-sensitivity are assessed based on changes of fracture volumes under different stress conditions. Characterized reactivated local fracture networks at different scales along the horizontal wells are used to map out volumetric extent of zones with potential to develop tensile and shear deformation during hydraulic fracturing. Available microseismic data from the hydraulic fracture stimulation of the reservoir is used to validate the fracture models.
Our stress sensitivity analysis indicates that reactivation potential of natural fractures varies considerably, mainly depending on natural fracture size and orientation, rock mechanical properties and anisotropy of horizontal stresses. DFN models reveal that fracture concentrations are correlative with the footprint of observed microseismic events. Comparison of 3D natural fracture models with the microseismic event distribution shows that vertical variation of fracture properties in the laminated shale reservoir adds complexity for fracture propagation.
A case study is used to illustrate the efficiency of the methodology. Fracture models at different scales and associated fracture stress-sensitivity can be used as a predictive tool for locating new wells and completion design in shale gas reservoirs.