bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comprehensive Analysis of Caprock Failure and Associated Steam Release Events During SAGD Operations
Authors: Matsuno Shiho , Furui Kenji 
Published: April 2019

Abstract
Massive steam injection during SAGD operation may result in significant changes in pore pressure, temperature, stress and strain in the overlying caprock as well as the injected formations. These changes lead to containment breach of the caprock as reported in the steam release incident at the Joslyn Creek field in 2006. To avoid such a catastrophic event, the integrity of the caprock and risks of steam release must be properly evaluated during planning and operating SAGD wells.
In this study, a thermo-poro-mechanical model is developed to evaluate the integrity of the caprock due to temperature and pressure changes observed during SAGD operations. A commercial reservoir simulator is used to calculate changes of pore pressure and temperature during steam injection. These results are used as a part of input data for the geomechanical model that considers poro-elasto-plastic stress-strain relations of the formations. The shear failure of the rocks is determined by the Drucker-Prager criterion while the tensile failure is judged by the tensile strength of the rocks, which are used to assess the integrity of the caprock.
Our simulation results indicate that the temperature change can be extended deep into the overlying formations while the steam chamber is developed in the reservoir interval. Because the caprock is expected to have low permeability, these temperature changes lead to notable pore pressure changes in the caprock interval, which plays an important role in the stability of the caprock in the geomechancial analysis. The simulation results also suggest the importance of considering free surface, underburden, and sideburdens as well as assigning appropriate boundary conditions in the model.
Using the model developed in this work, the Joslyn field case is investigated showing the existence of failure region in the caprock layer during the steam circulation phase. These findings may explain the mechanism of the caprock failure and the resultant steam release at the surface experienced in the field. It should be noted that the analysis results indicate, not only possible shear failure events but also a possibility of tensile failure developed in the caprock interval above the steam chamber. It is also found that the geological complexity including the existence of a mudstone layer between the reservoir and the caprock affects the likelihood of the steam release event.
The caprock integrity analysis method presented in this work can help engineers evaluate risks of the containment breach during a planning phase of SAGD project. Also, using the simulation model developed in this work as a forward model, the integrity of the caprock and the development of steam chamber during SAGD operation can be monitored by surface displacement measurements by In-SAR or tiltmeters. These study results can enable effective and safe operation for future SAGD production.
Digitalization Using IIoT and Cloud Technology in Oil and Gas Upstream-Merits and Challenges
Authors: Dange Aarti , Ranjan Pallavi , Mesbah Hossam , Chokshi Rajan 
Published: April 2019

Abstract
This paper discusses the application of IIoT in various areas of oil and gas upstream. It elaborates on the drivers of IIoT, presents the advantages and benefits and describes the challenges faced as of today in the implementation. IIoT and cloud computing work hand in hand. IIoT generates huge amount of data and cloud computing provides a pathway to present this data is a useful way and travel to the end user. A detail evaluation of the investment in using this technology and its anticipated returns are demonstrated. IIoT is believed to be an emerging solution for oil and gas complexities. The main drivers behind this technology are data storage, data analytics, reliability improvement and materiality assessment and control. The application of IIoT in areas of artificial lift optimization, Supply chain in real time, cyclic steam stimulation and flow assurance is described. This technology provides real time solution for dynacards interpretation and analysis for Sucker rod pumps, operating point analysis for Electrical submersible pumps and predicted cumulative production for all artificial lift optimization; efficient planning and waste elimination for supply chain and logistics; real time steam quality and quantity check for CSS and a complete digital approach to reservoir management and flow assurance. The main benefits of this technology are reduced MTBF, high efficiency, improved HSE standards, Instantaneous control over production loss, collaborative decisions leading to fast turnaround, highly responsive supply chain and enhancing environmental footprint. This has helped substantially in real time management of wells by exception and alerts in form of intelligent alarms indicating any deviation in the expected behaviour. This has significantly brought down the non-productive time (NPT). However, this paradigm shift comes with a substantial cost. The technical challenges include the data security, protocol non-uniformity, possible data loss and limitations of redundant system.
Electrical Submersible Pump Material Compatibility for High TDS Application
Authors: Kalu-Ulu Torty , AlBori Mostafa 
Published: April 2019

AbstractThe selection of completion equipment for artificial lift string for any field in the oil and gas industry is important for the safe and reliable operations of such a field. This is critical to the management and overall profitability of the oil and gas asset, especially in areas where artificial lift is the predominant means of water injection and hydrocarbon production. This paper focuses on why it is important to understand the saline subsurface and the total dissolved solids (TDS) of the environment in which the artificial lift completion is to be deployed and its impact on equipment selection.High concentration of corrosive components in the well fluid such as hydrogen sulfide, chlorine and total dissolved solids makes the well fluid conducive for electron migration. Such migration causes heavy corrosion, especially when dissimilar metals are used in artificial lift well completions. Carbon steel tubulars and casing are easily affected by such corrosive composition and leads to premature failure of artificial lift completions, which poses safety and operational issues. This type of environment is intense in electrical submersible pump completed wells because of the electromagnetic field generated by the current passing through the electrical cable of the pump system.A combination of field and laboratory data gathering, and analysis was utilized to determine the effect of the aggressive components of the produced fluid on electrical submersible pumps assembly. The contributions of the high total dissolved solids in the conductivity of the well fluid, and in the electrochemical process for metal corrosion were analyzed. It was evident from both forms and approaches utilized in the analysis that well fluid becomes an electrolyte that provided the desired path for electron flow, which was enhanced by the magnetic field of the ESP system cable.This paper highlights the integration of three approaches of geochemical analysis of well effluent, Anodic Index differential and tubular internal coating in corrosion prevention and electric submersible pump runlife elongation in wells with corrosive compositions including high total dissolved solids.
Real-Time Automated Drilling Optimization and Operations Benchmarking Services Deliver a Step Change in Khalda Western Desert Operations
Authors: Abdel Mageed Mohamed , Awad Mostafa , Hussein Ahmed , Osman Ahmed , Siam Mahmoud , Al-Kaabi Mohammed , Rafik Ahmed 
Published: April 2019

Abstract
Egypt's Western Desert is known to be a highly complex and difficult drilling environment. Drilling in this area suffers from multiple geological risks related to formation dip and hardness, faulting, interbedding, and abrasive lithology. These conditions have typically caused drilling problems and costly delays in wells delivery. Combined with the geological difficulties, differences in the implemented drilling practices and operational procedures have led to inefficiencies and the loss of some knowledge transfer among different drilling activities and field operations.
For a proof of concept in one of its fields, Khalda endorsed a drilling automation and operations benchmarking strategy to improve the well delivery time in one of its Western Desert fields. The strategy focused on on-bottom drilling activity as well as off-bottom practices and flat-time activities. One part of this strategy endorsed a real-time automated drilling optimization workflow for the on-bottom drilling activities whereby the implementation of a change-point algorithm dictates the optimum drilling parameters to obtain the best possible rate of penetration (ROP) within the rig and drilling assembly constraints and while operating within the safe drilling dynamics window for the assembly. This approach yields the optimum ROP and prevents any possible downhole equipment failure or premature bit damage. The other part of the strategy involved benchmarking the different rig activities while drilling or doing other mechanical operations to gauge the activity of the current well compared to the offset well. This highlights any inefficiencies that can be immediately overcome, areas of improvement, and key learnings for future optimization or implementation.
This strategy was implemented in a deep gas development well in a challenging Western Desert field with known problematic offsets. The results showed a step change in well delivery whereby the well finished 3 days ahead of plan and 7 days ahead of the offset well. The real-time automation technique for drilling optimization managed to show 24% on-bottom ROP improvement in one section, enabled completing another section with a one run less than offset, and managed to mitigate the harsh drilling dynamics to prevent downhole equipment incidents. Also, the activities benchmarking helped to develop standard drilling practices that reduced inefficiencies in off-bottom drilling activities by 50% and managed to highlight key learnings and areas of development for future wells. These results helped in validating the proof of concept set at the beginning of this pilot.
Hydraulic Fracture Calibration for Unconventional Reservoirs: A New Methodology for Predictive Modelling
Authors: Pankaj Piyush , Shukla Priyavrat , Wang Wei Kan 
Published: April 2019

Abstract
Hydraulic fracture calibration in an unconventional environment is a complex process and is inconsistently practiced. Automated calibration methods are not effective or efficient in accounting for the heterogeneity and variation of constraining parameters. However, it is important to build a consistent methodology to calibrate hydraulic fractures incorporating the observed data. This paper covers the systematic "Seismic to Simulation" workflow for unconventional reservoirs to constrain a hydraulic fracture model to obtain a calibrated result.
For the hydraulic fracture calibration, injection fall-off tests, sonic logs and image logs are commonly used as the primary inputs to calibrate the geomechanical model. A new workflow is developed to be used consistently incorporating the learnings from the traditional fracture calibration methods. Impact of high stress barriers and height and pinchouts of fractures are incorporated in a geomechanical-flow model. Simultaneous matching of the observed net pressure trend, incorporating the effect of reservoir laminations on fracture height growth is made using a complex fracture model. The effect of the natural fracture networks (NFN) on pressure losses and proppant transport is also accounted for in the fracture geometry. Further, hydraulic fracture geometry is calibrated using the microseismic data. The production behavior was validated using numerical simulation for production history matching.
A case study from the Permian basin is considered for the paper. The fracture geometry and footprint obtained using the calibration workflow match very closely the observed surface and downhole measurements. We constrained the model by matching the net pressures and achieved simulated production to match within 10% error compared to the actual oil and gas production. The fracture geometry was calibrated using microseismic data and controlled by incorporating the effect of weak interfaces and laminations. This workflow successfully demonstrates hydraulic fracture model calibration using pressure matching, microseismic data and production history matching. Systematically and consistently using this workflow provides solutions for infill well planning and well spacing for asset optimization.
This paper explains a systematic fracture calibration procedure that can be easily adopted by the operators to obtain reliable results in unconventional wells. The effect of reservoir laminations and impact of natural fracture in calibrating the fracture geometry and fracture pressure trend is uniquely demonstrated in this study.
A 3-D Hydraulic Fracture Propagation Model Applied for Multiple-Layered Formation
Authors: Tang Jizhou , Zuo Lihua , Xiao Lizhi , Wu Kan , Qian Bin , Yin Congbin , Ehlig-Economides Christine , You Xiangyu 
Published: April 2019

AbstractRock layering, a critical factor in determining fracture height growth, is pervasive in the Silurian Longmaxi shale formation in the southwest of China. From field studies, engineers found that the created fracture height is lower than the required height even after they enhanced the pumping rate to a very high value. This paper introduces a coupled three-dimensional hydraulic fracture propagation model considering the effect of bedding layers and investigate the effect of shear displacements along the bedding planes on fracture height growth. Our fracture propagation models address rock deformation and fluid flow. Rock deformation is governed by a fully three-dimensional displacement discontinuity method (3D DDM). The fluid flow model employs a finite difference method able to capture fluid movement along vertical fractures and bedding planes. Additionally, a propagation criteria determines whether the fracture would penetrate bedding planes. The Longmaxi shale formation has characteristics of large burial depth, low porosity and multiple bedding layers that hamper reaching the target fracture height even after increasing the pumping rate and treatment size. Hence, our fracture propagation model is applied to study the effect of bedding layers on fracture height growth. In this paper, we selected two different fracture geometries and analyzed profiles of fracture width, pressure and two types of shear displacement discontinuities. From numerical investigations, we found that the maximum width can be obtained at the junction after the vertical fracture penetrates the bedding planes as a result of the decrement of the compressive stress acting on the bedding planes. As the fracture penetrates the bedding planes, a certain amount of fluid would leak into the planes, which leads to fracture height containment. Moreover, the slope utilized for characterizing the correlation between leak-off volume and fracture height, is regarded as a tool to identify the number of BPs that fracture penetrates through. This paper illustrates the extensive application of our coupled hydraulic fracture propagation model for the Silurian Longmaxi shale formation with multiple bedding layers. Shear displacements along the bedding planes are regarded as a primary mechanism of fracture height containment.
Extended Acoustic Sand Monitoring Helps to Understand Ceramic Sand Screen Failure: A Case Study
Authors: Riyanto Latief , Sidek Sulaiman , Hugonet Vincent , Yusuf M Hafizi , Salleh Nurfarah Izwana , Ambrose Jonathan Luke 
Published: April 2019

Abstract
Many oil and gas fields have long been suffering from sand production due to either the absence or failure of primary well sand control. To avoid mobilizing costly work-over rig to pull out the tubing, operators have tried various thru-tubing remedial sand control. The well's condition such as sands accumulation and space constraints due to small inner diameter of tubing always make this remedial job challenging. It is not surprising that the results are not all satisfactory.
Among the industry-recognized remedial sand control, Stand Alone Screen (SAS) is the simplest and the cheapest method. Many SAS have been installed but most were failed with screen erosion as the main failure mechanism. Flowing high velocity fluid with sands wears out the screen fast making it impossible for the sands to bridge and to create formation sand pack around the screen.
Ceramic Sand Screen (CSS) technology which was recently introduced to the industry aims to address this erosion issue. Having more than ten times hardness of stainless steel, sintered silicon carbide ceramic material in CSS offers superior resistance to wear. The pilot was conducted by installing CSS in three (3) selected wells with sand production history. While waiting for acoustic sand monitoring installation, the wells were put on production with the same choke size and regular manual samplings were conducted to monitor the sand production.
The acoustic sand monitoring campaign began in November 2017. Sands production was carefully monitored during the process to determine the final choke size at which the wells would continuously produce. In the middle of the campaign due to adverse weather conditions, all non-essential personnel had to be abruptly demobilised from the field leaving acoustic sensors hooked-up to the respective flow line. This gave opportunity to have unplanned extended sand monitoring window.
Loss of Primary Containment (LOPCs) occurred in two CSS wells not long after that. In one the choke body was heavily eroded and the other well had a punched hole at the first elbow of the flowline. These incidents prompted full investigation to be conducted. This included pulling out the installed CSS and performed tear down analysis. Acoustic sand monitoring that just happened to be available in one of the wells proved to be critical in understanding the CSS failure.
The paper presents briefly on the CSS pilot project, the chronology of events until the incident, sands production trend from the acoustic sand monitoring. Using all available information, the paper provides details analysis on CSS failure mechanism.
Tight Coupling of a Reservoir Simulator With a Transient Flow Well Model: A Field Case Application to Optimise Cyclic Production in Liquid Loading Regime for a Tight Gas Field
Authors: Rasoanaivo Ombana , Danquigny Jacques , Henry Pierre , Hopkinson David , Liu Adeline , Marty Jacques , Marmier Rémy 
Published: April 2019

Abstract
Using a software integrator, a commercial reservoir simulator is tightly coupled with a commercial Transient Well Model. This is required when transient reservoir behaviour interacts with transient wellbore phenomena. It is the case in a tight gas field which is being developed since 2012 in China; long natural cycles of gas production in liquid loading regime followed by period of low or quasi nil-gas production are observed. Cyclic production is also being implemented to optimize the average gas production. In both cases, usual decline curve analysis is no longer valid. And computing long term production forecast becomes a challenge. The innovative application presented in this paper is an optimization of Cyclic Production in Liquid Loading Regime of a tight gas reservoir by coupling transient modelling of reservoir and wellbore.
A workflow is implemented in the software integrator RESOLVE which enables the coupling between a well and its multiple hydraulically fractured reservoirs. It ensures consistent results between the reservoir model and the transient well model in terms of mass flow rate, transient inflow performance and bottom hole flowing pressure. It also enables to visualize the cross-flow which occurs between the two reservoirs, and some water imbibition into the matrix during shut-in periods.
Tested on various reference wells, this new methodology represents properly the historical behaviour of the wells during steady-state flow and during self-killing periods. When modelling cyclic production, various shut-in / restart criteria can be handled by the workflow. It enables to optimize the average production of the wells and deliver some guidelines to the field operation teams. This is a great achievement compared with the need to implement long "cyclic production testing" campaigns.
Also, two-month coupled cyclic production modelling is performed at regular yearly intervals. Combining these long term production forecasts with the evolution of "average static pressure vs. cumulative gas production" derived from reservoir standalone long-term forecast, enables to compute reliable long term production forecast which accounts for cyclic production in liquid loading regime. The current results show significantly larger production than the one derived from usual decline curves.
Overall, the study is a leap forward in understanding transient well and reservoir interactions in order to improve field Estimated Ultimate Recovery. This field tested methodology can also be applied to many other situations when well instabilities interfere with reservoir transient behaviour (gas-lift heading, interference between unstable outflow and multi-layers inflow behaviour). To our knowledge, it is a "World First" of a coupling between a full commercial reservoir simulator and a commercial transient wellbore software.