bluuebunny/crossref_metadata_2025 huggingface dataset:
Utilizing a Data Analytics Workflow to Optimize Completion Practices While Leveraging Public Data: A Permian Basin Case Study
Authors: Olaoye Olubiyi , Zakhour Nancy
Published: October 2018

An evidence based hydraulic fracturing and production optimization procedure is presented using modern data science and data analysis techniques by leveraging publicly available data from the Midland and Delaware basins of the Permian. Results show a point of diminishing return has either been crossed or is being approached as Exploration and Production companies have intensified completions designs by tightening stage lengths, increasing number of clusters, increasing lateral lengths and more importantly escalating proppant and water volumes.

Multiple public data sources including FracFocus Chemical Disclosure Registry and the Texas Railroad Commission are combined, cleaned and processed for analysis with a unique workflow to showcase design optimization. Three critical completion parameters: proppant volume, lateral length and proppant loading have been addressed for select counties in the Midland and Delaware Basins of West Texas. The relationships between these three parameters and other variables affecting well performance are investigated and normalized using multivariate statistics techniques. These topics can directly help operators leverage data science methodologies to use historical data for data driven decisions that assist in optimizing completion designs while generating sound well economics.

This paper focuses on more recent completion designs (2013 onwards) where hydrocarbon production information reported is statistically significant while simultaneously focusing on the more relevant completion design solutions driving the ongoing shale revolution. In general, increasing proppant loading improves well performance, however the relationship is nonlinear, and operators need to be cognizant of the degree of nonlinearity associated with proppant volumes, potentially size and type. The approach described and presented here tackles the Midland and Delaware Basin of West Texas and can be applied to other basins as the data used is available and public.

This paper discusses a method that maximizes the use of public information while drilling down to specific completion parameters to assist in data-based decisions. The techniques used can be expanded to implement artificial learning in asset development.
Auto-Driller Automatic Tuning
Authors: Badgwell Thomas , Pastusek Paul , Kumaran Krishnan
Published: October 2018

While drilling rig control systems have been deployed for many years, a 2016 study [1] identified significant room for improvement in three areas: auto-drillers, top drive torsional damping systems, and heave compensation systems. In particular, in a representative configuration the auto-driller Weight-On-Bit (WOB) controller can exhibit undesirable behavior, including instability, as the drill bit penetrates successive layers of rock with differing hardness. An unstable WOB controller may lead to inefficient drilling and bit damage, and can even induce stick-slip. It was shown, both by simulation and by tests on actual wells, that this behavior can be mitigated by appropriate adjustments to the WOB controller gain. In this paper we present a new algorithm, which we call Drilling Rig Automatic Control Tuning (DRCAT), designed to make these controller gain adjustments automatically. We challenge the auto-driller vendor community to either deploy the DRCAT algorithm or develop a better solution.
Deployment of a Novel Proppant Coating Technology for Controlling Airborne Dust in the Permian: A Case Study
Authors: Kakadjian Sarkis , Reynolds Michael , Sawyer Jordan , Kelly Patrick , Bammidi Vidya , Murray Dennis , Solomon Marvin
Published: October 2018

Occupational exposure to respirable silica from proppant sand is a risk to field personnel in oil and gas operations. This risk must be mitigated to comply with new OSHA regulations that will take place between 2018 and 2021 for limiting respirable crystalline silica to less than 50 micrograms per liter averaged over across an 8-hr period. Therefore, oil and gas operators, oilfield service companies, and proppant suppliers are poised to employ technologies that can address proppant dust control in the field.

Historically, engineering controls have been applied to reduce sand dust using vacuum systems to gather dust in central locations; while other mechanical approaches include limiting sand volumes on conveyer belts or storing sand in silos (necessitating use of a trailer and a storage bin). This paper discusses laboratory and field results from tests designed to mitigate dust that results from handling sand during hydraulic fracturing operations. Coating proppant sand with inert chemical solutions that include a 100% environmentally-friendlybenign chemical blend at transloading rail facilities will be described.

Experimental test results to be discussed include lab scale screening of 10+ aqueous and nonaqueous formulations to control dust, sand caking studies, sand flowability, changes in conductivity, bacterial control testing, and chemical compatibility testing with current additive packages used in slickwater and crosslinked gel systems.

The outcome of field applications using coated sand samples in the Permian Basin showed up to a 97% decrease of dust generated and levels of employee exposure to respirable crystalline silica less than the revised OSHA PEL of 50 μg/m3 as measured in 10-mm nylon Dorr-Oliver cyclones.

A long-term goal for this product is to eliminate the risk of respirable crystalline silica even less than the OSHA action levels at 25 μg/m3 to field staff and to reduce dust exposure to the equipment, improving safety and operational efficiency for operators.
Back to Basics: Revisiting Proppant and Fluid Selection for Unconventional Reservoirs Using a New 2D Slurry Transport Model
Authors: Pankaj Piyush , Belyakova Ludmila , Isaev Vadim , Velikanov Ivan , Bannikov Denis , Semin Leonid , Tikhonov Alexey
Published: October 2018

It is often thought that in ultra-low-permeability unconventional reservoirs, proppant does not play a significant role in productivity because any proppant effectively results in a relatively infinite fracture conductivity. Although with over 75% of the treatment jobs pumped with slickwater in the shale reservoirs due to its cost benefit, it is also thought that slickwater has limited solids carrying capacity. Overflushing may compromise productivity by creating near-wellbore pinchouts. The study presented here aims to test some of these conventions through the use a new high-resolution slurry transport model in unconventional reservoirs. Hydraulic fracture propagation and solids transport are simulated across multiple wells and reservoir settings to measure the production performance of unconventional reservoirs.

Wells completed in the Eagle Ford formation are studied using an integrated earth model built to capture the reservoir geology, petrophysics and geomechanics. A pseudo 3D model for fracture propagation has been coupled with a fine grid numerical simulation of proppant and fluid transport in hydraulic fracture. The transport model can distinguish and demarcate the corresponding bridging resolution. This allows capturing the effect of slurry with proppant bypassing bridged 2D elements.

Multivariate analysis of over 50 cases with various combinations of hydraulic fracturing fluid with viscosity ranging from 1.5 cP (slickwater) to 362 cP (crosslinked gel) and various proppants ranging from 100 mesh to 20/40 proppants are evaluated using the 2D transport model to determine the impact on production. Additionally, various pumping schedules ranging from 750 lbm/ft to 3,000 lbm/ft are evaluated. Parametric sensitivity of the overflush fluid type and volume has been studied to measure the impact on proppant dislodgement in the near-wellbore area. Production performance for all the scenarios is studied through numerical simulation and an economic analysis workflow to evaluate the matrix for fracturing fluid and proppant selection.
Two-Way Acoustic Telemetry for Completion Installation, Control, and Monitoring
Authors: Geoffroy Gary , Werkheiser Gregory , Coffin Maxime , King Kimberly , Frosell Thomas
Published: October 2018

Technological advances are enabling the completion phase of well construction to evolve from interpreting surface-measured pressure and load charts to more direct communication for determining downhole activity and wellbore conditions. Bi-directional acoustic telemetry provides a method for communicating with downhole tools in real-time, where commands can be given to trigger an operational activity in lieu of traditional mechanical means, such as dropping a ball and building pressure, and in addition receive feedback that the activity has occurred.

While current completion methods have been successful using pressure and applied mechanical loads to actuate tools, there are certain scenarios where operations are difficult to execute and it can be challenging to confirm that a piece of equipment has functioned as desired. There are environmental conditions, such as high deviations and s-shaped wellbore geometry, which can be prohibitive to tasks such as getting an activating ball to gravitate to bottom and land on its seat. Using bi-directional acoustic telemetry can eliminate the need for these manual manipulations.

The aforementioned scenario has long been an issue for wells requiring sand control where the completion design might dictate deploying screens into an openhole horizontal wellbore section, performing a gravel pack for wellbore stability, and reducing the production of fines. With the growth of Extended Reach Drilling (ERD), this problem has become more common. This paper discusses adoption of proven bi-directional acoustic telemetry as a method to reduce completion time and remove some of the uncertainty in completing a well. The signal can be transmitted through the drillpipe by use of repeaters that allow for communication to extended depths. When setting a packer, receipt of the command at the hydrostatically operated setting tool triggers the setting tool to function. As a result, the packer at the top of the lower completion sets and the screens become anchored at the desired location. Bi-directional communication allows for confirmation at the surface that the signal was received and the tool properly triggered. This telemetry can further be used during the gravel packing operations to get near real-time temperature and pressure readings from washpipe gauges housed within the screen assembly.

The example documented in this paper is a novel method of deploying a gravel pack system with a bi-directional, acoustic through pipe telemetry within completion tools now in development. This method provides a platform for real-time control and monitoring in the completion environment.
Unconventional Reservoirs Next Frontier: Efficient Production Modeling
Authors: Ayoub Joseph , Krishnamurthy Shalini , Blakey Brian , Xiong Hongjie , Thambynayagam Michael
Published: October 2018

The operational efficiency in drilling and completing unconventional reservoirs has made impressive progress in the past few years. However, modeling the physics of reservoir production, while making progress, still requires substantial time and resources making it applicable only on a small fraction of wells. In this paper, we propose and illustrate use of a novel generation hybrid model that enable viable application on every well. In addition, it provides a practical tool to simulate as many what-if scenarios as needed to identify best solutions and to assess validity of proposed interpretation techniques. Following a brief review of the model validation and the effect of angle between fracture planes and well axis, several examples are presented to assess the impact of many factors including, flow convergence toward the wellbore, fracture-wellbore connection impairment and fracture complexity. Fracture complexity causes significant production increase during the early years of production that decreases with time but can significantly improve the return on investment. The impact on production of flow convergence and that of the fracture-wellbore connection damage is illustrated and a diagnosis method is proposed. Last, a field example history match is presented.
Water Shut Offs in Two Openhole Gravel Pack Wells, Deepwater Angola
Authors: Carragher Paul , Bedouet Sylvain , Talapatra Didhiti , Hughes Andrea , Curran John , Hou Wei , Kosi Orlando , Ralph Stan , Gao Qiang , Gracia Jesse , Galvan Jeanine , Calvert Patrick , Alcoser Luis , Dean Doyle , Mason David
Published: October 2018

Achieving water shut-off in gravel packed wells is challenging, particularly being able to place a mechanical barrier to flow into a gravel packed annulus. Gravel packed wells, often in deepwater environments, are often high rate wells and interventions can be costly, therefore only techniques with a high probability of success are typically sanctioned.

Many gravel pack wells are completed in multiple sands. If there are barriers between the sands that are believed to be laterally extensive, and if water is entering the lower sand, then isolating the lower sand can be a cost-effective intervention. Deepwater wells in Angola were reviewed as to whether a chemical solution or a mechanical solution would be preferred.

Providing a suitable mechanical methodology could be developed, it was felt this would provide a preferred solution. Further criteria for applying a mechanical solution were developed, to increase the chances of success. Extensive well modelling was also conducted to identify an optimum set of plugs to be placed in the well.

The operator identified a company that had an emerging technology that could offer such a solution. They then worked together to mature the technology through a series of proof-of-concept tests, through trials in Alaska, an early application in a deepwater well in the Gulf of Mexico, followed by a series of qualification tests to be ready for application in Angola. The qualification tests considered not only the mechanical configuration of the wells, but temperature, pressure and wellbore deviation. The application would require placement using a tractor, therefore testing with connecting to the relevant equipment was also incorporated in the plans for the wells.

Using a deepwater rig, several plugs were run in each well, including a meltable alloy plug. The latter plug provided a barrier to flow in both the annulus and inside the sand screens. Although not providing a barrier to shunt tubes, extensive modelling work at Cambridge university showed that it was possible to influence gravel movement in the annulus and shunt tubes, so as to maximise the pressure loss.

Two wells have had plugging systems run. The first well has reduced water cut from 100% to ca. 40% and shown a significant oil rate benefit. The second well has also shown a reduced water cut (from 70% to 40%).
New Advanced High-Performance Ultrafine Micromaterials for Providing Superior Properties to Cement Slurry and Set Cement in Horizontal Wells
Authors: Pernites Roderick , Clark Jordan , Padilla Felipe , Jordan Andrew
Published: October 2018

Wellbore cementing is critical for zonal isolation, bonding and supporting the casing downhole. In this paper, a novel high-performance micromaterial is presented for significantly improving the quality of the cement slurry and set cement tested in different API cements for horizontal wells. Its performance is compared to conventional Pozzolanic materials currently used in increasing cement properties. Strongly attractive for cementing horizonal wells, the innovative micromaterial provides excellent slurry stability, free water control, particulate suspension, and additional fluid loss control to superior set cement properties including high early compressive and tensile strengths, extremely low permeability, and zero shrinkage. This material offers consistently high performance and no variability of product quality as compared to Pozzolan materials that are derived as a by-product of coal burning.

The key novelty and invaluable contribution of this research to the field is the application of a unique high-performance micromaterial that can deliver multiple desirable properties in both slurry and hardened cement. With the illustration of the material giving many good surprising properties, the cement design can be optimized by reducing the dosage of several cement additives in the admixture, giving potential cost savings to service companies or operators. During our investigation, the new material does not require an additional chemical to activate its unique functionality.
A Black-Oil Approach to Model Produced Gas Injection for Enhanced Recovery of Conventional and Unconventional Reservoirs
Authors: Du Fengshuang , Nojabaei Bahareh , Johns Russell T.
Published: October 2018

In this study, a fast and robust compositionally extended black-oil simulation approach is developed, which is capable of including the effect of large gas-oil capillary pressure for first and multi-contact miscible, and immiscible gas injection. The simulation approach is used to model primary depletion and gas flooding in a high-permeability reservoir using a five-spot flow pattern for different reservoir pressures. The comparison with fully-compositional model shows good agreement. For an initially undersaturated reservoir with both injection and production wells pressures above the original bubble-point pressure, gas evolves near the injection well and it later breaks through the production well as produced gas is injected. Additionally, the primary depletion and huff-n-puff gas injection in tight shale reservoirs by using the compositionally extended black-oil model indicates that the effect of large gas-oil capillary pressure on recovery becomes smaller as reservoir pressure is higher. Finally, a dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied, and its effect on oil recovery is examined.
Select Naphthenic Acids Beneficially Impact Oil-Water Dynamics During Smart Waterflooding
Authors: Reilly Teresa , Medina Bryan , Lehmann Teresa , Alvarado Vladimir
Published: October 2018

Injection of a generic naphthenic acid blend in waterflooding experiments has been shown to enhance oil recovery. A brine-oil interfacial response upon addition of organic acids has also been recorded and linked to the improved recovery response. The purpose of this work is to analyze the effect of several individual naphthenic acids on the oil-water interface and thereby determine which structure of acids is most potentially influential in improving oil recovery. Acids were selected based on water solubility and structure; analyses were conducted on several molecular structural characteristics to assess the relationship to interfacial responses. Based on the observed fluid-fluid interactions and the likelihood that the acid blend in previous work contained some of the acids studied, we propose a causative connection between the addition of organic acid blends and the recovery efficiency.
Data-Driven Prediction of In-Situ Combustion Dynamics
Authors: Ogunbanwo Olufolake , Koh Yoo Kuy Hun , Gerritsen Margot , Kovscek Anthony R.
Published: October 2018

This paper presents a new workflow for the simulation of in-situ combustion (ISC) dynamics. In the proposed method, data from kinetic cell experiments, depicting the combustion chemistry, are tabulated and graphed based on the isoconversional principle. The tables hold the reaction rates used to predict the production and consumption of chemical species during in-situ combustion.

This new method of representing kinetics without the Arrhenius method is applied on one synthetic and two real kinetic cell experiments. In each case, the new method reasonably captures the reaction pathways taken by the reacting species as the combustive process occurs. A data-density sensitivity study on the tabulated rates for the real case shows that only four experiments are required to capture adequately the kinetics of the combustion process. The results are, however, found to be sensitive to the size of the time step taken. The method predicts critical changes in the reaction rates as the experiment is exposed to different temperature conditions, thereby capturing the speed of the combustion front, temperature profile, and fluid compositions of a simulated combustion tube experiment.

The direct use of the data ensures flexibility of the reaction rates with time and temperature. In addition, the non-Arrhenius kinetics technique eliminates the need for a descriptive reaction scheme that is typically computationally demanding, and instead focuses on the overall changes in the carbon oxides, oil, water and heat occurring at any time. Significantly, less tuning of parameters is required to match laboratory experiments because laboratory observations are easier to enforce.
Field Demonstration of a New Method of the Automation of Continuous Circulation Drillpipe Connections
Authors: Johnson Rachel , Luo Yan , Grace Christopher , Milne Adam
Published: October 2018

Continuous circulation technology is used to maintain constant circulation of drilling fluid in a well by enabling the rig pumps to remain on during all steps of the drillpipe connection process. Continuous circulation is a managed pressure drilling (MPD) technique; it improves drilling success for difficult high-pressure high-temperature (HPHT), narrow pore pressure/fracture gradient, and extended reach horizontal wells.

Traditionally, a continuous circulation system relies on a manifold connected into the rig standpipe, which diverts flow to and from the topdrive to a side port on a sub that is threaded into the top of each drilling stand. Historically, this side port flowline is connected manually by an operator, within the rig floor red zone, in a single barrier pressure environment. To enhance safety by removing exposure to any single barrier pressure applications, a new system was developed that automates and enhances the current manual process.

The automated continuous circulation system includes a connection tool that is mounted on a manipulator arm; after it is delivered to the drillstring and clamped, it will use a human machine interface (HMI) to automatically and remotely remove a threaded side port safety cap, connect the side port flowline, and control the manifold flow diversion process. The system is controlled at the HMI by an advanced software system that is capable of functioning autonomously, with operator verification steps. Internal robotic mechanisms drive the system to perform the exact steps as a human without requiring modifications to the proven continuous ciruclation sub design, all while providing instantaneous feedback to the operator located at the remote HMI.

A prototype tool was assembled and successfully tested in November 2016 in the Val D'Agri oilfield region in southern Italy. With a rapid technical development cycle of less than one year in a down market, a commercial tool was developed and deployed, including the implementation of all lessons learned. This system is the first in the industry to provide threaded engagement of the side port flowline, and a successful undermount delivery arm. This paper presents results from more than 1,000 diversion connections in both laboratory and field environments.

With a 10-year track history of the manual system, the automated system enables the operator to improve upon proven technology to safely deploy continuous circulation capabilities in offshoreapplications, from fixed platforms to floaters, in areas with strict industry certification regulations, personnel in red zone limitations, and double pressure barrier requirements. The system reduces overall added connection time from typical manual systems, increases safety, and maintains the benefits of continuous circulation to reduce nonproductive time (NPT) and total drilling days.
Drill Faster Wells by Transmitting Torque From the Strongest Power Sections to the Most Reactive Formations
Authors: Moisan James , Chapman Christopher , Marchand Nicholas , Smith Roger , Skyles Lane
Published: October 2018

Drilling Operators are continually striving to reduce the drilling cost of every well. Reducing the drilling cost can come from improved performance of the downhole motor. Power sections with even wall rubber technology have provided the latest step change in performance of these downhole motors. These power sections deliver higher torques than conventional rubber lined stators; without a loss of performance in other areas. However, delivering the higher torques from the power section to the drill bit requires new torque transmission technology in the lower end of the motor. The following paper will discuss a new technology utilized to transmit these higher torques. It also includes the developmental history of downhole motor power sections.
Modeling and Data Analytics Workflow From Delineation to Development: A Case Study Utilizing Limited Data in the Extensional Deep Dry Utica Shale Play of Pennsylvania
Authors: Passman Andrea
Published: October 2018

The Deep Dry Utica, also known as the Extensional Utica, is a newly recognized shale play in Pennsylvania and West Virginia. The most developed part of the dry gas Utica shale, in Monroe County, OH, is an inexact analogue as it shares limited characteristics with the Deep Dry Utica to its east. Unconventional workflows based on analogue plays often rely on the statistical significance of trends, impossible to exploit when each data point in a new play is unique, and results are unrepeatable. With only the data from a handful wells in the public domain, and a few wells being drilled by operators where the data is still private, understanding the reservoir and geologic complexity of the Deep Dry Utica has eluded most operators. The play has seen early successes and failures, with wells exceeding initial production rates (IP) of 60 MMcf/day and wells so difficult to drill that they were unable to be completed due to financial limitations. Thus, structurally complex shale plays like the Deep Dry Utica with limited data require a new methodology to rapidly move from delineation to development mode. With a limited heterogeneous data set, subsurface modeling and data analytics in conjunction with analogue analysis allow operators to rapidly understand performance indicators, optimize location selection, well spacing, horizontal drilling and completion designs.

This paper describes the modeling and analytics-based workflow utilized to unlock commercial viability of the Deep Dry Utica, making the play commercially competitive with Marcellus Shale development. The workflow described in this paper utilizes earth modeling, reservoir and completion modeling and contemporary data analytics techniques to accelerate development. The workflow is demonstrated in a case study from the Deep Dry Utica in Pennsylvania, moving from delineation to commercial development, with less than a dozen data points across 500,000 thousand acres.
A New Look at Sealing with Bismuth and Thermite
Authors: Carragher Paul , Fulks Jeff
Published: October 2018

Annular gas migration through micro-annuli in cement, or casing vent flow, is a common issue over the life of a well. This results from poor cement jobs or porous cement that cannot successfully prevent gas flow from creating channels while curing. Remediating this through traditional practices of perf and squeeze or section milling is often expensive and unreliable. This paper will demonstrate a new way to create gas tight seals in casing annuli, minimizing the chance a well will experience casing vent flow by overcoming the limitations of cement in gas environments. This solution can be implemented at any stage of the well but is most effective when utilized as part of the original well construction.
The Best Practices and Approaches for Replication of Achimov Formation Development Technologies
Authors: Nenasheva Marina , Okunev Maxim , Sleta Natalia , Timirgalin Azamat , Zhukov Vladislav , Garenskikh Dmitriy , Volkov Georgy , Priklonsky Oleg
Published: October 2018

The paper presents an analytical review of approaches to the development of the Achimov deposits and its foreign analogues. The purpose of this study was to identify key drivers that determine the success of developing low-permeability reservoirs with a highly heterogeneous both horizontally and vertically.

The first part of the work is devoted to the review of technological solutions used in foreign analogues fields. During preliminary screening of open sources, about 20 deposits of similar genesis or reservoir properties with Achimov deposits were allocated. For further consideration of technological solutions, a more detailed examination of each of the supposed analogs was made according to a set of key criteria, as a result of which 8 formations were singled out.

The second part was devoted to a retrospective analysis of the development of Achimov deposits in licensed areas of Gazprom Neft. To determine the optimal technological solutions, the whole stock of wells in the Achimov deposits was analyzed.

The analysis of publications on foreign analogues, allowed to allocate a pool of technological solutions in the field of completion of wells and hydraulic fracturing of the formation. An approach to a comparative analysis of the efficiency of the applied technologies was proposed.

In the course of a retrospective analysis of the technological operations carried out in Gazprom Neft on the Achimov wells fund, statistics were collected on the productivity, the initial well performance indicators, the parameters and the number of fracturing per well, the type of completion. The collected statistics was analyzed for the search for obvious and non-obvious dependencies, to identify key drivers of the effectiveness of Achimov deposits development. This analysis made it possible to identify the most optimal "historical" technological solutions, the mutual influence of technological parameters, as well as to identify hypotheses on the most effective involvement in the development of Achimov deposits for further verification in the pilot works.

In this work, a generalization of Russian and foreign experience in the development of Achimov deposits and its analogs was carried out. Based on the results of this work, hypotheses were generated on key drivers of Achimov deposits development effectiveness, as well as a pool of technological solutions for further testing the effectiveness of technologies within pilot work.
Shale Gas Novel Technology: Is Coiled Tubing Undulating Completion Compatible in Substituting Multistage Hydraulic Fracturing in Shale Gas Production?
Authors: Gunawan William , Pratami Fatimah Larassaty , Angtony William , Chandra Steven , Lumban Gaol Ardhi Hakim
Published: October 2018

The most common technique of shale gas production is massive or multistage hydraulic fracturing. However, as massive multistage fracturing involves relatively higher capital and is of a negative impact to environment, this paper will discuss the application of undulating coiled tubing as a potential substitute for conventional multistage fracturing in shale production - of which is more economical and has proven to be effective in the production of conventional hydrocarbon from thin and low permeability reservoir.

This study utilizes reservoir data extracted from publicly available Haynesville Shale data. Haynesville is an organic-rich shale play which extends across northeast Texas and northwest Louisiana, US. Overlain by Bossier shale, Haynesville is a unique shale play compared to other plays in US as it is relatively deep; with true vertical depth (TVD) within the range of 11,000 to 14,500 ft, abnormally high-pressure gradient (0.72 to 0.91 psi/ft), and temperatures greater than 300 °F (Thompson, et al., 2011). Haynesville will be the target shale play in this study that will be assessed by production simulation using both massive hydraulic fracturing and undulated well completion. Each production method will then be assessed economically.

This paper shows the applicability of undulated well completion to substitute massive hydraulic fracturing in producing hydrocarbon from shale plays, in terms of technical deliverability as well as economic viability for final warranty of the profitability of the technique. Production performance of undulated well is comparable to that of hydraulically fractured well. Also, the application of undulating drilling proves to have significantly less negative impact on the environment – of which has been the major concern of multistage fracturing due to its pumping at high pressures and huge amount of water needed. Ultimately from economic perspective, the production of shale gas using undulating coiled tubing drilling is attractive as it requires less capital investment.

Undulated wells do not require high-pressure pumped water which makes the completion more environmentally friendly than hydraulic fracturing. The unprecedented shale production using undulating coiled tubing drilling will also be the main discussion to be further compared with the widely and commonly used multistage fracturing. Moreover, between multistage fracturing and undulating completion, both technical and economic comprehensive assessments are conducted to see the well deliverability and profitability in shale gas production before subsequent decision to determine more profitable method.
3D Petrophysical Interpretation of Horizontal Wells
Authors: Kolomytsev Alexander , Sazonova Ekaterina , Ageeva Ekaterina , Pronyaeva Yulia , Pashynsky Alexey , Kneller Ilya , Evdokimova Inna
Published: October 2018

Conventional interpretation of well logging data is done based on coaxial - cylinder model, which was initially developed and proved its reliability in vertical wells. But utilization of this model in horizontal wells may cause false interpretation results. The reason for it is the fact that properties change in vertical direction affect measurements in different way, due to their depth of investigation (DOI). In other words, tool measurements are influenced by formations at the distance with different properties. All this above adds the complexity into petrophysical interpretation - true formation properties evaluation (lithology, porosity, permeability etc.). Consequently, for correct well logging data interpretation in horizontal wells for wireline and logging-while-drilling (LWD) data, the new approach must be implemented, which should be based not only on tool measurements, but also on well trajectory and dip of rock layers; which means it must be in done in three-dimensional space.

This work explains the methodology of logging-while-drilling data interpretation in three-dimensional space. The results of several wells interpretation are compared with standard approach (coaxial – cylinder model) and with 3D. The difference in formation properties and net-to-gross (NTG) are shown for both methods with the recommendation of 3D approach.
Specificity of Flow Initiation at Unconsolidated Reservoir of East Messoyakhskoe Field
Authors: Zagrebelnyy Evgeniy , Martynov Mikhail , Konopelko Alexey , Demenev Roman
Published: October 2018

The East Messoyakhskoye field is the northernmost developed oil field in Russia, located in the northern part of the West Siberian Lowgrounds, in the southwest of the Gydan Peninsula. His most studied object is the PK1-3 formation, the full-scale development of which was not economically viable ten years ago. The process of oilfield construction and pilot production in 2012-2014 was accompanied by the implementation of a large number of innovative technologies and approaches to its exploitation and development. However, it was not possible to completely solve all the problems related to the peculiarities of formation PK 1-3 bedding and structure, the physical and chemical petroleum composition.Reservoir characterization PK1-3:Average TVD reservoir top, m789High TVD reservoir top, m753Formation typemassive, fault-boundedReservoir typeporous, clastic rockAverage net thickness, m:   Oil-saturated16,8   Gas-saturated13,3Porosity0,29Permeability (core), 10-3 µm2387,7Net sand coefficient0,66Number of reservoir beds31Initial formation temperature, °C16Initial formation pressure, atm78

Located at shallow depth, the PK1-3 formation is mainly represented by unconsolidated heavy oil (viscosity 111 cP) sandstone, which characterized by low formation temperature (16°C), and resinous fractions in the reservoir fluid, which makes it possible to conclude that there are a lot of risks to reduce well productivity and increase the skin factor, up to the total or partial loss of the horizontal section.
Calibrating Global Uncertainties to Local Data: Is the Learning Being Over-Generalized?
Authors: He Jincong , Reynolds Albert C , Tanaka Shusei , Wen Xian-Huan , Kamath Jairam
Published: October 2018

A common pitfall in history matching is to falsely generalize the learning from local data to the entire field, which can lead to radical over-estimation of uncertainty reduction and bad reservoir management decisions. This problem is referred to as the local-global problem and in this paper a methodology is proposed to quantify and correct for the error arise from this problem.

Most performance metrics in an oil field, such as estimated ultimate recovery (EUR), are field-level ob jective functions that depend on properties (e.g., porosity) over the entire field. On the other hand, most measurement data (e.g., BHP) are sensitive only to a local area around the wells and are thus susceptible to local variation of geological properties. Calibrating field-level objective functions and multipliers of global properties (e.g., porosity) to local well data over-estimates the reduction of global uncertainties. In this paper, we derived the formula to quantify error in the calibrated posterior distribution (S-Curve) resulted from the local-global problem, as well as a correction factor to recover the true posterior S-Curve.

Through theoretical derivation, it is shown that the model error arise from the local-global problem is dependent on the magnitude of the global and local variation of the uncertain properties (e.g., porosity). The larger the local variation relative to the global variation, the larger the error is in the estimated posterior S-Curve. The error also depends on the variogram of the local variation, and the detection range of the data. The error is larger for case with long variogram for the local variation and short data detection range. In addition, this model error can be highly correlated for different measurement data points even when the measurement error for these data were independent. To address this local-global modeling error, a series of analytical and empirical formula is proposed, which has successfully corrected the error and greatly improve the posterior S-Curve for a series of cases.

To the best of our knowledge, this is the first time the error from the local-global problem is quantified and corrected. The methodology proposed could help improve the reliability of the result from probabilistic history matching.
Underreamer Block with Conical Diamond Elements – Concept, Design, Optimization, and Field Tests
Authors: Trunk Philip , Nasief Mary , Shi Kevin , Long Wiley , Terracina Dwayne , White Allen , Tocantins João Pedro , Costa Edson , Louback Leonardo , Hird Jonathan , Aguiar Romulo
Published: October 2018

Outline

History of Underreamer Blocks and Problem Description

Conical Diamond Elements in Underreamer Blocks

Complementary Design Features

4D Simulation Software Introduction

4D Simulation and Design Approach

Vibration and Drilling Efficiency Lab Testing

18.125-in × 22-in HEWD Job and 4D Simulation Study

12.25-in × 14.75-in URO Job

8.5-in × 9.0-in HEWD Job

Conclusion
Excelling Asset Design: Performance and Operation Management Utilizing Reservoir-Production-Processing Facility Integrated Modeling Approach
Authors: Yengle Carlos , Kumar Hemant
Published: October 2018

Asset steady-state modeling is frequently done by separate teams of engineers working on asset subsystem, production, and processing facility design and asset operation management. Design criteria shared between the teams are based on a limited set of predefined discrete assumptions for each subsystem. Currently, the commonly used modeling approach fails to account for subsystem interdependencies and does not enable assessment of changing conditions across the asset life cycle. This gap often results in suboptimal facilities design for the asset and cost overruns and/or lost production. Overall asset management decision-making tools should be based on reinforcing the consistence of information used across the whole asset. Integrated modeling helps to make informed decisions by considering the combined effect of reservoir uncertainties, well placement, surface network, and process facility on overall asset design, production, and management. This paper describes how a full integrated asset model is built and used as an effective decision support tool to help optimize overall asset design and operational performance management.

A full integrated model is built using typical industry-known commercial simulator packages for each subsystem and field conditions. It includes steady-state models for reservoirs, wells, production and injection networks, and processing facilities. A platform, which orchestrates data connectivity and integration while allowing subsystem applications to maintain their dependency in thermodynamic properties and equations of state solving, is used for transferring data and controlling variables within the subsystems. Data from a major capital project in the early stages of development were used to pilot test the technique and stress test the consistency of forecast production across the subsystems for whole asset impact due to a change in an individual subsystem such as reservoir uncertainties, well placement and scheduling, surface network operating conditions, and individual subsystem constraints."

The integrated multifield network model provided realistic optimal operating conditions and long-term production forecasts of oil production, sales gas, and water injection requirements by incorporating the physics at appropriate levels to ensure higher accuracies than discrete models.

Integrated asset modeling uses information consistently across the entire asset and includes subsystem interdependencies on overall asset steady-state operating conditions. Integrated modeling provides the opportunity for independent teams of facilities engineers, production engineers, and reservoir engineers to collaborate as a unified team while maintaining specific expert's needs and resources.

The asset integrated model technique offers a novel and versatile capability of evaluating diverse operational scenarios to find optimal settings for short- and long-term asset production needs.
Recovery Drive Analysis in Respect of Tilted Oil Rims
Authors: Fedorov Konstantin Mikhaylovich , Samolovov Dmitry Alekseevich , Polkovnikov Fedor Igorevich
Published: October 2018

This paper is dedicated to the reservoir management and the recovery drive of oil rims – depletion, barrier water flooding and gas reinjection. First, the review of world experience in development of oil rims was carried out; the performance results of different drive regimes are described. Main dimensionless criteria that influence on the character of filtration flows in tilted oil rim were formulated. These criteria take into account gravity factor, anisotropy factor, geometrical configuration of reserves of oil and gas.

The methodology of choosing the best recovery drive was presented. It resides in varying key dimensionless parameters with finding the optimal well position and individual well controls at the same time. The criterion of efficiency is discounted oil recovery due to the same number of wells in all variations. Two-dimendional, three-phase, black oil simulator was used to get the "i-chart" that points out the best recovery drive and the best well control. Such graph will help to perform snap-analysis of development of oil rims what will be especially actual for greenfields when designing concepts of systems of development.
Improving ESP Production Through Compression
Authors: Munding Paul , Hudson John
Published: October 2018

ESPs are a main type of artificial lift being used to unload current horizontal unconventional wells. Due to their high cost and high failure rate an operator must implement them in the most efficient manner possible. This paper addresses a way to create a solution to make ESPs more efficient by using compression at surface.

Current ways of handling gas through ESPs are insufficient utilizing variable speed drives (VSDs). Additional gas handling equipment installed in ESPs have also encountered mixed results as designs continue to be tinkered to improve gas handling. One area that has not been researched extensively is utilizing compression to drawdown the casing annulus of a well on ESP. A preferential path of less static head pressure allows the gas to be drawn up the annulus rather than handled through the pump. Thereby alleviating gas handling problems in the ESP and raising the FL over the pump.

The paper presents two case studies in Oklahoma involving ESP compression assistance up the annulus: one is a case study of an unconventional well of the Mississippi Lime with a low FL and moderate gas production, the second is an unconventional well in the Meramec formation with large amounts of gas production that was increased with the assistance of a compressor to the ESP. Data was collected over a six-week period and ESP performance is compared before and after the surface compressor installation for case 1. In case 2, well performance is compared for 3 different artificial lift setups: gas lift, ESP, and compression assisted ESP over a 3-month period.

Both case studies show benefits for utilizing surface compression with an ESP. The biggest benefits were found to be increased production and reduced operating cost by extending ESP longevity.