bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of Stress Shadowing and Geomechanical Effects on Gas Production From Marcellus Shale
Authors: El Sgher Mohamed , Aminian Kashy , Ameri Samuel
Published: April 2019

Unconventional resources play an important role in meeting the energy demand across the world. In the United States, the unconventional resource development especially shale gas is booming. In order to achieve commercial production from ultra-low permeability shale formations, it necessary to use horizontal wells with multiple hydraulic fracture stages. The properties of the hydraulic fractures and as a result the production performance of the horizontal well with multiple fractures are impacted by the stress conditions during the fracturing and the production. The objective of this study is to investigate the impact of the stress shadowing and geomechanical factors on the gas production from the horizontal wells with multiple hydraulic fractures completed in Marcellus Shale.

The fracture treatment data and shale properties (Young's modulus, Poisson's ratio, and in-situ stresses) from a Marcellus Shale horizontal well were utilized in conjunction with a commercially available hydraulic fracturing software to estimate of the hydraulic fracture properties for different stages which are impacted by stress shadowing. Laboratory measurements as well as the published studies on Marcellus shale core plugs provided the foundation for establishing the geomechanical factors relative to the matrix permeability, fissure permeability, and the hydraulic fracture conductivity. The predicted hydraulic fracture properties for different stages as well as the geomechanical factors were incorporated in a reservoir simulation model to predict the production performance of the horizontal wells under study.

The inclusion of the stress shadowing effects provided a close match between the simulated and actual production performance for the well under study. Furthermore, the inclusion of the geomechanical factors in the model improved the simulation results particularly in the early stages of the production. The results indicated the stress shadowing negatively impacted the production. The impact of the stress shadowing can be reduced by increasing the fracture spacing.
A Novel Meshing Routine for Modeling Reservoirs with Multiple Curved and Intersecting Faults in Coupled Flow-Geomechanical Dual 3D Grids
Authors: Bubshait Abdulrahman , Jha Birendra
Published: April 2019

We use a novel meshing routine to build a coupled flow-geomechanical model of injection and production in a caprock-reservoir-basement system with two conjugate curved faults that resemble a horst-graben or a synthetic-antithetic fault structure. The routine provides the 3D coordinates of each corner in the grid in a CMG grid file format. Our workflow enables us to represent the two faults as 3D objects to which we assign actual physical properties and dimensions of the faults. This is highly advantageous because traditional structured grids cannot represent curved faults, connected faults, or fault intersections without sacrificing either their geometry or their hydromechanical properties. Sacrificing the curved geometry of faults results in a loss of accuracy in computing the induced stresses in the basement region, which is known to host most of the recorded induced seismic events in US. The generated grid was used in a poro-elastoplastic simulation to examine stress changes resulting after production from a reservoir located in the hanging wall block (graben) region bounded by the two conjugate faults. The change in pore pressure due to production causes changes in both the total stress and the effective stress in the reservoir and the basement. The evolution of the shear and effective normal stresses on the faults may induce fault failure and slip depending on the fault rheology and friction parameters.
A Novel Application of Artificial Neural Networks to Predict Rate of Penetration
Authors: Aliyev Ramin , Paul Donald
Published: April 2019

The application of predictive analytics to drilling has a strong interest in the industry today. However, without data modeling, drilling operations are subject to unachieved efficiency. It is missing in the literature how to accurately predict the rate of penetration (ROP) when using surface-only measurements. The traditional approach is to estimate ROP from either data measured on the surface or data collected from downhole. Using the first set of data will result in imprecise results and using purely downhole data can be limited by the fact that there is a time lag due to the slow telemetry systems. In this paper, we propose a novel solution utilizing both data sets.

First, to use both downhole and surface parameters, data is normalized and standardized. Then, Random Forest (RF) regression model is introduced to predict downhole data without any time lag. Then, predicted downhole data such as torque and weight on bit are combined with other drilling parameters to build RF and multi-layer perceptron (MLP) regression models.

It was observed that the computed results better fit the field parameters as a result of incorporating the two sets of data. With the availability of surface data and downhole data, applying this technique is not only useful and accurate, but also simple and fast without incurring further cost to the operating company.
Modeling of Non-Equilibrium Effects in Particulate Flow Through Porous Media
Authors: Jin Yi , Ghanbarnezhad Moghanloo Rouzbeh , Davudov Davud
Published: April 2019

The complex dynamics of fluid and particles flowing through pore space demands some relaxation time for particles to catch up with fluid velocity which manifest themselves as non-equilibrium (NE) effect. Previous studies have shown that NE effect in particulate transport can have significant consequences when relaxation time is comparable to the characteristic time associated with the fluid flow field. However, the existing models are lacking to account for this complicated relation between particles and fluid.

In this paper, we adapt the general form of harmonic oscillation equation to describe NE effects in particulate flow system. The NE parameter is defined as a function of local particle velocity (vp) and fluid velocity (vf)[1-vp/vf]. The NE effect is evaluated by solving coupled mass balance equations with computational fluid dynamic (CFD) techniques within COMSOL Multiphysics®. Simplified straight tube model, periodic converging-diverging tube model and SEM image of a real pore network are applied in the NE analyses.

The results indicate that the time variation of the NE effect complies with the theory of stability. Two key parameters of oscillator equation are amplitude (A) and damping ratio (ζ), where the former represents the magnitude of NE and the latter is an indication of flow path geometry. NE parameter in a diverging flow path illustrates that the ζ value is between 0 and 1. Reducing fluid viscosity yields an increased value of A indicating a larger magnitude of NE effect. For converging flow path, the ζ value is between 0 and −1. The NE effect increases exponentially as a function of time implying that particle velocity always remains less than the fluid velocity. The flow simulation of SEM image shows consistent results with diverging and converging flow results as particles travel along pore network. By conducting simulation on the SEM image of a real pore structure, the equivalent radii of the pores that particles move through were obtained.

The outcome of this work can shed light upon explaining the complex NE effects in porous media. The generalized equation to model NE can help temporarily decouple particle transport equation from fluid equations facilitating much advanced particulate flow modeling in the large-scale problems.
Application of Sourceless Solutions for Geosteering and Formation Evaluation with Logging While Drilling Technologies: Case Study from Kuwait Reservoir
Authors: Padhy Girija S. , Gezeery Taher M. , Rashidi Mohamed A. , Silambuchelvan Jeevankumar , Rashidi Tahani Al , Abdulkarim Anar , Farhi Nadir , Rahimov Huseynagha
Published: April 2019

An emerging technology called sourceless well placement and logging (without using traditional chemical radioactive sources) has intensified in recent years because of various factors, such as drilling risk reduction and cost optimization, as well as evolving government regulatory and health, safety, and environment (HSE) requirements.

Established technologies, such as acoustic sensors, have been tested during pilot projects in several Middle Eastern development environments to evaluate the viability of replacing conventional density-neutron sensors. Current developments and integrated workflows are encouraging for the provision of sourceless well placement, porosity, and petrophysical and geomechanical evaluations for some of the mature reservoirs. These developments include a substantial number of case histories already established in clastic and carbonate depositional environments for the previous five years.

The current well was planned through carbonate and clastic sequence as part of a geological section deemed important from a borehole stability point of view. Borehole deterioration and significant variations in pore pressure were also considered to increase the potential risk for the drillstring sticking. Conventional porosity tools used during a logging while drilling (LWD) bottomhole assembly (BHA) with radioactive sources exacerbate the potential risk at an environmental-hazard level. Additionally, retrievable-based sources can be problematic during extraction in high-angle wells. LWD azimuthal-acoustic tools free of radioactive sources were run for porosity measurements, pressure prediction, geomechanics, and possible anisotropy using a centralized four-axis acoustic caliper. A comprehensive petrophysical interpretation was also performed as part of the horizontal build section using acoustic porosities in comparison to its nuclear counterparts acquired in different modes. Permeability was deduced from acoustic and high-resolution microimaging data.

This paper discusses the planning, design, and use of acoustic tools as part of the BHA and the viability, integrity, limitations, and reliability of logged data and interpreted results. The integration of petrophysical data with cutting analysis is investigated to optimize real-time drilling operations and petrophysical data acquisition requirements for improvement of future developments and overall reservoir management strategies.
Application of Pressure Transient Analysis and 4D Seismic in Evaluating and Quantifying Compaction in a Deepwater Reservoir
Authors: Suleen FNU , Oppert Shauna , Lari Usman , Jose Adachi
Published: April 2019

An integrated approach involving Pressure Transient Analysis (PTA) and quantitative interpretation of time lapse seismic (4D) was developed to estimate production-induced compaction in a deep-water Gulf of Mexico reservoir. The integration of both engineering and geophysical technologies is a robust approach that aims to increase the accuracy and confidence in reservoir characterization. Multiple buildups were extracted and analyzed from the flowing history of the well. Since the well was equipped with a permanent downhole gauge, good quality extended duration buildups were available for analysis. The buildups were studied using analytical pressure transient models. The well was nearly horizontal with oil, water and gas flows and the effects on permeability due to compaction were isolated from the multiphase flow effects. 4D seismic interpretations were used to estimate the temporal strain changes in the shales above the depleted sands. A relationship between shale velocity change and strain change in the reservoir was used to infer the amount of compaction observed on the 4D seismic. The interpretations indicated relatively high rates of compaction at the reservoir depths and dilation in the shales above and below. The findings were used to quantify the level of compaction in terms of porosity change in the reservoir. Sequential analysis of historical buildups integrated with 4D seismic interpretations revealed that the reservoir absolute permeability had declined significantly due to compaction. Most of this decline could be attributed to a production event after which all the buildups indicated reduced permeability level. This suggested a plastic deformation in the rocks and a study of the pressure and rate history suggested that this deformation could be associated with a sudden decrease in the flowing bottom hole pressure around the production event causing an increase in drawdown. Using the porosity-permeability correlations, a 1-2 p.u. change in porosity was estimated. The quantification of the change in porosity and permeability due to sudden increase in pressure drawdowns can be used to help guide operational decisions, where compaction is a significant concern.
Effect of Well Location and Fault Conductivity on Geomechanical Stability in a Faulted Oil Field
Authors: Zhao Xiaoxi , Jha Birendra
Published: April 2019

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

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

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

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

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

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

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

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

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

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

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.
Estimating Downhole Vibration via Machine Learning Techniques Using Only Surface Drilling Parameters
Authors: Okoli Prince , Cruz Vega Juan , Shor Roman
Published: April 2019

Drillstring vibration can be divided into three types: axial, lateral and torsional. All three can cause significant wear and tear in drilling equipment, which leads to increased failures, non-productive time, and poor drilling performance. It also causes wasted mechanical energy and wellbore instabilities. Access to real-time, high-frequency downhole vibration data while drilling remains prohibitively expensive; however, it may be estimated via machine learning (ML) techniques using only surface drilling parameters. The task of predicting the severity of downhole vibration using surface parameters was approached as a supervised classification ML problem. Five basic, traditional techniques were investigated: the nearest neighbour, logistic regression, naïve Bayes, discriminant analysis, and decision trees.

Drilling data was obtained from multiple bottom hole assemblies (BHAs) from several wells in North America. The learning tasks were separated into inter-BHA runs (where the learner is trained on data from one BHA and tested with data from a different BHA) and intra-BHA runs (where the learner is trained and tested with data from the same BHA). Severity of vibration was assessed primarily through the time-weighted average of root mean square amplitude and then classed into severity levels. Performance of the classification results was assessed using the predictive accuracy and weighted macro-average of precision obtained using cross validation and presented as confusion matrices for specific iterations of the cross validation. The classification ML for the intra-BHA runs produced overall predictive accuracies that averaged between 50% and 85%. Of particular concern is the misprediction of certain vibration levels as either lower or higher levels, even when overall predictive accuracy is high.

The results show that these simple ML techniques can achieve considerable accuracy in the prediction of vibration levels for intra-BHA runs. For inter-BHA runs, predictive performance was reduced. This demonstration of the viability of ML in predicting bottom hole vibration motivates the application of more advance ML techniques, including deep learning estimators, and it signals the potential benefits that can be reaped.
The Impact of Re-Injecting Flowback Fluids on Formation Damage. Case Study: Marcellus Shale
Authors: Zhang Lifu , Tice Michael , Hascakir Berna
Published: April 2019

Reuse of flowback water in hydraulic fracturing is usually used by industry to reduce consumption, transportation and disposal cost of water. But because of complex interactions between injected water and reservoir rocks, induced fractures may be blocked by impurities carried by flowback and mineral precipitation by water-rock interactions, which causes formation damage. Therefore, knowledge of flowback water-rock interactions is important to understand the changes within the formation and effects on hydraulic fracturing performance.

This study focuses on investigating flowback water-rock interactions during hydraulic fracturing in Marcellus Shale Formation. Simple deionized water-rock interactions and complicated flowback water-rock interactions were studied under static and dynamic conditions. In static experiments, crushed reservoir rock samples were exposed to water for three weeks at room condition. In the dynamic experiment, continuous water flow interacted with rock samples through the core-flooding experimental system for three hours at reservoir condition. Before and after experiments, rock samples were characterized to determine the change on the rock surfaces. Water samples were analyzed to estimate the particle precipitation tendency and potential to modify flow pathway.

Surface elemental concentrations, mineralogy and SEM images of rock samples were characterized. Ion contents, particle size, TDS and Zeta potential in the water samples were analyzed. In both static and dynamic experiments, compared with deionized water-rock interaction, rock samples after being exposed to flowback water show change in the elemental compositions, more fine particles attachment and new minerals detected on rock surface due to effect of flowback water. In produced water, Na, Sr and Cl are extremely high after flowback water-rock interactions because of flowback water contamination. Water parameter analysis indicates after flowback water-rock interactions, suspensions in produced water have highest precipitation tendency because of extremely highest TDS, largest particle size and lowest absolute Zeta potential relative to all water samples. Therefore, according to rock and water characterization, if flowback water without any treatment would be reused in the field hydraulic fracturing operation, created flow pathways and pores are more likely to be blocked and formation damage will be caused.

This study provides information on comparison between deionized water-rock interaction and flowback water interaction. The information enhances the understanding of basic water-rock interaction mechanisms and evaluates formation damage caused by reuse of flowback water.
A Novel Edge-Based Green Element Method for Simulating Fluid Flow in Unconventional Reservoirs with Discrete Fractures
Authors: Wu Yonghui , Cheng Linsong , Fang Sidong , Killough John E. , Huang Shijun , Jia Pin
Published: April 2019

The boundary element method (BEM) is widely used in modeling fluid flow in fractured reservoirs. However, the computation is extremely expensive when real heterogeneity and large numbers of fractures are modeled. This paper presents a novel edge-based Green element method (eGEM) for this problem, and two significant modifications are made to the classical GEM. An edge-based discretization scheme is proposed to improve the GEM's accuracy. The eGEM technique is further enriched for simulating discrete fractures.

The mathematical model is transformed into the Laplace domain, which makes it convenient to incorporate multi-porosity models because the boundary integral equation form is the same. The matrix is meshed using Cartesian grids, and discrete fractures are handled flexibly by embedding into the matrix grids. In eGEM, the matrix-matrix flow is coupled at the common edge, so the unknown flux could be eliminated by using the edge-based scheme. In each matrix block, the matrix-fracture flow is modeled by treating the fracture elements as sources or sinks like BEM. The finite difference method is used to handle the fracture-fracture flow.

In this paper, we tested the numerical accuracy and computational efficiency of eGEM based on several cases. First the technique was shown to have higher accuracy than the classical corner-based GEM for transient problems in the petroleum industry. This shows the advantage of the edge-based discretization approach in handling the unknown flux of each solution point. The eGEM's ability to handle discrete fractures was validated with the several models for transient flow problems. Comparing to the commercial numerical simulator in handling flow in orthogonal fractures, the eGEM is shown to be less grid-sensitive and maintain relative high precision even with coarse grids near the discrete fractures. A detailed grid sensitivity analysis on grids was performed. It is recommended that fracture grids be refined to capture the early time flow behavior in pressure transient analysis. On the other hand, relatively coarse grids meet the accuracy requirements for production performance simulation. This is the first time to present an efficient edge-based discretization scheme for GEM to enhance accuracy in handling unknown flux while at the same time utilizing eGEM to enrich simulation of discrete fracture networks. This method serves as a new efficient approach for reservoir simulation and numerical well testing. Because of eGEM's high precision with coarse grids, the technique can be readily used in larger field applications.
Characterization of Oil and Water Sound Speeds and Densities for Ultrasonic Water Cut Meters
Authors: Castrup Suzanne , Webb Charlie , Lazaruk Corey
Published: April 2019

This paper presents produced water and heavy oil density and speed of sound (SOS) data for an extended range of temperatures and pressures. The data were obtained from laboratory measurements of samples collected from selected heavy oil wells and and from tests conducted at a specially designed flow loop. The paper also presents recommended methods for establishing oil and water density and SOS reference values required for ultrasonic water cut measurement.

The laboratory tests were designed to evaluate short-term measurement repeatability, equipment reproducibility and long-term stability of oil and water samples at 101.3 kPa (14.7 psia) pressure and temperatures ranging from 20 to 70 °C (68 to 158 °F). Additional tests were conducted at a flow loop constructed by Chevron to evaluate two-phase and three-phase metering equipment over a range of temperatures, pressures, flow rates, water cuts and gas volume fractions. Water only and oil only flow loop density and SOS tests were conducted under steady-state conditions with pressures ranging from 377 to 653 kPa (54.7 to 94.7 psia) and temperatures ranging from 60 to 122 °C (140 to 250 °F).

This is the first time that laboratory and flow loop data have been used to conduct an in-depth assessment of published tables and empirical equations for oil and water SOS and density. As a result, this effort has produced improved methods for creating reference density and SOS values for oil and water over an extended range of temperatures and pressures, an important breakthrough in the effort to utilize ultrasonic SOS methods to measure water cut.
Comprehensive Overview of US Environmental Regulations; Implementation and Impact on the Industry
Authors: Shipman Janine , Liu Fuchen , Wilcox Andra , Haut Richard , Yuan Bo , Liu Anqi
Published: April 2019

The following will illustrate how laws and public concerns can serve as a framework for oil and gas exploration, drilling, and production. It will outline several case histories and how different laws and motivations intersect and shape the industry.

This is a comprehensive analysis of laws governing a particular region's actions and examined on a federal, state and, in some cases, local level. Other factors, including public image and community feedback are evaluated, too. Three case histories are explored. These are presented via a timeline of events leading up to an implementation, reevaluation, and/or development of legislation and/or legal decision. Other legislation is assessed on how an Act (e.g. Clean Air, Clean Water) is initiated apart from the oil and gas realm and then eventually adopted to address certain public concerns.

In most cases, regulations were already set in place and oil and gas entities had to interpret accordingly and work within determined protocols. In some cases, incidents occurred that, in turn, created new legislation and/or set expectations that had implications for how the industry would execute future projects. Incidents include a case of negligence and how the specific company responded as well as other operators located in the immediate vicinity. The regulations and/or best management practices that were created because of the incident will also be discussed. Other cases illustrate the cultural norms surrounding a particular set of legislation. An operator may be familiar with one area yet when branching out to other locations, conclude that the new area is not financially feasible for them due to the different technology and documentation required. Bigger and/or local operators have made these ventures profitable.

A comprehensive report on regulations and how operators execute them will also be provided. Impacts and effects on the oil and gas entities as well as the social and natural communities are assessed, illustrating the important connection between the residential/individual communities and the business entities via the government bodies to hear both sides and appropriately represent the cases at hand.