bluuebunny/crossref_metadata_2025 huggingface dataset:
Kinetics Analysis Validation for In-Situ Combustion by Coupling Experimental Data with Analytical Methods
Authors: Ismail Norasyikin Bte , Siu John , Hascakir Berna
Published: October 2018

The complicated nature of combustion reactions makes the performance prediction of in-situ combustion difficult. This study proposes a solution to better understand the complex chemical reaction schemes through systematically conducted Thermogravimetric Analysis and Differential Scanning Calorimetry (TGA/DSC) experiments.

In this study, results from combustion tube experiments (CTE) are integrated with kinetic and analytical modeling. The SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions of a bitumen sample were subjected to TGA/DSC experiments under air injection at a constant heating rate. Heat flow curves (DSC curves) were used to determine kinetic parameters by using Reaction Kinetic Models (Arrhenius Model, Coats-Redfern Model, Horowitz-Metzger Model, and Ingraham-Marrier Model).

The kinetic analyses conducted on separate SARA fractions and on bulk crude oil samples provided valuable information: asphaltenes require the largest activation energy but generate the greatest amount of heat upon combustion. Saturates provide large amounts of heat, which proves their ignition feature. Aromatics and Resins play an important role on asphaltene cracking, in addition to supplying large amounts of heat to asphaltenes upon burning.

In-situ combustion is a very promising enhanced oil recovery method which can yield high oil recovery. However, the unknowns associated to chemical reactions inhibit the prediction of combustion performance. This study provides a unique solution to find the correct and simple reaction kinetics by integrating reaction kinetic experiments with several kinetic analysis methods.
High-TDS Produced Water-Based, Low-Damaging Fracturing Fluids for Applications at 300°F or Higher
Authors: Li Leiming , Saini Rajesh , Mai Nam
Published: October 2018

Water usage in hydraulic fracturing jobs has been increasing continuously, mostly due to multistage hydraulic fracturing of horizontal wells in unconventional reservoirs. Meanwhile, nearly 100 billion barrels of produced water, often with total dissolved solids (TDS) higher than seawater, is being generated every year from oilfield operations. Operating cost could be lowered if produced water is used in place of fresh water in fracturing activities, due to the reduced fresh water consumption and produced water disposal cost.

Formulating slickwater or linear fracturing fluids with high-TDS produced water is a common practice. Crosslinked fluids have also been prepared with salt and hard produced water for medium and low temperature applications. At elevated temperatures above 250°F, it becomes much more challenging to make stable crosslinked fluids with untreated produced water due to the damage caused by the high water salinity and hardness. Without resorting to scale inhibitors and/or high fluid pH, fracturing fluids prepared with untreated high-TDS produced water have so far shown stability at around 275°F.

With careful selections of the fluid additives, a new high-temperature fracturing fluid system was recently formulated with untreated produced water having TDS at or above 295,000 mg/L. Made up of metal-crosslinked polysaccharides, the fluids were stable at high temperatures of 300°F or more. In representative tests, the fluid viscosity stayed above 100 cP (at 100 s−1 shear rate) for 2 hours at 300°F. To reduce the scaling tendency and enhance the gel cleanup, the fluid pH was suppressed to 7.2 or below as measured at surface temperature, resulting in a regained permeability of 77% in the conductivity test. Overall, the new produced water-based fluid system showed satisfactory performances at 300°F in fluid viscosity and stability, regained conductivity, and scaling tendency.

The key roles played by the additives to render the fluid stability at 300°F will be discussed for the high-temperature fracturing fluids prepared with high-TDS produced water, and the laboratory test results will be presented in detail.
Quantifying the Probability of Success of Stimulation Treatments When Information is Limited
Authors: Hoeink Tobias , Cotrell David , Odusina Elijah , Ghorpade Sachin
Published: October 2018

A paradigm shift in dealing with subsurface uncertainty in hydraulic fracturing treatments is introduced. The mathematically rigorous application of uncertainty and sensitivity analyses for a proposed stimulation of a lateral well within an unconventional reservoir in the Marcellus with limited formation data delivers the ability to identify the optimum treatment parameters and to quantify its probability of success. Selection of the optimum reservoir stimulation treatment is achieved by systematically investigating thousands of hydraulic fracture simulations over a large parameter space covering formation properties with inherent uncertainties (e.g., stress gradients, leak-off coefficients) and tunable treatment parameters (e.g. pumping rates, fluid and proppant properties, perforation spacing), and computing an objective function. Operators commonly select objectives based on technical (e.g., propped fracture length, fracture height containment), operational and investment considerations. Here, the average fracture conductivity at closure is selected as the primary technical objective to be maximized. A subsequent uncertainty analysis of the optimum treatment plan that expressly includes the limits of formation property knowledge quantifies the probability of success. Production forecasts of specific cases illustrate the range of possible outcomes. Results from more than 12,000 hydraulic stimulation simulations demonstrate a wide distribution of results in terms of average fracture conductivity. Surprisingly, only a small, isolated fraction (< 5%) of the design space returns clearly superior results compared to the majority of investigated scenarios. The optimum treatment designs in this study are associated with relatively low volumes of a gel treatment pumped at relatively high rates. Production simulations illustrate that the best 10% of cases significantly outperform production over the first two years by approximately 50%. Collectively, the approach presented here illustrates the application of uncertainty and sensitivity analyses on several thousand simulations that cover a large, realistic parameter space. Embracing uncertainty, this approach enables identification of the best treatment plan and quantification of the probability of success given limited formation data. In addition, this methodology offers input for risk assessment and return on investment decisions.
AI Supports Information Discovery and Analysis in an SPE Research Portal
Authors: Schoen Eric , Smith Reid , Boden John
Published: October 2018

Ongoing growth in the volume of raw data generated by digitized oil and gas operations has been widely documented (Spath, 2014). What may be less apparent is that the industry is also authoring dramatically more unstructured content—interpretations, learnings, case studies, etc.—on an annual basis. This is not surprising, as anecdotal evidence suggests that most decisions are taken on the basis of unstructured data (Quaadgras & Beath, 2011) (Garland, 2017) (Palkowsky, 2005) (Haines, Shaughnessy, & Briggs, 2006) (Hollingsworth & Schey, 2017). At the Society of Petroleum Engineers, the number of new papers published annually has followed an exponential growth curve that doubles approximately every 10-11 years, beginning as far back as the early 1950's.
Mapping the Success Dimensions of Large Oil and Gas Projects
Authors: Redda Yitbarek , Turner Rodney
Published: October 2018

In order to satisfy the increase in world energy demand, the global oil and gas industry is expected to invest US$ 25 trillion from 2015 to 2040 in development projects (IEA, 2015). However oil and gas projects have had a long track record of sluggish performance. This study investigated the performance of Development (Pre-FID) Large Oil and Gas Projects and determinants of their success. Adopting a view that project success comprises success factors and criteria considered simultaneously, 11 success criteria and 57 success factors were first identified using a systematic and exhaustive literature review backed up by validation from experienced practitioners. A global online survey was then conducted to solicit the perceptions of project directors and managers from Owners and EPC Contractors regarding the identified success criteria and factors. A total of 96 and valid responses were received.

Exploratory factor analysis using SPSS software identified three success criteria groupings - (1) Project Management Success, (2) Business Success, and (3) Future Potential/Growth. For success factors the number of groupings is six. These are (1) Project Management, Leadership & Team Competence, (2) Front End Loading, (3) Project External Context and Compliance, (4) Project Impacts on External Environment, (5) Project Risk and Quality Management, and (6) Project Connectivity with Local Resources Capacity. The criteria and factors identified are directly applicable to projects and programs in other domains such as mining, large scale infrastructure development, ship building, and defense acquisition. The results of this study can be used as a starting point towards the development of a success measurement methodology for industrial megaprojects.
Gas Velocity-Based Lift Curves for Quantifying Lost Production in Liquid-Rich Permian and Delaware Basin Horizontal Liquids Loaded Wells
Authors: Nagoo A. S.
Published: October 2018

In this continuation work, we expand upon the Nagoo et al., SPE-190921 [1] seminal paper that unveiled for the first time a simple and direct analytical critical gas velocity diameter-and-inclination-dependent equation for predicting the onset of liquids loading in horizontal wellbores. Using this equation, we now introduce a new analytical method for quantifying lost liquids production in liquids-rich horizontal gassy oil and gas wells undergoing liquids loading. Case studies of in-operation horizontal wells from the Permian and Delaware basins are used to highlight and validate the methodology.

For horizontal liquid-rich wells in unconventional plays, liquids loading can severely impair production in gassy oil or gas wells with significant oil or water production. Currently, there is no reliable, field-focused, simple-to-use, analytical method for quantifying the lost (or deferred) liquids production because of the liquids loading happening in the wellbore. We propose that the downhole wellbore gas velocity and the critical gas velocity profiles can be superimposed on the traditional wellbore lift curve to yield a varying unloading point on the wellbore lift curve that is very sensitive to and dependent on the predictive reliability of both the diameter-and-inclination-dependent critical gas velocity model used and the wellbore multiphase flow model used. In looking at the new gas velocity-based lift curve results for several horizontal wellbores, the lost liquids production can now be quantified and compared to the actual liquids production drop in the well history before and after the onset of liquids loading. Furthermore, it is demonstrated that as opposed to prior ad hoc recommendations of bottom-of-lift-curve or tangent-of-lift-curve demarcation points for liquids unloading, the new analysis presented provides an analytical intersection point between the downhole wellbore gas and critical gas lift curves as the basis for the unloading point (onset of flow liquids flow reversal point). This signifies that the combination of analytical multiphase flow wellbore and analytical critical gas velocity calculations will now change and define the range of unloading producing rates according to diameter, inclination and fluid property changes.

For the first time, a practically useful and simple analytical method for quantifying lost liquids production in liquids loaded horizontal gassy oil and gas wells is presented in the form of gas velocity-based lift curves. This signifies a new powerful arm of horizontal well artificial lift modeling for life-of-well lift optimization (i.e., incorporating rate declines) for keeping wells flowing at flow rates to avoid liquids loading. Both the lost liquids and lost gas production can be predicted on a well-by-well basis and wells can now be prioritized for artificial lift needs according to their downhole "loading proximity". Various relevant field case studies are used to validate the method in practice.
Comparing Completion Designs Using Normalized Rate Transient Analysis – Proposed Workflow and Case Study
Authors: Ockree Matthew , Brown Kenneth G. , Frantz Joseph H. , Voller Katharine , He Jonathan
Published: October 2018

Proper design and analysis of field tests requires two critical components: 1) availability of quality production data from appropriate control wells, and 2) a normalization process capable of isolating the impact of well and/or completion design changes on well performance.

We will present a normalization workflow currently employed in our Marcellus Shale assets. Normalization methodologies published by others will be summarized and discussed in this paper as well. Lastly, we will compare these published methodologies to our proposed approach, noting the pros and cons of the various approaches.

We begin by discussing an updated rate transient analysis (RTA) workflow (update of SPE-165711) that is based on analysis of 1,000+ Marcellus Shale wells with several years of production history, and incorporates several "lessons learned" in regard to non-uniqueness issues and input uncertainties. Details of our proposed normalization process will then be presented, which involves Production Data Analysis (PDA), Rate Transient Analysis (RTA), and analytical modeling. Lastly, we will explore a case history illustrating the value of this normalization process.

The case history will demonstrate the use of this normalization process to assess the value of different completion designs. This study will clearly illustrate the value of implementing an adequate normalization process to 1) assess field tests, 2) accurately forecast well productivity, 3) evaluate well economics associated with further testing, and 4) better understand why a new design performs differently from previous designs.
Statistical Analysis of Generational Effect on Marcellus Well Completions Using Bottomhole Gauge Data
Authors: Ayers Kimberly , Jacot Henry , Ayers Alivia
Published: October 2018

In the Appalachian Basin, the primary focus has shifted from exploratory wells to full pad development. Therefore, generational affects--the relationship between parent and child wells--are becoming a primary concern to operators that are fully developing their lease positions. This study examined bottomhole gauge data from a parent Marcellus Shale well that was recorded during the hydraulic fracture stimulation of three children wells in the Marcellus Shale and two children wells in the Burket Shale.

The characteristics of the children wells created a robust data set due to variation in inter-well spacing, producing formation, completion design, and stimulation timing. Fracture modeling was performed in advance of the completion operations in order to mitigate possible parent-child communication. The parent well produced natural gas and condensate for nine months prior to being shut-in for the completion of the children wells. Rate transient analysis was performed on the parent well to further understand the depletion of the producing zone. Detailed bottomhole pressure and temperature data were measured in the parent well during the stimulation.

Once operations were completed, the bottomhole gauge data was examined to identify frac hits to the parent well. The general magnitude and timing of the frac hits were examined in relation to the rock matrix and completion design parameters, and completion sequence. It was concluded that over 75 percent of Marcellus frac stages communicated with the parent well, with the most frac hits being attributed to the nearest child well. Logistic regression tests were performed on individual parameters to determine key influencers on the likelihood of a frac hit.

Detailed bottomhole gauge data, as presented in this paper, is limited in the current literature due to the expense of data acquisition. The unique characteristics of the wells involved in this field experiment provide for robust statistical analysis that is not typically available publicly in the Appalachian Basin.
Mining FracFocus and Production Data for Efficacy of Fracturing Fluid Formulations
Authors: Luo Hongyu , Zhang Yongqiang
Published: October 2018

Using environmentally friendly and low-cost chemical ingredients that are also effective in terms of oil and/or gas production is the ultimate goal of formulating fracturing fluids. The relatively transparent production data and fracturing fluid ingredients through FracFocus provide an opportunity to mine large amount of data for insights on the efficacy of fracturing fluid ingredients, which were not possible through traditional means of individual lab tests and statistical analysis of individual ingredients and small clusters of wells.

Here we showcase a big data analytics framework where through data preprocessing and feature engineering, algorithms and models can be built to quantify the efficacy factors of fracturing fluid ingredients for gas production. Special attention is paid to geological properties so that they are similar or identical for comparison.

As an example, we demonstrate the big data analytics process on a dataset of more than 3100 horizontal Marcellus shale gas wells in Pennsylvania, and the data-based insights not only corroborate the empirical wisdoms known in the industry, but also established quantitative measures such that ingredients with higher efficacy factors should be used more confidently, while caution should be exercised on those ingredients that have negative efficacy factors for gas production.

This work also shows the potential value of the FracFocus database in improving the efficiency and efficacy of hydraulic fracturing, in addition to its intended environmental cause. Big data and data sharing should be encouraged not only for public safety grounds, but also for economic reasons for the industry.
Accounting for Serial Autocorrelation in Decline Curve Analysis of Marcellus Shale Gas Wells
Authors: Morgan Eugene
Published: October 2018

Current decline models fail to capture all of the behavior in shale gas production histories. That is, upon fitting one of these models, one often sees significant and sustained deviation of the flow rate data points from the decline trend. One way to measure this "lost signal" is to look at the autocorrelation in the residuals about the fitted decline model. Indeed, with many shale gas wells we see significant amounts of autocorrelation, especially when comparing the flow rate at one time to the next (lag one). Theoretically, this serially autocorrelated error can impact decline curve analysis in two ways: 1) inefficient estimation of decline curve parameters, and 2) lost signal in the data. Borrowing from time series statistics, there are two conventional ways of dealing with these potential problems: 1) estimate the decline curve parameters with generalized least squares or generalized nonlinear least squares, and 2) fitting an ARMA model to the residuals and adding it to the fitted decline curve.

This paper investigates the practical implications of these two procedures by exercising them over decline curves fit to 8,527 Marcellus shale gas wells (all wells from that play with viable data for the analysis). The study explores the effect that generalized regression methods and ARMA-modeled residuals have on six different decline curves, and performance is measured in terms of sum of squared residuals (a metric for goodness-of-fit, calculated on the training data (first 24 months of each record)) and mean absolute percent error (a standard metric for forecasting accuracy, calculated on the testing data (all production rates after 24 months)).

We find that inclusion of the ARMA-modeled residuals largely improves the goodness-of-fit for any decline curve, and improves the forecasting accuracy for the Hyperbolic decline curve and Duong's model. The use of generalized least squares or generalized nonlinear least squares has little benefit in fitting the decline curves, except for the Logistic Growth model, where it improves both fit and forecasting accuracy.
Adopting Physical Models in Real-Time Drilling Application: Wellbore Hydraulics
Authors: Shahri Mojtaba , Kutlu Bahri , Thetford Taylor , Nelson Brian , Wilson Timothy , Behounek Michael , Ambrus Adrian , Ashok Pradeepkumar
Published: October 2018

The first step towards drilling optimization and automation is a reliable data acquisition and handling system. This includes receiving and processing different frequency data across multiple platforms and ensuring proper data quality. Once we implement such a platform, we can build different advisory solutions to improve drilling efficiency and move towards drilling automation. The developed Drilling Intelligence Guide (DIG) already enabled us to achieve the aforementioned goal and access different data (from contextual to high frequency) in real-time.

In the next phase, different models (physical or data analytics) can be built in to optimize various stages of drilling operations. The drilling industry has made significant progress on different physical models that can be run offline (either for pre-job design or post-job analysis) in the previous decades. Given the developed data platform, we can now adopt and run these models in real-time for optimization and automation purposes. As an example, a real-time, computationally efficient hydraulic model that can account for drill string rotation and eccentricity would enable us to monitor ECD (to be used for wellbore stability, kick and lost circulation mitigation) and calculate pump pressure corresponding to different operational conditions (to be used for drill string washout/pump failure prediction and sensor calibration).

The aim of this paper is to show the application of the hydraulic model for real-time monitoring and optimization purposes. An analytical hydraulic model including drill pipe rotation and eccentricity effects is used and compared against transient numerical simulations. In the next step, Pressure While Drilling (PWD) data are used to verify the accuracy of the model for real-time applications. After the verification steps, we explain the process to couple real-time data (e.g., flow rate, RPM), contextual data (e.g., mud properties, BHA and wellbore geometry) and the physical model using field examples. In addition to ECD monitoring at the bit and casing shoe, the real-time hydraulic model can also be used to monitor washout and pump failure events. The application of the model is shown using field examples.
The Impact of the Net Stress on Gas Recovery from the Marcellus Shale
Authors: El Sgher Mohamed , Aminian Kashy , Ameri Samuel
Published: October 2018

Unconventional reservoirs have high initial production rates followed by a steep decline as compared to conventional reservoirs. The increase in the net stress with the production results in matrix and fissure permeability reduction and hydraulic fracture compaction and conductivity impairment due to proppant embedment. At the same time, the pressure decline will result in gas slippage and matrix permeability enhancement. The impact of the net stress and pore pressure changes are often neglected when evaluating the production performance of the shale wells. The objectives of this study are to investigate the impacts of net stress changes (geomechanical) and pore pressure changes (gas slippage) on the gas production from horizontal wells with multiple hydraulic fractures completed in the Marcellus Shale. Laboratory measurements on Marcellus shale core plugs provided the foundation for evaluating the impact of pore pressure and net stress changes on the matrix permeability. Additionally, these laboratory measurements on Marcellus shale core plugs provided the fissure closure stress. The results of the published studies on Marcellus shale core plugs were also utilized to develop relationships for hydraulic fracture conductivity and the fissure permeability as a function of the net stress in the shale. Core, log, completion, stimulation, and production data from the wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were utilized to generate the formation and completion properties for the base model for a horizontal well completed in Marcellus Shale. The results of the laboratory measurements and published studies were then incorporated into the base model to account for the impact of the stress on the matrix, fissure, and hydraulic fracture permeability (conductivity), and consequently on the production performance.

The model was utilized to determine the effective properties of the hydraulic fractures by history matching the production data from two horizontal wells at MSEEL site. For the comparison purposes, the geomechanical effects were excluded from the model, individually and all combined, to history match the same production data from the horizontal wells. The results indicated that the geomechanical effects for fissure permeability have a significant impact on gas production as compared to geomechanical effect for matrix permeability and hydraulic fracture conductivity. The gas slippage was found to have an insignificant impact on the production. The base model was finally used to perform a number of parametric studies to investigate the impact of fracture half-length, initial fracture conductivity, and fracture stages spacing on the stress-dependent fissure permeability.
Hydraulic Fracture and Reservoir Characterization for Determining Optimal Well Spacing in the Marcellus Shale
Authors: Pankaj Piyush , Shukla Priyavrat , Kavousi Payam , Carr Timothy
Published: October 2018

Naturally fractured reservoirs such as the Marcellus shale require an integrated reservoir modeling approach to determine well spacing and well-to-well interference. The Marcellus Shale Energy and Environment Laboratory (MSEEL) is a joint project between universities, companies, and government to develop and test new completion technologies and acquire a robust understanding of the Marcellus shale. The study presented in this paper aims to reveal an approach to determine reservoir depletion with time through coupled geological modeling and geomechanical evaluation followed by completion and well performance history matching for a multiwell pad in the Marcellus shale.

The geomechanical model was prepared with interpreted vertical log data. A discrete natural fracture (DFN) model was created and used to determine the complexity of hydraulic fracture geometry simulated through complex fracture models on a two well pad. The microseismic data obtained during the hydraulic fracture simulations served as a constraining parameter for the hydraulic fracture footprint in these wells. Sensitivity to the DFN is realized by parametric variations of DFN properties to achieve a calibrated fracture geometry. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Well spacing sensitivity was done to reveal the optimum distance that the wells need to be spaced to maximize recovery and number of wells per section.

Hydraulic fracture geometry was found to be a result of the calibration parameters, such as horizontal stress anisotropy, fracturing fluid leakoff, and the DFN. The availability of microseismic data and production history matching through integrated numerical simulation are therefore critical elements to bring unique representation of the subsurface reaction to the injected fracturing fluid. This approach can therefore be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus. With the current completion design and pumping treatments, the optimal well spacing of 990 ft was determined between the wells in this study. However, wells to be completed in the future need to be modeled due to the heterogeneity in the reservoir properties to ensure that wells are not either underspaced to cause well production interference or overspaced to create upswept hydrocarbon reserves in the formation.

By adopting the key learnings and approach followed in this paper, operators can maximize subsurface understanding and will be able to place their wellbore in a nongeometric pattern based on reservoir heterogeneity to optimize well spacing and improve recovery.
A New Model to Evaluate Polished Rod Load of Sucker Rod Pumping System
Authors: Wang Yanbo , Wang Sai , Yang Lu , Pu Hui , Ling Kegang
Published: October 2018

Sucker rod pumps provide mechanical energy to lift oil from bottom hole to surface when oil wells do not have enough energy to produce the oil through natural flow. It is efficient, simple, easy to be operated, and can be applied to slim holes, multiple completions, and high-temperature and viscous oils. The disadvantages include excessive friction in crooked holes, solid-sensitive problems, low efficiency in gassy wells, limited depth, and bulky volume. The load on the rod is one of the key factors that dictate the maintenance frequency of pumping unit, energy consumed to lift the fluid, and the optimization of pumping system operating parameters.

The cyclic load applied on the rod causes the fatigue and finally the failure of the rod if not designed properly. The rod load is a function of friction force, plunger acceleration/deceleration, weights of plunger, fluid being lifted, and sucker rods string, and the pressures above and below on plunger. Literature review indicates that a model to accurately calculate the load of a pumping cycle is highly desired. In this study, we couple the wellbore with reservoir performance to better analyze the dynamics of pump system, which yields more accurate results.

In this study, force balance during the pumping cycle is analyzed. Friction force due to the movement of the plunger and the rod, buoyant force, and gravity force are included in the modeling. The effects of acceleration and deceleration of the plunger on rod are considered. The sensitivity of pumping speed is investigated. This study proposed a more general model comparing with former researches because more factors that affect the load applying on rod are included. Including the friction force due to the viscous fluid is critical to rod load analysis in pumping heavy oil.

The proposed model is significant to the cyclic fatigue and failure analysis of rod in sucker rod pumping system. It can be used to predict the possible failure point for rod string by analyzing load along the whole string. It is also a useful tool to design the tapered rod string to minimize the maximum rod load while achieving optimum rod string life. Therefore, an optimization of sucker rod pumping system is implemented by balancing the tradeoff between the maximum rod string life (or rod size) and the minimum rod load (or lowest energy consumption).
Integrated Methodology for Laboratory Evaluation of Shale Plays Cuttings
Authors: Carreño P Angelica Maria , Pérez T Maria del , Marfisi Nelbett , Gomez Juan José , Pérez C Edgar Ricardo
Published: October 2018

This current paper is intended to show the implemented methodology for integrated mineralogical, geochemical, petrophysical characterization of Shale Plays from the analysis of well cuttings at the Colombian Petroleum Institute (ICP).

The implemented methodology starts with taking drilling cuttings (Wet Trench samples) during the drilling of exploratory wells in areas of interest for production of Shale Oil & Gas in diferents Colombian basins. Then fragments are selected (picking) with stereoscopic magnifiers. Observed proportions and lithology in the Formation Evaluation Log (FEL) for a given range should be consistent.

Subsequently, the textural and compositional macroscopic description of each sample using Hydrochloric Acid (HCL) to identify carbonates is performed. This description takes into account the degree of effervescence and solid waste analysis. Finally, the percentages of every lithotype present per interval are defined, and this way samples are selected for evaluation.

The evaluation of texture and composition of samples was performed by conventional Petrography of relative abundance of elements by means of Scanning Electron Microscopy (SEM). The mineralogical evaluation of samples is performed by X-ray Diffraction (XRD).

Furthermore, geochemical analysis of TOC and pyrolysis are performed in some fragments of the selected samples. Other tests include: Mercury Injection Capillary Pressure analysis (MICP), helium porosity, nanoindentation technique. These analyzes are made to determine mechanical properties of the rock. The integrated analysis of these techniques provides information to the mineralogical, geochemical and petrophysical characterization of rocks from a shale plays.

This allows defining areas of interest for hydraulic fracturing and production in a UnConventional Reservoirs. The methodology was validated with results obtained from core samples from well Iwana-1 drilled by Ecopetrol in unconventional reservoirs in Middle Magdalena Valley Basin (MMVB). This fact provided competitive advantage to Ecopetrol in exploration and exploitation of Shale Plays. This mineralogical, geochemical and petrophysical characterization laboratory methodology for Shale Plays from well cuttings was used during 2014 at the ICP to characterize 880 ft at El Tablazo Formation in well Casabe K1, 850 ft at La Luna formation in well Golosa 1 and 5,900 ft at Gala 1K at the same formation. This methodology allowed shortening the laboratory analysis time from 120 to 60 days with respect to laboratory tests on a core of 800 ft
Application of The Technique MPD Using Automated Systems for Non-Conventional Wells Drilling with Narrow Operating Window in the Neuquén Basin
Authors: Ruiz Ismael A , Padilla Rivelino A , Pagani Alexis
Published: October 2018

For many years it has conducting the drilling of unconventional wells looking for optimize the operation looking for reduce risks and operational problems, additionally increasing the staff security in the complex operations of the Neuquén Basin. New technologies applied to extremely demanding scenarios contribute to reach these goals, and the MPD technique together with automated pressure control systems are a sample of these applications.

Despite the remarkable progress in the drilling of unconventional wells, through the application of UBD and MPD techniques it is observed that with the use of manual equipment continue to have operational problems, which are often associated to difficulty to maintain a proper annular pressure profile for a very narrow operating window and complex geology, which in most cases is due to human factors added to operating conditions of the equipment. As a result of this improper handling of the pressure profile while drilling or during the control of an influx, there are problems of severe admissions, collapses, trapping and presence of cross flows, generating excessive NPT and in some cases the loss of the well with the associated costs that this entail.

The content of this document will show the results of the drilling operation of horizontal wells in the Fortin De Piedra field, where is drilling by applying the MPD technique with automated systems and will demonstrate the difference with wells where techniques MPD or UBD were used with manual or semi-Automated equipment.

This article is considered of interest to those involved in drilling wells in shale gas areas with complex geology and narrow operating windows, especially Neuquén Basin, particularly for design and drilling engineers wishing to evaluate other technologies to apply to optimize drilling operations.
Lessons Learned from Bacteria Monitoring and Treatment in Marcellus Production Operations
Authors: Weaver Dalton , Densmore Zachary , Evans Paul
Published: October 2018

Significant effort around bacteria monitoring has been a focus since July 2016. Water testing program covers all operating areas including southwestern Pennsylvania and Marshall county, West Virginia.

The program began with most probable number (MPN); otherwise known as serial dilution testing, for sulfate reducing bacteria (SRB) and acid producing bacteria (APB). Based on the water test results, biocide treatments were performed for selected wells from October 2016. More than 300 horizontal wells from Marcellus formation were tested for SRB and APB by third quarter 2017 and biocide treatments were optimized by the end of 2017.

Bacteria DNA testing in the form of next generation sequencing (NGS) and quantitative polymerase chain reaction (qPCR) was performed on selected wells to characterize the microbial consortium present in these samples. Due to the limitations of serial dilution testing and understanding of the bacteria makeup with DNA testing, the program has evolved to utilize fieldwide adenosine triphosphate (ATP) testing and a locked-down biocide treatment procedure. Biocide treatments are prioritized during extended midstream maintenance to minimize downtime and maximize contact time and have shown to be effective for extended durations.

To investigate the root causes of bacteria, data science tools are utilized to look at the effect of the completions design and other variables on bacteria during operation. Variables under consideration include biocide type and concentration, fracturing fluid chemical additives, produced water reuse during completions, produced water chemistry, and geologic variation. Initial findings will be discussed and shared with lessons learned from production operations.
Tailored Fracture Fluid Using Nontraditional Water in Unconventional Reservoirs – Argentina Case History
Authors: Bonapace Juan Carlos , Coronel Maximiliano
Published: October 2018

The unconventional Vaca Muerta (VM) boom in Argentina has led operators to explore other targets, including tight-gas formations and shale oil formations, in different provinces and basins. For these projects, the primary objective was to evaluate the feasibility of using alternative sources of water for hydraulic fracturing. The customization of a fracture fluid with these types of water has had two goals. The first goal is an environmental focus, according to the geographic field locations; the second goal focuses on costs and includes both the reduction of completion costs and the improved profitability for these projects. This paper documents and summarizes three cases in which a tailored fracture fluid was developed using these nontraditional sources of water.

Case histories, including the Austral basin (Magallanes formation, a tight-gas reservoir), Golfo San Jorge basin (Diadema-129 formation, a shale oil reservoir), and Neuquina basin (VM formation, a shale oil in Mendoza province) are presented. The paper describes the scope of work for each project, sources of water evaluated, and laboratory methods applied to evaluate a customized crosslinked fracture fluid to meet the operational requirement. A summary of the total jobs performed and the total water volume used for these nontraditional water sources has been included.

A database was developed to collect the primary information required to formulate these fluids. The data are classified into three data groups. The Completion and Stimulation group provides the base information for this work and includes bottomhole temperature, pumping time, and well configuration. The second group, Water Analysis (physical-chemical), includes valuable information used to identify the deviations from the baseline standard for fresh water. The third group includes a full fluid test that consists of hydration gelling curves, a dynamic rheology test (downhole condition), a stability and break test, and a variable shear rate test.

Several types of fluid were tested for these nontraditional water sources, including a guar-borate fluid and a derivatized guar- (CMHPG) zirconate fluid. To develop a solution that would not economically affect the project, the focus was to evaluate the guar-borate system; a different type of boron crosslinker was tested. Finally, a tailored fracture fluid was developed for each project, using the different boron crosslinker, in accordance with the characteristics of the water sources.

The use of alternative water sources to formulate tailored fracture fluids enabled operators to explore or develop unconventional targets in environmentally sensitive areas. In addition, this type of solution contributes to an improved project economy, which reduces completion costs.
Coiled Tubing String Design in Extended Reach Shale Wells
Authors: Nebiolo Martin , Del Negro Ricardo , Rebasa Nicolás , Grimaldo Carmen , Valdez Martin , Prieto Agustín , Codega Dario , Bark Alejandro
Published: October 2018

Horizontal shale wells’ drilling has been challenging the technical limits since its beginning, and the same challenge was faced in completion phase with the Plug&Perf method. Vaca Muerta shale play in Argentina is not an exception of this. Lateral lengths in Vaca Muerta achieved 800-1000 m in the beginning of its shale operations with horizontal wells, and now they are designed to achieve more than 2500 m, even 3200 m, similar to the major laterals in the main shale plays of USA and Canada.

In Plug&Perf completion method, new materials for fracture plugs and advanced designs of perforating guns were also influenced by the technological advances of the industry.

Coiled Tubing (CT) was not an exception of this trend. CT strings for milling out plugs have been demanded to achieve longer laterals without loosing efficiency, with the required Weight on Bit (WOB).

Two main aspects must be taken into account for CT string design: Lateral reach with enough WOB depends mainly on geometrical aspects (external diameter and combination of different wall thicknesses) in order to minimize the occurance of buckling by decreasing the friction caused by the contact of the string with casing wall.Extended fatigue life

In this way, a new technology in CT manufacture was developed and patented, and introduced by the first time in the market in 2005 (R. Rolovic. M. Valdez et al, 2017). This technology employs materials with a new chemistry, and involves a heat treatment for achieving a complete microstructure transformation and homogeneous properties all along the string. Hence, bias weld, heat affected zone and longitudinal seam weld.

Field performance of this new technology in CT has gone beyond the experience achieved with conventional CT. Furthermore, testing of several strings after being removed from the field have shown a superior residual fatigue life than conventional strings, confirming the stated conclusions and pevious observations.
Optimizing Completion Operations using Latch-Functioned Tools with Full Inside Diameter Stimulation
Authors: Richardson Matt D. , Bolivar Javier
Published: October 2018

As operators continue drilling longer laterals, current completion methods present challenges in maximizing stage counts while maintaining operational efficiency and minimizing operational risk. This paper will discuss recently developed completion systems, the Ultra-High Stage Count and the Latch-and-Perf Systems, and results in addressing completion challenges from field trials.

Some of the inherent risks and challenges associated with the current completion methods include: (i) reaching the toe of long laterals with coiled tubing and wireline for setting, stimulation and millout operations; (ii) maintaining a full inside diameter during stimulation for an effective treatment; (iii) time and cost efficiencies; and (iv) logistics. The pros and cons of multiple completion technologies will be highlighted, including various sliding sleeve completion methods in both openhole and cemented applications, as well as plug-and-perf completions.

Design considerations, bench testing and field trials related to the Ultra-High Stage Count System and the Latch-and-Perf System will be presented. The Ultra-High Stage Count System uses pump down sleeve activation tools that build on the efficiency and cost savings associated with continuous pumping operations, requiring no downtime between stages as a unique latch-functioned sleeve actuation tool is pumped from surface to land and shift a corresponding sliding sleeve in the wellbore. Using full diameter sliding sleeves provides no restriction in the wellbore during treatment, maximizing pump rates. The Latch-and-Perf System also provides a full diameter during stimulation and uses a latch isolation tool deployed on wireline to isolate a stage for perforating and treatment, eliminating the requirement for plug setting and millout operations. Both systems are currently in field trials.

The novel Ultra-High Stage Count System presents a step-change in completion design as it overcomes challenges presented by drilling longer laterals without comprising any of the efficiencies and benefits from today's current completion technologies.
Application of Natural Gas for Foamed Fracturing Fluid in Unconventional Reservoirs
Authors: Pankaj Piyush , Phatak Alhad , Verma Sandeep
Published: October 2018

Foamed fracturing fluids have been used in unconventional reservoirs to reduce the water use and minimize deleterious impact on water-sensitive formations. As part of a Department of Energy (DOE) sponsored program, we previously identified an optimal thermodynamic pathway to transform wellhead natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. This study now aims to extend that work by determining the impact of using NG foam fracturing fluids on hydraulic fracture geometry and on productivity from the unconventional reservoirs.

The current study is focused on investigating the impact of the NG-based foam of various foam qualities in hydraulic fracture geometries and their production through simulation models. Field data and laboratory based measurements for NG foam fluid properties are incorporated in the study. In addition, the transient response of the fluid flowback from foam based fluid is studied using numerical simulation. Comparative analysis is done with typical slickwater, linear gel, and crosslinked fluid application for hydraulic fracturing using 3D-complex hydraulic fracture models. 1D and 2D particle transport models have been used to verify the differences in proppant distribution in the hydraulic fractures.

Rapid wellbore clean-up, low formation damage, and effect of the relative permeability improvement are added advantages apart from reducing the water requirements for hydraulic fracturing. In addition to providing the logistical benefit of using wellsite liberated low pressure gas, NG foamed fracturing fluid has a dynamic fluid leak-off behavior and increased effective viscosity over the base fluid that allows pumping and transporting proppant at least 10% farther in the hydraulic fractures than linear gel. Slickwater displays poor proppant transport and hence poses inability to pump higher concentrations of sand. NG foam fracturing fluid on the other hand displays improved proppant transport and has been shown to create more complexity than slickwater in our simulations.

Use of NG foamed fracturing fluid has not been practiced widely yet. Application of NG Foamin field test and reaping the economic benefit from simplified logistics and improved production would enables operators to invest in creating a safer handling environment for wellsite application of NG foam.