bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Well Location and Fault Conductivity on Geomechanical Stability in a Faulted Oil Field
Authors: Zhao Xiaoxi , Jha Birendra 
Published: April 2019

Abstract
Production and injection activities in heavily faulted or stress-sensitive reservoirs can generate multiple recurring fault slip events that resemble the natural seismic cycle of well-known faults in terms of stress accumulation and relaxation periods. We hypothesize that the relationship between well location and fault properties holds the key to understanding such induced cyclicity of reservoir-scale faults and must be examined to monitor fault stability and fluid recovery during production/injection. This paper uses a coupled multiphase flow and geomechanics framework to investigate the effect of well type (production or injection), well location and fault conductivity on the fault slip induced by production and injection activities. We consider one injection or production well in a confined reservoir located in the hanging wall block of a normal fault. For both injection and production cases, we observe that as the well-to-fault distance decreases, the induced Coulomb stress on the fault increases at a faster rate, and the fault slips earlier. For a fixed duration of production or injection, the slip area is larger at the end of simulation when the well-to-fault distance is smaller. Well type affects the time to failure and the cumulative slip. The Coulomb stress reaches the Mohr-Coulomb failure condition slower during production compared to injection. Interseismic slip and the stress relaxation period are shorter for production compared to injection. We observe a larger stress build-up, slip and relaxation cycles in production case. Comparison of results from the non-conductive and conductive fault scenarios suggests that higher conductivity stabilizes the fault and delays slip. We conclude that the possibility of producing or injecting close to unknown/unmapped faults in stress-sensitive reservoirs necessitates coupled geomechanical studies to evaluate the effects of existing and planned well locations and well rates on the stability of faults with uncertain locations and properties. Our framework can be applied to such reservoirs to monitor reservoir performance and geomechanical integrity.
Integrating Multiple Pressure Build-Up Tests to Characterize the Behavior of Dynamically-Closed Fractures
Authors: Luo Le , Cheng Shiqing , Lee John 
Published: April 2019

Abstract
As reservoir pressure decreases with production, the conductivity of hydraulic fractures will also change. These changes in fracture conductivity may impact well productivity significantly, so it is important to investigate the behavior of dynamic fractures. Also, characterzing and forecasting dynamic fracture properties can help with well-spacing design and adjustments in development stategy.
This paper proposes a semianalytical model to characterize the behavior of dynamically-closed fractures through pressure buildup test analysis. Time-dependent and space-varying fractures are considered in the modeling process. We note that, although time-dependent fractures are investigated in this study, calculation of variable-rate pressure buildup response is still based on the solution of linear differential equations governing fluid flow in a reservoir. Hence, the convolution theorem can be utilized to deal with the transient pressure buildup data. We recommend a modified exponential function to represent time-normalized fracture conductivity. The representation of dynamic fracture conductivity was handled with a stair-step function, and the fracture-flow model was solved numerically. Pressure buildup responses were obtained by coupling with an analytical matrix-flow model.
When fracture conductivity is time-dependent, the pressure drop during the bilinear flow regime will increase. We discuss the effects of fracture conductivity changes and production history on the resulting pressure buildup response. We present a synthetic case study which demonstrates that pressure build-up tests conducted in different years allow us to diagnose changes in fracture conductivity during production history. The results of our interpretations can generate an equation that describes the relationship between fracture conductivity and time. Using the results of multiple pressure buildup test analyses, this method can be applied to forecast fracture characteristics in specific formations of interest.
Integrated Modeling of In-Situ Combustion from Laboratory to Field Scale
Authors: Zhu Zhouyuan , Liu Canhua , Gong Yuning , Song Yang , Liu Yanni , Zhao Renbao , Chen Zhangxin 
Published: April 2019

Abstract
Integrating in-situ combustion from laboratory scale into field scale has always been challenging, due to difficulties in deciding the reaction model and Arrhenius kinetics parameters, together with erroneous results observed in simulations when using large sized grid blocks. Based on the methodology proposed in our previous work, we present a case study on the successful simulation heavy oil in-situ combustion from laboratory experiment history match to field scale process modeling.
We choose the ongoing PetroChina Liaohe Du-66 block heavy oil in-situ combustion project as the case of study. The workflow includes kinetic cell and combustion tube laboratory experiments, test data interpretations, establishing the kinetic reaction model, isoconversional activation energy analysis, history match of the experiments, and finally field-scale reservoir simulation using the proposed upscaled reaction model. The reaction upscaling methodology uses standard thermal reactive reservoir simulator with a different upscaled reaction source or sink term.
First, we established a suitable kinetic reaction model, deduced the necessary information from the kinetic cell experiment, and performed detailed history match of the kinetic cell to obtain matched Arrhenius kinetics parameters. Second, the laboratory combustion tube experiment was history matched to further determine other simulation parameters and also to calculate the fuel amount per unit reservoir volume. We have found matching of the experiments highly ill-conditioned with multiple possible inputs, if only matched to combustion tube experiment without information from the kinetic cell. Finally, we upscaled the Arrhenius kinetics to upscaled reaction models for field scale simulations. The model with upscaled models showed consistent results with different grid sizes, which is favorable for field scale simulations. Field scale production forecast was conducted for the Du-66 block in-situ combustion process in Liaohe oil field, using computationally affordable grid block sizes.
In conclusion, this work shows the successful implementation of the integrated simulation methodology on a major in-situ combustion project in China, which demonstrates the practical workflow for predictive modeling of in-situ combustion from laboratory scale to field scale.
Event Recognition on Time Series Frac Data Using Machine Learning
Authors: Ramirez Alberto , Iriarte Jessica 
Published: April 2019

Abstract
Hydraulic fracturing pumping data is recorded and mapped in the field at one-second intervals. The designation of the stage start and end time is very important because these boundaries govern summary calculations, such as pressure, rate, and concentrations. Manual selection of staging flags is often very time consuming and prone to inaccuracies due to the lack of uniform selection and interpretation methods across the industry. The purpose of this study is to demonstrate the automation process to identify accurate and consistent stage start and end times in a high-frequency treating plot using machine learning algorithms.
This study is based on the analysis of metered high-frequency treatment data coupled with supervised machine learning algorithms. The pumping dataset includes treating pressure, slurry rate, and clean volume for 179 stages, for a total of 1,530,445 rows of data per variable. Sixty-six percent of the data were used to train the model, eight percent were used to validate the model, and the remaining twenty-six percent were used to test it. Subject matter expertise, taking into account user-defined start/end time flags, was used to train the algorithm.
Pumping data behaves very differently than traditional time-series data such as weather, stock prices, or population growth. The features examined are not affected by time but by physical events, so the correlation or dependency between features can affect accurate pattern recognition. To allow the algorithm to run leaner, the dataset was pre-processed using loss functions, smoothing techniques, and the rate of change of the main data channels. To understand how data may impair the predictions and to evaluate different model performances, we tested two classification algorithms: logistic regression and support vector machine.
Classification techniques were used to generate an accurate suggestion of where the pumping of a hydraulic fracturing stage starts and ends in a high-frequency treating plot. Results show that flag predictions have a training and validation accuracy of approximately 90 percent using logistic regression algorithms. The predicted flags were within 10 seconds of the manual selected flag. A limitation of this method is that it requires periodic retraining with new field data to improve the prediction robustness and to maintain high accuracy.
Accurate start and end time selections make it not only viable to process large volumes of fracture treatment data but also reduce the time spent reviewing field data for quality control. Petroleum engineers need to continue their focus on optimizing their systems with the greatest possible efficiency. Leveraging common analytical methods combined with the large, structured datasets that are readily available provide impressive results without extensive programming knowledge.
Revisiting Kelvin Equation for Accurate Modeling of Pore Scale Thermodynamics of Different Solvent Gases
Authors: Al-Kindi Ilyas , Babadagli Tayfun 
Published: April 2019

Abstract
Understanding the thermodynamics of fluids in capillary media is essential to achieve a precise modeling of EOR applications such as hybrid (with thermal methods) and sole solvent injection processes. The theoretically derived classical Kelvin equation describes the influence of surface tension, contact angle, pore radius, and temperature on vapour pressures. The deviation of propane vapour and condensation pressures from this equation was determined experimentally by measuring them on capillary/porous media with various sizes and types, namely Hele-Shaw glass cells, silica-glass microfluidic chips, and rock samples. The experimental data were also compared with the vapour pressures obtained for the bulk conditions. The gap thicknesses in Hele-Shaw cells were 0.13 and 0.04 mm whereas the medium size in micromodels was ranging from 142 to 1μm. The results showed that vapour and condensation pressures of propane recorded in the experiments were comparatively close to the bulk vaporization pressure and calculated vapour pressures from the Kelvin equation. Conversely, vapour pressures obtained from rock samples were noticeably lower than bulk vapour pressures.
Practical Automated Detection of Remaining Oil in Mature Fields Using Production and Geology Data
Authors: Arslan Izzet , Rajabi Farzaneh , Ibrahima Fayadhoi 
Published: April 2019

Abstract
In all development phases of brownfields, identifying sweet spots and the potential remaining oil in place to be recovered is a cornerstone of reservoir management studies and field development operations. This becomes even more imperative for mature waterfloods, where the increasing water cut hinders the ongoing oil production.
The current algorithms in waterflood network-based models are capable of building and matching a reservoir model by employing reduced physics data-driven approaches. These schemes estimate the saturation in the entire field; however, the next step in those approaches is adding a fully-integrated and closed loop automated workflow to model the remaining hydrocarbon volumes.
The new data analytics approach presented is a systematic bottom-up approach in which the field data, including injection and production, well perforations, pressure history, geological and fluid properties and original oil in place, are integrated. The remaining hydrocarbon thickness and saturation calculated from this methodology are key to target future reactivation and recompletion candidates, therefore potentially reducing CAPEX and OPEX. This automated methodology is robust to handle not only the waterflood but all the development phases. Moreover, it is much faster than the ubiquitous history-matching processes, which require several months on average to be completed. To this end, we have validated the results by a blind test approach to increase the confidence in using the methodology.
This proposed workflow greatly improves the assessment capabilities to locate the remaining hydrocarbon resources, and therefore is pragmatic for the prediction of the most prolific future production targets.
Landing String Slip System Numerical Analysis to Evaluate Pipe Crushing Problems
Authors: Mirasdar Shailesh , Deshpande Kedar , Amezaga Federico 
Published: April 2019

Abstract
As the technology of offshore drilling improves, the industry seeks oil in deeper waters, inhospitable environments, and challenging climatic conditions. The new harsher drilling conditions warrant modifications to existing downhole tools and development of new technology using numerical simulations. The landing-string slip system (LSS) is a tubular-holding tool in which slips act as a spider to grip landing strings or drill pipe during makeup or breakout of drill strings. This paper presents a detailed numerical methodology to evaluate the safe pull-load rating for pipe held in the LSS. The method uses advanced computational techniques and applies ASME section VIII Division 2, Part 5 design criteria to corroborate numerical findings.
First, laboratory tests were conducted on pipes with varying sizes to estimate the pipe load-carrying capacity without causing operational failure. Strain gauge measurements were taken at regular intervals during the laboratory tests. A detailed finite element analysis (FEA) using an explicit solver was conducted to computationally simulate the LSS operating mechanism. In particular, non-linear FEA was conducted on the 45° pipe section to simulate slip indentations followed by axial loading of the pipe. The maximum axial load applied on the pipe after slip indentation corresponds to 100% yielding load. ASME Section VIII Division 2, Part 5 design criteria involving ratcheting analyses was applied towards numerical studies at a 100% yield loading condition.
Extensive FEA studies were conducted to check the validity of the numerical results with laboratory testing and then to understand the LSS capabilities for field-based loading scenarios. FEA studies predicted stresses within 10% of the values obtained through laboratory measurements. Simultaneously, FEA plastic strain patterns revealed that the spread of plastic strains is highly localized to the penetrated surfaces of the pipe and is also generally absent through the thickness for load capacity up to 100% of the pipe yield strength. Based on ASME section VIII Division 2, Part 5, a ratcheting analysis was conducted that involved loading and unloading cycles on the pipe to monitor the plastic strain propagation. The ratcheting analysis determined that for a 90% yield load, the LSS safely held pipe for operational purposes.
The ratcheting evaluation was not possible using laboratory tests because of the cost and time required for a cyclic loading test. This paper introduces ASME section VIII Division 2, Part 5 design criteria to develop confidence in numerical results and justify the LSS design.
A Transient Two-Phase Flow Model for Production Prediction of Tight Gas Wells with Fracturing Fluid-Induced Formation Damage
Authors: Wu Yonghui , Cheng Linsong , Huang Shijun , Fang Sidong , Killough John Edwin , Jia Pin , Wang Suran 
Published: April 2019

Abstract
A major concern with hydraulic fracturing in tight formation is the fracturing fluid-induced formation damage (FFIFD) for the high capillary pressure and the presence of water-sensitive clays. Analytical models are good choices for formation damage evaluation comparing to computationally expensive numerical simulations. However, many analytical models are limited to single-phase flow and the FFIFD is seldom addressed. This paper presents a semi-analytical model for this problem with the consideration of both two-phase flow and FFIFD.
A triple-porosity model is modified to capture the formation damage caused by fracturing fluid, and mainly two modifications are made. First, two-phase flow is assumed in the fractures to capture the choking effects. In addition, a low permeability fracturing fluid invasion layer (FFIL) is used to characterize leakoff caused clay swelling and polymer adsorption in the matrix pores. The analytical solution is obtained in the Laplace domain, and a successive iteration is used to update the dynamic parameters by coupling the flowing material balance equations.
The precision of the semi-analytical model is validated using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that gas production is greatly affected by FFIFD. The effect of two-phase flow on gas production is mainly within the early several days. The permeability and width of FFIL have a significant effect on gas production. Gas production rate in the early hundreds of days will be much larger with thinner FFIL and larger permeability, but it will decline sharper later for the faster depletion. The field case shows that different models can match the production data, but the interpreted parameters and the physical meaning are totally different. In addition, a good match will be obtained with FFIFD and two-phase flow effects considered in the model.
A simple yet versatile semi-analytical model is proposed in this paper for production prediction and analysis with the consideration of both FFIFD and two-phase flow. It is a quite comprehensive model to allow for a seamless way to analyze production data in the flow-back and production stage. It can also serve as an alternative to computationally expensive numerical simulations to evaluate the formation damage for unconventional reservoirs.
Data Analytics for Steam Injection Projects
Authors: Castrup Suzanne 
Published: April 2019

Abstract
Steam is the most effective means of transporting heat into viscous, heavy oil reservoirs. Consequently, millions of dollars are spent annually to generate steam for continuous and cyclic injection projects. This paper presents best practices for collecting and analyzing data to streamline decision-making, optimize field operations and maximize economic performance steam injection projects. Required data collection types and frequencies are defined. Cost-effective monitoring methods and procedures to ensure data integrity are described.
Data analysis methods for evaluating heat migration efficiency through surface piping, down injection or cyclic wells, through the reservoir, up producing wells and through casing vapor recovery systems are illustrated. Methods for integrating and interpreting qualitative information, such as surface terrain, reservoir structure and stratigraphy are also illustrated.
Data normalization techniques are presented to properly evaluate steam injection requirements and better characterize production response. Recommended practices are also presented for establishing, calculating and evaluating key operating parameters to clearly identify and implement project improvements in a timely manner.
The Application of Dissolvable Cement Retainer for Remedial Cementing Technique in High Water Production Zone
Authors: Zhang Shuo , Wang Weiyi , Zeng Liam , Chep Niketa 
Published: April 2019

Abstract
With the increase of mature wells, comingled production from multi-zones in long laterals has become more common in recent years. High sand production, wellbore collapse and water invasion from high-pressure aquifers have been observed more frequently. Among these adverse consequences, water invasion is one of the most common issues throughout the production in lateral wells. Various solutions have been introduced to mitigate this, but this paper will focus on an innovative cement retainer which could eliminate the mill out and leave zero debris downhole after the tool functions for zonal water shut off.
Identification of the Decline in Well Productivity Index due to Wellbore Damage through the Removal of Fluid and Formation Effects
Authors: Morsy Samiha , Pan Yan , Lari Usman , Clark Wesley , Mire Erin , Suleen Fnu 
Published: April 2019

Abstract
A dynamic diagnostic tool for quantification of factors influencing well productivity decline is presented in this paper. The diagnostic tool helps identify well stimulation candidates and potentially uplift in production. Wells in deep water reservoirs show significant rate decline with time due to various causes including: changing reservoir properties (e.g. reduction in rock permeability because of compaction), degradation of completion efficiency (e.g. increasing skin), and changes in fluid flow conditions (e.g., single phase to multiphase flow). Rate decline due to an increase in skin can be mitigated by a properly designed well stimulation job, while other causes of rate decline related to changes in formation properties and/or multiphase fluid production may not be remediated and requires a long-term reservoir management plan. Engineers routinely screen for well stimulation candidates based on the decline in well productivity index. Diagnostics and quantification of primary and secondary contributing factors for well productivity decline play an important role in candidate selection. In this work, practical workflows are presented to remove the effects of rock compaction, fluid properties changes, and multiphase flow effects from the estimated productivity index. The presented workflow uses the recently developed multiphase well testing method by Kamal et al (2018) to estimate the changes in the relative permeability values, so total fluid viscosity values can be estimated to remove fluid properties changes and multiphase flow effects at each analyzed pressure buildup test, and the estimated absolute permeability is used to remove compaction effects. The workflow provides a dynamic diagnostic tool for monitoring well productivity changes to identify the main causes of productivity decline and quantify effects on the normalized productivity index. The presented workflow is validated using synthetic cases covering a wide range of reservoir and fluid properties as well as wellbore conditions. A field example from the Gulf of Mexico is presented to show the practical use of the proposed workflows as it ensures an accurate and reliable process for properly selecting candidates for well stimulation. The field case shows a total reduction in the normalized well productivity index up to 53% due to combined impacts of fluid properties changes, multiphase, and compaction.