bluuebunny/crossref_metadata_2025 huggingface dataset:
Asphaltene Gradient Analysis by DFA Coupled with Geochemical Analysis by GC and GCxGC Indicate Connectivity in Agreement with One Year of Production in a Norwegian Oilfield
Authors: Johansen Yngve Bolstad , Rinna Joachim , Betancourt Soraya S. , Forsythe Julia C. , Achourov Vladislav , Canas Jesus A. , Chen Li , Zuo Julian Y. , Mullins Oliver C.
Published: October 2018

Asphaltene gradient analysis in many wells in a large field match the Flory-Huggins-Zuo Equation of State (FHZ EoS) indicating equilibrated asphaltenes, thus reservoir connectivity. This analysis is consistent with data from over one year of production to date. Reservoir fluid samples were acquired with use of focused sampling techniques providing contamination free samples. Pressure measurements and many fluid properties are used to validate fluid equilibrium, including GOR and composition analyzed by the Cubic EoS, and a variety of markers in the condensate range, black oil range and the biomarker region. All analyses indicate equilibrium with the exception that the only two outliers in the asphaltene gradient curve are shown to be of different thermal maturity by utilizing the preferred biomarkers, the hopanes Ts and Tm. Moreover, the asphaltene abumdance in differently charged fluids varies by a factor of 6 while the maturity ratio Ts/(Ts+Tm) varies by 6% showing the sensitivity of asphaltene gradients for connectivity analysis. The modest levels of biodegradation (Peters- Moldovan rank=1) are used to constrain the petroleum system context of this reservoir considering that current reservoir temperatures significantly exceed biodegradation thresholds. There is evidence both that mildly biodegraded oil spilled into this reservoir and that some further biodegradation occurred in reservoir. Different gas-oil contacts in the field are associated with charge direction and show the limits of Cubic EoS for connectivity analysis in contrast to the good capability of the asphaltene gradients and FHZ EoS for this purpose. Moreover, the FHZ EoS analysis indicates that the asphaltenes are dispersed as a true molecular solution for this light oil in accord with the Yen-Mullins model of asphaltenes. Results from detailed whole-core and petrophysical analyses supports connectivity analysis. Core analysis shows the lack of any asphaltene deposition in the reservoir as expected from the fluid and asphaltene evaluations.
Advanced Well Positioning with Magnetic Interference Based on Passive Magnetic MWD Ranging: Case Study
Authors: Eatough Oliver , Alahmad Mohammad , Momot Fabien , Sikal AnaS , Reynaud Denis
Published: October 2018

This paper presents an efficient application of Passive Magnetic Ranging (PMR) on the B3 well sidetrack drilled on the High Pressure/High Temperature (HP/HT) Elgin field in the UK Central-North Sea. The planning and execution of this sidetrack presented an escalated set of challenges beyond those encountered in standard well conditions due to the high temperature (HT), the potential for magnetic interference and collision avoidance constraints. The PMR method was deployed in order to mitigate the risk of, and ultimately resolve, magnetic interference. This resulted in minimised collision risk and safe achievement of the sidetrack in a HT environment.

Challenges were faced in the 12 ½″ section which resulted in the open-hole being plugged and abandoned below the 14″ casing shoe, with the drill-string cemented in place. A complex sidetrack was planned below the 14″ shoe. Reservoir target and collision avoidance constraints required the planned sidetrack well-path to be close to the abandoned branch, therefore magnetic interference was possible. PMR was planned in the case of interference. The aim was to make the preparation and operational deployment process as efficient as possible, while drilling this sensitive section. A work-flow was developed to manage the performance of ranging passes, specifically interfaces between all parties involved in operations. PMR was deployed to map the relative position of the well during periods of interference and develop ‘synthetic surveys’ to construct the well-path, allowing collision avoidance calculations by defining reliable projection ahead and thus permitting steering of the drilling assembly.

The PMR process was successfully deployed on B3 after experiencing high magnetic interference allowing drilling to continue to planned depth with limited impact on operations. This paper provides information on the application of independent PMR and processing aspects to be considered when defining relative wellbore position based on synthetic surveys. Understanding advantages and limitations of PMR opens up opportunities to benefit from this technique in similar challenging drilling applications and help to reduce operational risk and optimise cost. PMR can thus provide a viable alternative to Gyro While Drilling (GWD), where conditions do not allow or where the probability of magnetic interference is marginal and high tool costs could be incurred when potentially not required.
Adsorption Isotherms and Permeability of Tight Shales Using Magnetic Suspension Balance Experiments
Authors: Ratnakar Ram R. , Dindoruk Birol
Published: October 2018

Adsorption and flow characteristics of methane and other natural gases onto tight rock formations is of economic interest for the proper evaluation and production of the field. In this work, a novel technique to enable the determination of adsorption isotherms and permeability of a gas in such formations through the transient analysis of experimental data from magnetic suspension balance is presented. Adsorption of gases onto the tight shale samples were measured using the magnetic suspension balance (MSB) apparatus at a constant pressure and temperature conditions. The current work presents the experimental technique in sufficient detail to allow others to replicate and evaluate the results. MSB has been proved a very effective tool for evaluating the adsorbed amount of gases onto tight shales/coals, especially when the adsorbed amount is very small. A mathematical model based on volume averaging is developed to describe the transient behavior of the MSB-set up, which was utilized to obtain the permeability of shale sample from experimental data.

A simple methodology, developed with a theoretical framework, is presented to obtain adsorption isotherm of a gas onto tight shale/coal sample and permeability of the sample. The methodology can be utilized to any type of adsorbing gases and shale/coal samples. In particular,

Experimental data for adsorption of methane onto a shale sample is presented at 50C and in the pressure up to 25bar using the MSB apparatus. The density of methane was also measured with MSB which shows very good match with the data available in literature, demonstrating that MSB can be an excellent tool for density measurement of gases. A simple method is developed to decouple the buoyancy effect and obtain the absolute adsorption isotherms. Most-importantly, a low-dimensional mathematical model based on volume averaging is developed to describe the transient adsorption process in MSB experiments, which was used to regress the experimental data and obtain the permeability of the shale sample. The permeability versus pressure plot shows the Klinkenberg effect, as expected. Further, the validity and accuracy of the model was verified by comparing the absolute permeability obtained from our method with an independent measurement using pulse-decay experiments.

The novelty of the work includes the development of a mathematical model describing the transient adsorption process in MSB experiments that can be utilized to obtain permeability of tight shale samples. In addition, the current work presents how to decouple the buoyancy effects to determine absolute adsorption isotherm. The methodology was tested and verified against the experimental measurements and can be utilized for industrial applications.
Sequence Mining and Pattern Analysis in Drilling Reports with Deep Natural Language Processing
Authors: Hoffimann Julio , Mao Youli , Wesley Avinash , Taylor Aimee
Published: October 2018

Drilling activities in the oil and gas industry have been reported over decades for thousands of wells on a daily basis, yet little effort was made to analyze this text in large-scale for information retrieval, sequence mining, and pattern analysis. Drilling reports contain interpretations written by drillers from noting measurements in downhole sensors and surface equipment, and can be used for operation optimization and accident mitigation. In this initial work, a methodology is proposed for automatic classification of sentences written in drilling reports into three relevant labels (EVENT, SYMPTOM, and ACTION) for hundreds of wells in an actual field. Some of the main challenges in the text corpus were overcome, which include the high frequency of technical symbols, mistyping/abbreviation of technical terms, and the presence of incomplete sentences in the drilling reports. This work describes state-of-the-art classification accuracy obtained within this technical language and illustrates advanced queries enabled by the tool.
First Application of Fiber Based LCM in Srednebotuobinskoe Oilfield, Russia
Authors: Belyakov Andrey , Panov Maksim , Shirokov Ilya , Silko Nikita
Published: October 2018

Lost circulation is one of the main causes of nonproductive time during drilling in Eastern Siberia. In Srednebotuobinskoe oilfield major challenges are related to severely fractured igneous rock intrusion. Drilling through this interval is associated with constant severe to total losses. As a result, drilling velocity may drop below one meter per hour. Significant reduction of drilling time was achieved with application of an innovative fiber based LCM. Current paper describes results of this project.

Curing losses in severely fractured igneous rock formations is challenging. In most cases the fracture width is not known; it can only be predicted. However, this prediction is not always accurate.

An engineered fiber-based kill fluid was used to mitigate this lack of knowledge. Laboratory tests demonstrated ability to plug 1-5 mm fractures. System was applied in two wells in Srednebotuobinskoe oilfield. Fiber based pill was used in a combination with conventional LCMs. Additional operation time reduction was achieved by BHA compatibility. Average velocity of drilling through igneous rock interval was further compared to offset well from the same pad.

Drilling through 140 meters igneous rock interval of the well took around 147 hours. Conventional LCM are sensitive to fracture width. Due to geological complexity of the interval they had limited efficiency. A novel LCM based on soft, short fibers allowed to overcome this problem. It has a dual plugging mechanism. It can bridge across fractures up to 5 mm and form a filtercake on the formation surface, mitigating losses to the fractures network.

Applying this innovative solution in the 225 meters igneous rock interval of the second well (same pad) allowed to reduce drilling time to 119 hours. Thus, drilling became two times faster. Fiber based pill is also compatible with BHA, including telemetry. So additional time was saved on POOH/RIH operations. For the third well on the same pad pill placement strategy was further optimized. So, 135 meters igneous rock interval was completed in 23.5 hours. Drilling became 6 times faster comparing to the first well. Fiber based LCM showed high efficiency for mitigating severe losses in igneous rock intervals of Srednebotuobinskoe oilfield. BHA compatibility allowed to avoid additional POOH/RIH operations, providing extra value. Application of fiber based LCM led to significant acceleration of drilling igneous rock intervals.

The pill was prepared on the well site with equipment available. Compatibility with surface and downhole equipment was also confirmed.

Various successful field applications of fiber-based pills have been reported from various parts of the world. Current work presents first application of an engineered fiber based pill in Srednebotuobinskoe oilfield, Russia. The pill was pumped successfully in 2 wells in igneous rock intervals. Pill was placed through BHA. This solution allowed operator to achieve 6 times reduction of time required to complete the interval.
Wettability Quantification in Mixed-Wet Rocks Using a New NMR-Based Method: Experimental Model Verification
Authors: Newgord Chelsea , Tandon Saurabh , Rostami Ameneh , Heidari Zoya
Published: October 2018

Nuclear Magnetic Resonance (NMR) measurements have been attractive options for fast wettability characterization of rocks in petroleum reservoirs. Several NMR-based wettability indices are documented in previous publications. These methods often require calibration at irreducible water and residual hydrocarbon saturations, which complicates their applicability in mixed-wet rocks at different fluid saturations. We recently analytically derived a new NMR-based wettability index and confirmed its reliability using pore-scale NMR simulations. This new model only requires calibration at fully water- and hydrocarbon-saturated states for different wettability states ranging from water-wet to hydrocarbon-wet. In this paper, we experimentally quantify the influence of wettability on NMR measurements and verify the reliability of the new NMR-based wettability model in the core-scale domain for partially-saturated rocks.

First, we measured the transverse relaxation (T2) distribution of the unmodified water-wet samples using a 2-MHz NMR spectrometer in selected core samples. Then, we modified the wettability of two samples by injecting anionic surfactants. For the third sample, we injected a naphthenic acid and decane solution into the core. We quantified the wettability of these samples using the Amott-Harvey method and sessile drop contact angle measurements. Next, we measured the T2 distribution of the water-, mixed-, and hydrocarbon-wet samples at partially water- and hydrocarbon-saturation states. Finally, we assessed the wettability of these samples using the new NMR-based method and compared the wettability estimates to those obtained from the Amott-Harvey wettability method.

We measured the wettability of the core samples to be in the range of −0.6 to 0.5 on the Amott-Harvey index. The calculated NMR-based wettability for the altered core samples were in the range of −0.66 to 0.51, which was in good agreement with the wettability estimates from the Amott-Harvey method. The experimental results demonstrated that our new NMR-based wettability model successfully estimates the wettability of mixed-wet rocks in a wide range of wettability and eliminates the need for calibration at irreducible water and residual hydrocarbon saturations. The outcomes can be used to improve the speed and reliability of NMR-based wettability characterization. The results from these core-scale measurements are promising for application of the introduced model to log- and field-scale wettability assessment in mixed-wet rocks with complex pore-structure and at different fluid saturations.
High-Performance Inhibitive Water-Base Fluid System for Drilling Challenging Wells
Authors: Voitenko Dmitry , Ignatyev Sergey
Published: October 2018

This article addresses the general results of using a high-performance inhibitive water-base fluid system for drilling horizontal extended reach wells (ERD) and two-casing wells on a field in West Siberia, Russia. It also reveals potentialities for drilling even more challenging wells, as well as prospects for future projects where drilling fluid systems of this type can be used.
High Salinity Swelling Polymeric Particles for EOR
Authors: Panthi Krishna , Sharma Himanshu , Lashgari Hamid , Mohanty Kishore
Published: October 2018

Most carbonate reservoirs have fractures which have a detrimental effect on sweep efficiency during oil recovery. The objective of this research is to block the big fractures with polymeric particles and divert the injection fluid into the matrix for better sweep efficiency during CO2 floods. Polymeric particles have been developed that swell as salinity is increased. These particles are termed SISPP or salinity induced swelling polymeric particles. SISPPs swell more in higher concentration brine contrary to common polymeric particle gels (PPGs) which shrink. Water flood and miscible floods are conducted in fractured cores with SISPP placed in the fractures. The SISPP placement increases oil recovery in fractured cores during high salinity water floods and miscible/CO2 floods. Furthermore, a model for particle swelling, and the concomitant change in permeability, as a function of brine salinity was implemented in UTCHEM, and single phase and oil recovery corefloods were modeled. UTCHEM simulations showed good agreement with the experimental results.
Safe Choice – Operationalizing Human Performance Science in Decision-Making
Authors: Santamaria Carla , Flood Jim K. , Schuberth Paul C. , Morell Jorge J. , Hinojosa Jaime R. , Haddock Justin , O'Donnell Hugh , Sandelands Eric , Cowan Mel , Higgins Alan
Published: October 2018

An approach for enhancing safety performance in Energy Industry field applications by integrating decision-making science will be presented. Results – both qualitative and quantitative – will demonstrate step change potential in safety performance in pursuit of plateau breakthrough to zero high severity incidents. Safe Choice empowers and enables safe decision-making at all levels of an organization by providing new knowledge and techniques, and linking these to current behavioral based safety practices.

Emerging understanding about brain and social science, as it relates to Energy Industry safety, is provided in practical discussion centered around decision-making. Workforce members are entrusted and empowered with new knowledge, personal decision-making style survey results, and an appreciative inquiry discussion that integrates brain science concepts in a simple effective way to their existing, familiar work processes and tools for managing safety and risk in their operating, drilling, and construction field sites. Following Safe Choice, individuals have a greater understanding of their own human performance and decision-making. Focusing on individual learning and awareness is the differentiator.

The program was first developed for the ExxonMobil Hebron Project integration, hook-up and commissioning construction site in Newfoundland and Labrador, Canada during 2015-2016. Together, with other transformational safety leadership initiatives, Safe Choice contributed to best-in-class safety performance. Safe Choice was then further developed and adapted for application within operating field sites during 2017. With further success, the program is now being implemented globally with an agile, user-centered design philosophy and approach.

The small group approach to training includes each worker receiving an individual decision-making style report and creates an atmosphere of appreciative inquiry, trust and openness. Developing leadership supporting strategies that foster a continuation of this atmosphere once back in the field (and outside of the classroom) has proven effective, with use of the new language and concepts evident in regular daily meetings such as toolbox talks, shift handover and safety meetings, as well as being used between workers during conversations in the field. Many locations where Safe Choice has been implemented have excellent safety performance, and will show both qualitative and quantitative measures of success achieved.

Energy Industry Leaders, Operations, Drilling, Construction and Safety Professionals will gain new knowledge on successful next-step integration of decision-making science into safety programs for protecting their workforce. This will expand and extend earlier insights from panel discussions at SPE HSSE Meetings in New Orleans (April 2017) and Abu Dhabi (April 2018). This paper includes results of the program so far.
Novel Analyses and Design of Relief Wells Considering 3D Effects
Authors: Sweeney Eugene , Zhou Lei , Gomes Paulo , Knight James
Published: October 2018

In developing a relief well contingency, current industry standard practice is to use a one-dimensional (1D) multiphase flow model to determine the requirements such as pump rate and mud weight to kill the blowout well. However, this does not consider certain variables. For instance, this analysis returns the same results regardless of the intercept angle of the relief well (i.e. results are identical if the relief well intercepts at a steep angle into the direction of flow, or if it intercepts at a steep angle in the same direction of flow).

A novel approach has been developed that considers the three-dimensional vector effects when a blowing out well is killed by means of a relief well intercept. This analysis offers safety and environmental benefits for well kill design and operations because it provides results which more accurately reflect the physical principles. This allows for optimization of a relief well design. For instance, this more comprehensive analysis allows the possibility to design a relief well with shallower intercept depth and lower pump requirements with the potential for an earlier kill.

This new method considers the complex interaction of the countercurrent flow that occurs at the relief well intercept and can utilize computational fluid dynamics (CFD). This enables optimization of parameters previously not considered such as specific spray design from the relief well. For instance, industry currently assumes that there is an advantage to pumping the kill fluid down the annulus of the relief well. The frictional losses are lowered (compared to pumping down the drillstring), thereby minimizng the pump requirements and maximizing the achievable rate for given pump capability. Whilst this may indeed be the case, the research covered in this paper shows that, depending on the circumstances, there can be a benefit to designing the spray pattern from the flow from the relief well at the intercept.

Various relief well kill cases were analyzed by both the standard method and the new method and the results compared. The new method predicted that relief well kills could be made with lower rates and pressures than predicted by the standard model. Using the new method offers an opportunity to increase the accuracy of relief well planning, enabling a more precise understanding of what may be achievable.

A test apparatus was designed and created to verify which of the two methods was more accurate. Physical experiments indicate that results from the proposed method match the test results closer than the standard approach.
Viscous Slickwater as Enabler for Improved Hydraulic Fracturing Design in Unconventional Reservoirs
Authors: Zhao Haiyan , Danican Samuel , Torres Hortencia , Christanti Yenny , Nikolaev Max , Makarychev-Mikhailov Sergey , Bonnell Andrew
Published: October 2018

The development of unconventional fields has experienced major efficiency gains. One main breakthrough in efficiency is the introduction of viscous slickwater fracturing fluids. Viscous slickwater enables placement of higher proppant concentration than conventional slickwater and is less damaging than guar-based fluid, leading to aggressive fracturing designs and improved production.

High viscosity friction reducer is the main component in viscous slickwater, which can replace hybrid and crosslinked fracturing fluids in unconventional reservoir completions. The successful application of high viscosity friction reducing fluid requires proper fluid hydration and adequate viscosity, which depends on water salinity and proppant concentration. We developed techniques for improved testing of friction reducers and friction reducer selection guidelines to support optimum placement of the fracturing design. A comparison of production results of wells fractured by viscous slickwater to those offset wells demonstrated the effectiveness of aggressive design with viscous slickwater fluids.

A high viscosity friction reducer was tested in the laboratory and applied in the field. Experimental data demonstrate a good correlation between low shear viscosity and proppant transport capability. Static and dynamic proppant transport data were used to design viscous slickwater to replace linear gel. The friction reducer has been successfully applied in the field in more than 3,000 stages. Formations that were traditionally fractured with crosslinked gel were successfully fractured using viscous slickwater with ease. Replacing conventional slickwater with viscous slickwater enables the transport of higher proppant concentration with little change in operations. Aggressive designs deliver a boost in production, thus confirming viscous slickwater as the fluid of choice.

Improved chemistry enables easier operations, faster well completion, and improved initial production, as confirmed by case studies. This study provides information for the application of viscous slickwater and the rigorous testing that is required and often overlooked.
New Kick-Off Procedure with RSS Reduces the Operation Time by 92%. Western Siberia Experience.
Authors: Teregulov Oleg , Shakurov Rafael , Sirotin Denis
Published: October 2018

Drilling multilateral (fishbone) wells in western Siberia is a common practice. A particular characteristic of these wells is the kickoff in the openhole horizontal section—no cement plug or whipstock is used. In the overwhelming majority of wells, it is economically impractical to perform tripping procedures twice—to change the bottomhole assembly (BHA) for the kickoff, and change it again for subsequent drilling. To reduce the well construction time, one requirement is to drill the horizontal section in one run.

Many operators have realized the advantages of using rotary steerable systems (RSS) for drilling multilateral wells that are becoming more complicated. During a well startup, the use of RSS to drill fishbone wells caused some concern about kickoff procedures. The operator had no experience with the process due to the analogue of adjustable kick-off sub (AKO) on the positive displacement motor PDM absence. The first kickoffs were made and resulted in a significant time increase compared to the same process with (PDM): 26 to 28 hours instead of 16 to 20 hours. Further experience with using kickoffs with RSS resulted in procedures and process improvements.

Based on the experience gained, a new kickoff procedure with RSS was tested at more than 20 jobsites in Western Siberia. A notable record was achieved on one of the multilateral wells on March 18, 2018 at the job for Lukoil-Zapadnaya Sibir Ltd. The kickoff in the open horizontal section was made in 1 hour 40 minutes, whereas the standard procedure took 20 hours 30 minutes. The time reduction of the kickoff process was 92% compared to the standard procedure, and 17% compared to the previous set record. The next stage of this technology will be its application in Eastern Siberia, with some modifications based on the lithostratigraphic section of the target horizon.
Application of Discrete Element Method for Modelling Sand Control Systems
Authors: Lezhnev Konstantin
Published: October 2018

Sand production is a major problem on weakly-consolidated fields. To limit the sand flow into the well, downhole filters are used. Filter sizing criteria, however, only work for a narrow range of rocks. Optimal sizing criterion suggests size of filter pores small enough not to let coarse particles to enter the well, but big enough so that skin-factor would not be too big. The aim of this article is to propose a method to create universal sizing criteria for any rock and filter type.

To model suspension flow through filter Discrete Element Method (DEM) was used. It suggests modeling system on the scale of single rock grains, which allows reconstructing all the microscopic mechanisms and interactions during filtration process. Particles were spherical, their sizes differed from 40 to 1400 μm. Interactions between particles were via Hertz forces. Different types of filters were considered: slotted liners (SL) and Gravel Packs (GP).

Based on the DEM models number of numerical experiments was carried out. Recomendations to sizing criterions and a method to evaluate Gravel Pack's skin-factor are proposed.
Evolution of Natural Gas Business Model with Deregulation, Financial Instruments, Technology Solutions, and Rising LNG Export. Comparative Study of Projects Inside the US and Abroad
Authors: Talipova Amina , Parsegov Sergei
Published: October 2018

One of the primary energy sources, natural gas is widely used for power generation, industrial production, transportation, commercial buildings, and households. The industry is a capital intensive one for all stages from exploration to delivery. Two types of supplies: pipeline and Liquefied Natural Gas (LNG), recently have faced a direct intra-industrial competition. Physical nature of methane and associated transportation costs lead to domination of so-called "natural monopolies" or "national champions" and strict government regulation, which postponed the development of free trade and competition. After decades of technical innovations and cost curve improvement in LNG sector, increasing global energy consumption, shale boom in the USA, and demand for supply diversification reformulated the role of gas in the global energy balance. While the pipeline sector remains to be in the hands of large corporations and a subject of strategic interstate and international agreements, LNG provides more diversity and flexibility of trade. However, even after a long history of LNG shipment since the late 1950s, this market is still regional with high spreads between countries and terms of delivery.

The paper presents the evolution of business models in the natural gas industry, focusing on the primary drivers as government regulation, technologies, and regional markets trends on the way to liberalization and cointegration. Thus, our primary objective is to show relative influence power of these drivers. This analysis also defines the competitiveness of corporate business model under conditions of asymmetric information in regional gas markets, deregulation trends, fast-growing production technologies and downstream infrastructure (specifically in the LNG sector). We also enclose the analysis of the most globally competitive gas projects. We analyze changes in value chain change and trading contracts. Our methodological approach poses model-based principles, including option and contract models, jointly with game theory elements.
Application of Low-Temperature Separation Technology for the Field Processing of Achimov Gas: Challenges and Opportunities
Authors: Ahnert Falk , Chepurnov Aleksandr , Driever Heinrich , Fritz Michael , Kubanov Aleksandr , Istomin Vladimir , Prokopov Andrey , Fedulov Dmitriy , Snezhko Daniil , Dubnitsky Roman
Published: October 2018

During recent years the active development of Achimov deposits in the Urengoy oil and gas-condensate field has begun. The development of these deposits will not only reduce the gas production decline rate from traditional Cenomanian and Valanginian deposits, but will also allow to increase the production of liquid hydrocarbons. The cumulative extraction of gas from these deposits in 2017 exceeded 20 BCM, while production of the hydrocarbon condensate (including unstable and deethanized) amounted to approximately 9 million tons. It is planned to reach the production level of Achimov gas in Urengoy field of 40 BCM/year [1 - 3]. Achimov deposits were discovered in other fields as well, for example in the Yamburg field.

The activity of Wintershall Holding GmbH for development of the Achimov deposit is represented by two Joint Ventures with PAO Gazprom – AO Achimgaz with the operating Gas Treatment Plant UKPG-31 [4] and OOO Achim Development with the future UKPG-41 and UKPG-51.

These plants are designed for gas treatment in accordance with STO Gazprom 089-2010 and extraction of unstable gas-condensate with the properties according to STO Gazprom 5.11-2008 as well as Technical Specifications TU 05751745-02-88 "Unstable gas-condensate in mixture with the associated oil". The composition of unstable condensate (UC) includes not only hydrocarbons C5+, butanes and propane, but ethane and even methane as well. The target components for further processing are the hydrocarbons C5+ and propane-butane fraction.

Field gas treatment at the gas-condensate fields of the Extreme North is mainly performed using the low-temperature separation technology (LTS). The natural gases of Achimov deposits are characterized by the following properties, which allow the identify them as a separate research object [3].
A Large-Scale Study for a Multi-Basin Machine Learning Model Predicting Horizontal Well Production
Authors: Amr Salma , El Ashhab Hadeer , El-Saban Motaz , Schietinger Paul , Caile Curtis , Kaheel Ayman , Rodriguez Luis
Published: October 2018

This paper proposes a set of data driven models that use state of the art machine learning techniques and algorithms to predict monthly production of unconventional horizontal wells. The developed models are intended to forecast both producing locations (PLs) and non-producing well locations (NPLs). Furthermore, results of extensive experiments are presented that were conducted using different methodologies and features combinations. Results are measured against conventional Arps's decline curve analysis showing significant boost in prediction accuracy for both NPLs and PLs. The most accurate model outperforms Arps's-based estimates by almost 23% for NPLs and 36% for PLs. Results also show that using data from multiple basins in training models for another basin yields gains in accuracy, especially for basins with relatively small data.
Pressure Effects on Low-Liquid Loading Oil-Gas Flow in Slightly Upward Inclined Pipes: Flow Pattern, Pressure Gradient and Liquid Holdup
Authors: Rodrigues Hendy , Pereyra Eduardo , Sarica Cem
Published: October 2018

This paper studies the effects of system pressure in oil-gas low-liquid loading flow in a slightly upward inclined pipe configuration using new experimental data acquired in a high-pressure flow loop. Flow rates are representative of the flow in wet gas transport pipelines. Results for flow pattern observations, pressure gradient, liquid holdup and interfacial roughness measurements are presented and compared to available predictive models. The experiments were carried out at three system pressures (1.48, 2.17 and 2.86 MPa) in a 0.155 m ID pipe inclined at 2° with the horizontal. Isopar-L oil and nitrogen gas were the working fluids. Liquid superficial velocities ranged from 0.01 to 0.05 m/s while gas superficial velocities ranged from 1.5 to 16 m/s. Measurements included pressure gradient and liquid holdup. Flow visualization and Wire-Mesh Sensor (WMS) data were used to identify the flow patterns. Interfacial roughness was obtained from the WMS data.

Three flow patterns were observed: pseudo-slug, stratified and annular. Pseudo-slug is characterized as an intermittent flow where the liquid does not occupy the whole pipe cross-section as the traditional slug flow does. In the annular flow pattern, the bulk of the liquid was observed to flow at the pipe bottom in a stratified configuration, however, a thin liquid film covered the whole pipe circumference. In both stratified and annular flow patterns, the interface between the gas core and the bottom liquid film presented a flat shape. The superficial gas Froude number, FrSg, was found to be an important dimensionless parameter to scale the pressure effects on the measured parameters. In the pseudo-slug flow pattern, the flow is gravity-dominated. Pressure gradient is a function of FrSg and vSL. Liquid holdup is independent of vSL and a function of FrSg. In the stratified and annular flow patterns the flow is friction-dominated. Both pressure gradient and liquid holdup are functions of FrSg and vSL. Interfacial roughness measurements show a small variation in the stratified and annular flow patterns. Model comparison gives mixed results, depending on the specific flow conditions. A relation between the measured interfacial roughness and the interfacial friction factor is proposed, and the results agree with existing measurements.
Surface to Borehole Electromagnetics for 3D Waterflood Monitoring: Results from First Field Deployment
Authors: Colombo Daniele , McNeice Gary , Cuevas Nestor , Pezzoli Mauro
Published: October 2018

Monitoring the waterflood oil recovery process is a difficult task for seismic-based methods in hard carbonate reservoirs. The changes in velocity/density due to water-oil substitution are too small when compared to the errors involved in repeating the measurements. We detail the development of a novel technique based on surface-to-borehole controlled-source electromagnetics (CSEM), which exploits the large contrast in resistivity between injected water and oil to derive 3D resistivity distributions (proportional to saturations) in the reservoir. Surface-to-borehole CSEM responses using surface electric transmitters and borehole EM receivers were modeled using a black-oil simulator for a large oil field in the Middle East. Results indicate that the vertical electric field can be used to detect waterfront changes in 2 and 5-year time-lapse scenarios. A surface-to-borehole acquisition system was engineered comprising the development of a powerful, custom-made electric transmitter (2000V/500A) and borehole electric and magnetic field sensors. The surface-to-borehole 3D CSEM technology was deployed for the first field trial in the same well used for the modeling study. The field demonstration was carried out in 2017 comprising 144 permanent surface electrodes drilled in a radial configuration around a vertical observation well. The current electrodes were designed in an L pattern to form 48 inline (radial) and 48 cross-line (tangential) dipoles at a nominal range of 600m to 3,500m from the vertical observation well. A wireline sensor array comprising two vertical electric and two vertical magnetic field sensors recorded the EM signal transmitted from the surface in regularly spaced positions in the reservoir section. Surface measurements of transient EM (TEM), CSEM and magnetotellurics (MT) were recorded together with the borehole acquisition to characterize the overburden and the shallow subsurface. The acquired dataset was processed to increase the signal/noise content of the data as well as to correct for casing effects and surface distortions. A marked asymmetry of the EM responses is recorded in the vicinity of the observation well which translates, after 3D inversion, to resistivity distributions consistent with the saturation/production logs acquired in the nearby wells. The sensitivity of the inversion extends up to 1.8 km away from the observation well. Analysis of the measurement repetition errors compared to predicted EM responses after 2 and 5 years indicates that time-lapse surveys would provide detailed mapping and an independent estimation of saturation variations related to waterflooding. The encouraging results obtained from the first surface-to-borehole CSEM survey in a producing oil field suggests that the technology may become an important tool for analyzing the waterfront evolution in the interwell space. By doing this, the technology is expected to enhance reservoir management and history matching.
Artificial Intelligence–Driven Asset Optimizer
Authors: Gupta Supriya , Sharma Abhishek , Abubakar Aria
Published: October 2018

Currently, as oil and gas companies continue to face risk of volatility in oil prices, production optimization and maintenance play a critical role in driving operational excellence for the industry while maintaining good profit margins. E&P companies must maintain a focus on reducing unit cost/barrel. This can be achieved by reducing operating costs, increasing production, and reducing downtime. We propose a recommendation engine driven by artificial intelligence (AI) that seamlessly integrates subsurface information and production characteristics for knowledge extraction needed to optimize production operations across conventional and unconventional assets. We used a three-phase approach to designing and building an advisory system that ingests data, learns patterns, and feeds these learnings from the data into different functional workflows necessary for improving the efficiency and effectiveness of production operations. The system uses these mechanisms of knowledge extraction, statistical learning, and contextual adaptation as it evolves into an autonomous asset optimization system that can proactively recommend actions for effective decision making to lower the unit cost/barrel.
ESP Surveillance and Optimization System in Smart Fields of Salym Petroleum Development
Authors: Gorlov Alexander , Musorina Anastasia , Terebennikov Valery , Safonov Victor
Published: October 2018

In current conditions of oil and gas production the highest significance is the use of intellectual control technologies improving operational activities of the company. The main task of intellectual system is optimization of production, technical solutions, processes of planning and operational expenditures.

SPD pays significant attention to issues of optimization of oil production and production energy efficiency, and in this relation in the beginning of 2016 the company developed and implemented a program of daily analysis of production well stock operation and making decisions on optimization of their operating modes called “Optimization Register".

This system is integration of well and equipment operating parameters in real time mode and technical information from different databases into one base with automatic check of data correctness. This allows to promptly draw attention of Analytical Engineer to arising problems with the well, create a request for actions to re-establish operating mode and send the request to responsible persons for implementation of required actions to stabilize its operating mode. All requests are created in the program and automatically sent to performers. Time of request submission and its closure is strictly recorded by the program, which allows to assess prompt work of different services in the company.

Automatic detection of destabilization of well and/or equipment operating mode, creation and implementation of requests within limits of work optimization now presents a closed cross-functional cycle of information delivery allowing each participant to have all updated information on specific well and leave comments related to his/her responsibility area.
Observations and Complexities in Experimental Measurement of Acid Fracture Conductivity for a Deep Carbonate Field in Kazakhstan
Authors: McDuff D. , Malhotra S. , Comeaux B. A. , Quintero B. W.
Published: October 2018

Acid fracture conductivity experiments provide information valuable to effective design of acid fracture stimulation treatments in carbonates. They are complex tests, and a number of procedural details must be taken into consideration in order to upscale results to an adequate representation of well-scale acid fracture behavior for well productivity predictions. This paper focuses on a study performed on analog, quarried limestone core samples and a small number of reservoir core samples from the Unit 2 formation of Kazakhstan's Tengiz field to understand the impact of different acid fluid systems and procedural steps on acid fracture conductivity.

The physical structure of the etched channels is observed to be impacted by the nature of the fluid and has a strong impact on the conductivity. The quality and uniformity amongst the core samples has a critical impact on the measurements and is assessed. The residence time of the acid in the acid-etched experimental channel is small, and the equivalency of acid volumes injected at the experimental scale to the large acid volumes injected into a well-scale fracture channel is considered. Special consideration is given to the procedure of applying stress to and measuring conductivity of the experimental acid fracture channel which may result in large-scale mechanical failures of the core sample, preventing a high-quality measurement of conductivity following injection of a closed fracture acidizing stage.

This body of work discusses the design options and challenges which play a role in defining the testing strategy for an acid fracture conductivity study. Results demonstrate that with selection of appropriate fluid systems, acid fracture conductivity can be retained up to a closure stress of 6,000-7,000 psi in the Tengiz Unit 2 reservoir. A modified stress ramp-up procedure to improve closed fracture acidizing conductivity testing results obtained through the testing program is presented.
Flow Velocity Estimation in Horizontal Oil Wells Using the Method of Thermal Flowmeter Based on the Fiber-Optic Distributed Permanent Monitoring System
Authors: Ipatov Andrei , Kremenetskiy Mikhail , Lazutkin Dmitry , Skopintsev Sergei , Sharovarin Evgeniy
Published: October 2018

The current improvement of temperature logging informative value in horizontal wells is considered in the article. Examples of production logging in wells with multistage hydraulic fracturing (multi-fracs) and the features of their interpretation are given. The role of temperature logging in the modern complex of production logging gages is considered. The advantages and limitations in the applicability of the methods of classical temperature logging are distinguished, the possibilities of long-term temperature monitoring using the fiber-optic sensor system distributed along the well are considered.

Aim of the present work is to show new findings in the theory of thermal flowmeter on base of fiber-optic data for evaluating the inflow intervals and determining the fluid flow velocity in the horizontal well bores.

The authors proposed a new method of field production monitoring, based on the use of a fiber-optic distributed measuring system as a thermal flowmeter, that is heating a fiber optic cable certain section in order to get from it characteristic of temperature relaxation during its cooling. A mathematical model is developed that justifies the efficiency of the solution and a plan for experimental confirmation of the theory with mathematical calculations is drawn up.
Feasibility Testing of a Pilot-Scale Two-Stage Biofiltration Unit for Mitigating VOC Emissions from a Wastewater Sump
Authors: Khoramfar Shooka , Jones Kim , Boswell James , Shah Aditya , Aggarwal Shubham , Ghobadi Jalil
Published: October 2018

Volatile organic compounds (VOCs) present in crude oil can be released to the atmosphere from storage tanks, wastewaters and equipment leaks in petroleum industries. A pilot-scale sequential biotrickling-biofiltration (BTF-BF) unit as an environmentally safe and economical treatment procedure was designed and tested for removal of VOCs from a wastewater sump at the CITGO Corpus Christi Refinery. To identify and quantify VOC emissions from the refinery wastewater sump, the air was sampled using 6 L canisters and characterized using gas chromatography-mass spectrometry. The pilot-scale unit included a BTF for removal of more water soluble compounds followed by a BF for removal of poorly soluble compounds. Performance of the BTF and BF units containing plastic cross flow and compost-based media were investigated at pollutant loading rates of 6 g/m3hr to 1750 g/m3hr.

The characterization results of the pilot test showed benzene as the main constituent of the vapor stream (85% of vapor) emitted from the wastewater sump. The ratio of benzene to toluene and xylene was determined to be 12:2:1 in these samples. The high concentration of benzene as an amenable food and energy source for the microorganisms lead to high biomass growth and more than 85% removal efficiency (RE) for total emitted VOCs.

Application of an innovative sequential biotrickling-biofiltration unit was also demonstrated to effectively handle the cyclic emissions of VOCs at most oil and gas industries. Although several researches have been done to evaluate the performance of BFs and/or BTFs in the laboratory, this pilot study can be used to design and optimize the performance of a bio-oxidation unit under actual refinery operating conditions.