bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Performance of Multiple Completion Designs: Openhole, Slotted Liner, ICD, and AICD: A Case Study for Water Control in Villano Field, Ecuador
Authors: Andrade Alejandro , Chango Mario , Atahualpa Gustavo , Correa Ramón , Corona Georgina , Calvopina Byron , Pico Juan
Published: October 2018

This paper presents an analysis of the effectiveness of various downhole completion designs in reducing or deferring water production in a mature field under the presence of an active strong aquifer reservoir. The results of completions using nozzle inflow control devices (ICDs) and fluidic diode autonomous ICDs (AICDs) are compared with conventional openhole and slotted liner completions. As all of these designs were installed in the same field/reservoir, the comparisons provide a meaningful and representative analysis of well production performance to assist in the identification of the most appropriate completion design for future wells and the production optimization of existing ones. The designed vs. actual production performance of inflow control completions providing water control (ICD/AICD) is presented and discussed.

The methodology was developed from comparative analysis results of conventional openhole and slotted liner vs. ICD and AICD completions. The analysis was primarily based on elapsed time comparisons for water/oil ratio (WOR) and water cut (WC) and used diagnostic plots to identify the water production mechanisms, historical drawdown (DD), productivity index (PI), and production cumulative performance (oil and water). The corrective actions are described, including operational procedures to reduce skin damage and screen plugging implemented in the Villano-23HST2 (V-23HST2) well, which is the longest horizontal well drilled in Ecuador and completed using AICDs; these corrective actions were based on lessons learned from the Villano-22D (V-22D) well, which included appropriate fluid [brine/oil-based mud (OBM)] conditioning, fluid displacement, filter cake removal, and compatibility testing between screens and the fluid in which the bottomhole assembly (BHA) was deployed. Additionally, this paper evaluates the importance of the design phase, emphasizing the importance of comparing preliminary data (permeability and water saturation) compared to actual results obtained from the initial production test. Finally, as good production results largely depend on successful operational procedures and execution, lessons learned and best practices for deploying downhole completions in future operations for the Villano field in Ecuador are discussed.

Although many studies compare ICDs vs. conventional completions, few compare different inflow control technologies, such as ICDs vs. AICDs, within the same reservoir and with similar well conditions. This paper compares various inflow control technologies in the same field with cumulative production data, which verifies the effectiveness of each completion design. Based on these results, a validated methodology for ICD and AICD simulations and design is also described as the basis for achieving good production results.
Conceptual Approach for Gas Field Clusters Development in Terms of Synergy Effect
Authors: Buchinskiy Stanislav , Kovalenko Alexander , Permyakov Alexander , Khakimov Artur , Savchuk Danil
Published: October 2018

The article is devoted to creation problems of the strategy for involving of fields group in development, taking account of geological, logistic, organization factors, and aspects of forming the unite field facilities construction.

In the present work the importance of conceptual approaches while planning of involvement in development of quite small fields group that are relatively near to each other is described.

The main trends of complexation are: The choice of the most effective development variant for every development production zone;The optimizing of project well stock and gathering schemes;The points of preparation and transportation products taking account of possible synergy.

A particular attention was paid to the interaction abovementioned factors for achievement a maximum techno-economic efficiency of the project.
Mechanistic Modeling of Gravity Film Drainage Using Relative Permeability Equation of State
Authors: Khorsandi Saeid , Johns Russell
Published: October 2018

The double-displacement process (DDP) in dipping reservoirs has resulted in large oil recoveries with low operating costs. The large recoveries in the field result from high sweep efficiency and very low residual oil saturation, where very low saturation is obtained by oil flow through thin spreading films. Oil spreads to saturations near zero owing to competing interfacial tensions at contact points between three phases (oil, water, and gas). Experimental studies with micromodels and pore scale imaging support oil flow through films, where the rate of recovery and film drainage are controlled by parameters such as fluid compositions and topology of the water and gas interface within a give pore morphology. The interface topology is largely controlled by phase saturation, gas phase connectivity, pore structure and fluid wettability. Current relative permeability models, however, do not model spreading reliably as they do not include a mechanistic model for dynamics of film spreading on relative permeability.

We use the relative permeability equation of state (kr-EOS) to mechanistically model dynamics of film spreading and its effect on relative permeability. The reconnection of oil phase by spreading is modeled with a compositional evolution function for Euler characteristic. The IFTs and spreading coefficients are calculated based on phase compositions. Then, the physically based kr-EOS is implemented in our in-house fully compositional reservoir simulator. The simulation results are compared to published core flood and field data. We also performed a sensitivity analysis to determine the effects of gas and oil composition, miscibility, and reservoir heterogeneity on recovery rates and timing. These results show that saturation profiles from simulation are similar to those observed from CT-scanning of core floods, demonstrating good accuracy from the new mechanistic relative permeability model.
Geochemical Productivity Index, Igp: An Innovative Way to Identify Potential Zones with Moveable Oil in Shale Reservoirs
Authors: Piedrahita Jaime , Aguilera Roberto
Published: October 2018

A method is presented to identify intervals in shale oil reservoirs that contain moveable hydrocarbons with a novel geochemical productivity index, Igp. This index merges 3 important rock properties that always have to be considered for sound shale oil reservoir characterization: vitrinite reflectance (%R°), oil saturation index (OSI), and free water porosity (ϕFW). Integration of this index with other petrophysical properties and geomechanical parameters leads to define intervals with moveable oil.

Shale oil is both source and reservoir rock. Hence, it is critical to know both its organic matter maturity and oil/water flow capacity. The introduced Igp considers these features simultaneously; maturity is evaluated by discretizing %Ro from 0 to 1 depending whether the rock is immature or not; free oil flow capacity is modeled normalizing OSI between 0 and 1 based on results from Rock-Eval pyrolysis (REP) obtained in the laboratory or electric logs; and water flow capacity is estimated from ϕFW, obtained with the use of NMR log, which is transformed to an index between 0 and 1.

Use of the Igp is explained with real data from a vertical well that penetrates several stacked shale oil reservoirs. However, the same approach can be used in any other kind of wellbore architecture (deviated, horizontal, geosteered). Initially, a correlation between vertical depth and %R° is developed. This results in a continuous organic matter maturity curve along the well section. Next, OSI is simulated with the use of a bin porosity from NMR log, where T2 is between 33 and 80 ms and is correlated with OSI data from REP. As a result, a good match between simulated and real OSI data is achieved. Similar to OSI, ϕFW is also calculated from the NMR log but using a bin porosity when T2 is greater than 80 ms. All these 3 parameters are transformed to partial indexes, which are combined into a unique index, Igp. When the index is greater than 0.66 there is a good chance that the 3 conditions mentioned above will be met. For the example well considered in this study, it was found that almost 30% of total vertical section has good moveable oil potential. This corresponds to 10 intervals in the well.

The key novelty of the paper is that it develops a continuous curve of an index that is easy-to-use and is powerful for identifying intervals with moveable hydrocarbon potential. This is true even in those intervals without laboratory data due to the continuity of the Igp curve. In addition, the Igp integrates criteria that are usually applied independently.
Recently Announced Reforms in the Russian Domestic Gas Market: Impact on the Market Players' Value in New Realities of International Gas Trading
Authors: Talipova Amina
Published: October 2018

Over the past two years, the Federal Antimonopoly Service of the Russian Federation (from now on referred to as FAS) raised the issue of the internal gas market's efficiency, as well as possible scenarios for its partial or complete deregulation. Previously several times settled task has been discussed in the context of the transition to market pricing of wholesale gas volumes and the preservation of state regulation regarding tariffs for the transportation of gas through the Unified Gas Supply System (from now referred to as UGSS). However, to date, the regulation of the domestic gas market, pricing rules and tariffs for transportation have not changed significantly, except for somehow development of the gas exchange trading (SPIMEX), which nevertheless also has some problems and constraints to the development of open market trade.

The main criticism in this issue is the currently applied pricing regime, which consists in the presence on the over-the-counter (OTC) market of monopolistically regulated prices and the so-called open pricing mechanism, and exchange prices on the Saint Petersburg International Mercantile Exchange (SPIMEX) gas exchange, respectively. Experts agree that such a system leads to an asymmetry of the market, and, as a consequence, its inefficiency, unequal position of players in the market, as well as risks of a serious shift of the balance towards one player in case of a significant change in gas market regulation. In this regard, each separate proposal of the FAS on reforming the domestic gas market, whether it relates to the division of the dominant seller into production and transportation or the abolition of price regulation, faces severe contradictions on the each player's side. Thus, the pilot project in three subjects of the Russian Federation (Tyumen Region, Yamal-Nenets, and Khanty-Mansiysk Regions) was discussed to be settled in 2016 on the abolition of the lower boundary of the monopolistic regulated gas price for industrial consumers. The project, however, has not been implemented due to the reason mentioned above for the disagreements of all interested parties.

Such aspects further exacerbate this problem as the share of the gas industry in exports, and, in particular, the export of liquefied natural gas (from now on LNG). The role of LNG in the transformation of global, regional gas markets has been noted over the past decade by the IEA and Russia, as one of the players in this industry, is also setting strengthening rules the positions of Russian gas companies in LNG markets as one of the country's developments priorities.

The paper briefly examines the proposed reforms on the abolition of the gas price lower limit for industrial consumers in the context of the impact on independent gas producers, their market position, market value and credit rating. Also, the work considers the development of exchange trade in natural gas, as an indicator of open pricing and related problems.
Ensemble-Based History Matching and Uncertainty Quantification for Reservoirs Exhibiting Complex Non-Gaussian Characteristics
Authors: Kumar Devesh , Srinivasan Sanjay
Published: October 2018

History matching is an integral part of field development planning for oil and gas reservoirs. It can be viewed as an inverse modeling technique which utilizes information contained in the observed flow response variables like flow rate, well bottom hole pressure etc. to better quantify the spatial distribution of reservoir model parameters like permeability or porosity. As the reservoir parameters and flow response variables are often related by non-linear relationships, the solution to the inverse problem of history matching is often non-unique. This makes it a problem that can be better handled by stochastic approaches than deterministic approaches. The proposed approach called ‘Indicator-based Data Assimilation’ (InDA) is suitable for such problems. To initiate the process, multiple realizations of the reservoir model parameters are generated based on the available information related to the reservoir description. The ensemble of realizations serves as a measure of initial uncertainty in the spatial distribution of model parameters. Next, flow simulations are run on the ensemble of models and the difference between the observed and simulated flow response variables are used to update the reservoir parameters using InDA. With successive updates, the uncertainty in the model parameters is reduced and the spatial distribution approaches the "true" distribution. Considering the residual uncertainty of the final updated models, reliable field development planning decisions can be made. The proposed method is validated using a realistic reservoir with complex channel-like features emulating a reservoir formed in a fluvial depositional environment. Liquid rate data from existing wells are used for updating reservoir parameters for several time steps using InDA. A comparison of the spatial distribution of final model parameters with the reference model used for validation shows a good match. After the history matching period, existing and new infill wells are run in a forecast mode where the observed and simulated flow responses show a good match. As majority of oil reservoirs comprise of high permeability oil-bearing zones in form of channels passing across low permeability zones, the statistical permeability distribution is bimodal making it non-Gaussian. It is shown that ‘Indicator Transformation’ of variables used in InDA preserves the non-Gaussian structure of the permeability field in comparison to methods like ‘Ensemble Kalman Filter’ (EnKF) that are sub-optimal in such cases.
Engineered Fracture Spacing Staging and Perforation Cluster Spacing Optimization for Multistage Fracturing Horizontal Wells
Authors: Salah Mohamed , Ibrahim Mazher
Published: October 2018

Horizontal drilling and multistage hydraulic fracturing applied in tight reservoirs in North America over the past decade and economic productivity attained by creating large fracture surface area to contact the reservoir and create the conductive pathway for the flow of hydrocarbon into the wellbore. Perforation cluster spacing and fracture stagging are keys to successful hydraulic fracturing treatment for horizontal wells. The early focus of the industry was on the operational efficiency. A geometric spacing of perforation clusters adopted as the preferred completion method. Cipolla (2011) presented a case study on the interpretation of production logs from hundreds of horizontal wells. The results indicated that 60% of perforation clusters contribute to production when completed geometrically. Recently, numerous studies have been undertaken to understand this phenomenon. Increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity was an obvious area for improvement to engineering the completion design. An area with a limited number of horizontally multistage fractured appraisal wells in the Western Desert of Egypt is targeted for this study. The developed workflow comprises integration of petrophysical, geomechanical and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and selectively place perforation clusters in "like-rock" thus promoting the chance of initiating all perforation clusters within a stage and ensuring uniform placement and distribution of the induced fractures and that every cluster in each zone is fracture stimulated and can contribute to the well's full potential. The hydraulic fracture attributes from the fracture simulator were exported to the reservoir simulator. The surface production measurement together with the production profile was used to calibrate the reservoir model.

The scope of this study is to present an integrated workflow to identify reservoir properties variation along the lateral section of horizontal to engineer completion design, improve stimulation effectiveness, and improve cluster efficiency. The methodology adopted in this study resulted in optimized fracture design that helped reduce-cost and increased well EUR. Optimal cluster spacing was determined based on long-term production performance. The final calibrated hydraulic fracture and reservoir models were used to optimize the cluster spacing and other completion parameters.
Efficiency Analysis of Massive Fracturing with Linear Gel Pad on the Achimov Formation of the Urengoyskoe Field
Authors: Shturn Dmitriy , Zavyalov Nikolay , Perfilyev Dmitriy , Kamenskiy Leonid , Tyurin Victor , Astafyev Vladimir , Osipov Ilya , Zolnikov Denis
Published: October 2018

The primary objective of large fracturing treatments (from 150 to 300 tons of proppant) in the Urengoyskoe (Urengoy) field is to increase the drained volume of the producing zone of the target reservoir by increasing the fracture length and placing a larger mass of proppant while maintaining similar fracture widths and heights.

The basic goal of fracturing is to increase production from the target reservoir. In this study, to increase the fracture length and propped fracture length in the target zone, linear gel fluid was used for the main fracture pad stage instead of the traditional cross-linked fluid pad. Because of the high filtration rate of linear fluids and their reduced efficiency, pads of larger volumes were used and were pumped at a higher rate. An additional goal of this strategy was to increase the formation coverage. The fracturing treatment proppant stages were pumped using crosslinked fracturing fluid, which helped to reduce the risk of screenout.

Large fracturing treatments using linear fluid pads increase risk because of the high possibility of screening out and because of undetermined economic efficiency. The initial strategy of the Achimov formation development for the given section of the field planned to complete wells using standard large fracturing treatments on S-type wells with crosslinked fracturing fluid throughout all of the main stages. Because of similar geological conditions across the field, the significant number of previous well stimulation operations performed, and the use of extensive logging by the operating company (including bottomhole pressure and temperature online monitoring during fracturing job, and production logging), it was possible to evaluate and compare the economic efficiency of large fracturing treatments using linear fluid pads and large fracturing treatments using crosslinked pads. The comparison of the results from geophysical studies after the fracturing and the subsequent well productivity analysis have been performed.

The described operations enabled fracturing risks and economic efficiency to be understood, both in the Achimov formations of the Urengoy field and in similar gas reservoirs with low permeability. Well productivity after fracturing with a linear pad increased in comparison with offset wells treated with crosslinked fracturing pad fluid.
Utilizing Drill Cuttings to Enhance Characterization and Description of Tight Carbonate Reservoirs
Authors: Salim Ahmed , Lagraba P. Javier Oscar
Published: October 2018

Tight and complex carbonate reservoirs development requires placing horizontal lateral wells to maximize the reservoir contact across the zones with the best flow potential. Identification of the best permeable intervals and understanding their lateral and vertical continuity are key tasks faced during the field development. It is of critical importance to find means to identify all geological and petrophysical facies changes in such complex rocks. These changes could reveal variations in flowing capabilities of the reservoir.

Standard wireline and LWD logs during the appraisal phase do not always provide the necessary information to capture significant facies changes to identify conclusively permeability variations in the reservoir. Fonnation tester logs are expensive and have limitations in tight formations. Incorporating advance analyses of drill cuttings data into petrophysical and geological evaluations significantly improves the capabilities to recognize geological facies variations, even with minor changes in mineral composition, texture and grain sorting. Capturing these variations in the rock are critical to identify permeability and reservoir quality variations.

In this paper, a method to integrate drill cuttings analysis into standard formation evaluation program is presented as an alternative to enhance reservoir characterization and description.
Increasing the Efficiency of Gas Injection for Oil Recovery from Tight Reservoirs
Authors: Betekhtin Andrey , Glavnov Nikolay , Vershinina Maiia , Zobov Pavel , Khlebnikov Vadim
Published: October 2018

The paper describes the results of a series of slim tube experiments to study the miscibility properties of light West Siberian oil and associated petroleum gas (APG). The experimental MMP for the field's APG was found to be 26 MPa. To improve the degree of miscibility and facilitate the oil and gas miscibility, it is recommended to inject a slug of liquefied gas or other light hydrocarbons into a reservoir before injecting APG. To increase the accuracy and reliability of MMP, it is recommended to use the graphical function of gas breakthrough vs. pressure, rather than the usual function of oil displacement ratio (after injecting 1-1.2 pore volumes of APG) vs. pressure.
Study in Efficiency of Acid Compositions Application in the Clastic Reservoirs of Perm Region Based on Experimental Studies of Core Sample
Authors: Plotnikov Vladimir , Rekhachev Pavel , Barkovsky Nikolay , Amirov Aleksey , Mikhaylov Nikolay , Popov Sergey
Published: October 2018

The paper considers results of laboratory experiments on the effect of an acid composition consisting of hydrochloric and hydrofluoric acids on core samples taken from clastic reservoirs in Perm Region. The research included determination of porosity and permeability properties of the samples before and after treatment with the composition, taking anisotropy of rock properties into account. The paper presents the research program and the experimental results obtained that showed a significant change in permeability after filtration of the acid composition and the influence of anisotropy on this parameter. The specific feature of the research carried out is the study of the combined effect of the acid reagent and varying effective stresses on permeability of core samples.
Natural Gamma Ray Tool Response Discrepancies: Not Always Due to the Calibration!
Authors: Allioli Françoise , Nicoletti Luisa , Stoller Christian , Xu Libai
Published: October 2018

It is not uncommon to note discrepancies in natural gamma ray (NGR) data from different designs of gamma ray (GR) tools run in the same well. These discrepancies are often blamed on inaccurate primary or secondary calibrations of the tools; however, it can be shown that in many cases, the different readings are inherent in the NGR measurement itself. Because the primary calibration is performed at the University of Houston (UH) in a reference formation with a specific mixture of thorium, uranium, and potassium, a change in the relative elemental concentrations results in a change of the energy spectrum of the gamma rays that reach the tool’s detector. The tool response to the different energies depends on a large number of factors; e.g., thickness and type of material traversed by the gamma rays, dimensions and type of the GR detector, as well as differences in threshold settings of the acquisition electronics. The standard environmental corrections for NGR tools correct for borehole effects (mud weight and composition, borehole size, and tool position in the borehole), so that the tool response to a given formation is independent of the borehole environment.

In this paper, we present a detailed Monte-Carlo modeling study quantifying the impact of the tool and detector design on the sensitivity to the three predominant naturally occurring radioactive materials (Th, U, and K). Also, the modeling study includes the impact the thickness and type of the materials have that is traversed by the gamma rays before reaching the detector. The modeling is benchmarked against the measured response in formations with a known Th, U, and K concentration, such as the UH Th and U pits, or internal calibration facilities.

The modeling results show that there can be significant discrepancies in the response of different tools to the same formation if the relative Th, U, and K concentrations deviate considerably from those in the UH reference pit. This condition will be illustrated by field cases with comparisons of the total NGR measurement and the spectral NGR measurement, which show that tool-to-tool differences can be attributed to a change of the composite energy spectrum of the emitters from the formation.

Finally, it can be shown that the tool calibration, as well as the interpretation of tool discrepancies, can be improved by using not only a 200-gAPI reference but also an independent Th, U, and K calibration associated with specific response functions for each tool design.
Wastewater Injection and Slip Triggering: Results from a 3d Coupled Reservoir/Rate-and-State Model
Authors: Babazadeh Mohsen , Olson Jon
Published: October 2018

This paper present results from a combined model that brings together injection physics, reservoir dynamics, and fault physics to better explain the primary controls on induced seismicity. We created a 3D fluid flow simulator with embedded discrete fracture technique, coupled with a 3D displacement discontinuity geomechanics model that uses rate and state friction to model stable or unstable rupture events. The model incorporates reservoir properties including vertical and horizontal extent; stratification including top-seal, reservoir, and basement; multiple permeability and porosity. Injection parameters include rate and pressure. Fault properties include size, 2D permeability, and frictional properties. Several suites of simulations were run to evaluate the relative importance of each of the factors from all three parameter groups.

We find that the injection parameters interact with the reservoir parameters in the context of the fault physics. For a given reservoir and fault properties, injection rate increases magnitude and frequency of earthquakes, and volume is unimportant. For a different reservoir, these relations may change, leading to the need to specify/examine the injection parameters only within the context of a particular faulted reservoir. Both injection and reservoir properties can interact with the fault properties to trigger or impede slip, so that the magnitudes of induced earthquakes depend on all three groups of parameters. For example, the fault permeability structure is a key factor in inducing earthquakes in basement in many reservoir scenarios. In some cases, the main component in inducing seismicity include the pressure on the fault and its rate of change, which affect how big of a fault area is being affected, and therefore initial earthquake size. By implication, selecting reservoirs for wastewater disposal may involve prioritizing those reservoirs with higher permeability as it takes longer for fluid pressure to exceed critical pressure and trigger large unstable rupture events on nearby faults.
Analysis of Horizontal Well Fracture Interactions, and Completion Steps for Reducing the Resulting Production Interference
Authors: Daneshy Ali
Published: October 2018

An oft-occurring outcome of modern fractured horizontal well production systems is considerable interactions between adjacent hydraulic fractures; in the same well (intra-well), or in offset wells (inter-well). An unwanted consequence of these interactions is production interference. Inter-well interactions can cause production re-routing from one well into the adjacent well, and occasionally even short-term loss of production from one of the wells. Effects of intra-well fracture interactions may include production re-distribution within the created fractures, and, patchy depletion of the reservoir surrounding the horizontal well.

Causes of intra-well interactions include stress shadowing and Dynamic Active Fracture Interactions (DAFI). Under common fracturing practices these can cause unpredictable deviations in fracture growth path which can even lead to coalescence of some fractures and non-uniform production from individual fractures. Another important outcome of these interactions is differences in created fracture lengths, with some fractures extending a long distance into the reservoir. Recent trends towards larger size treatments and shorter spacing between individual fractures are intensifying these effects.

Inter-well interactions include frac-to-frac connections that hydraulically link the two wells together; either temporary (while fracturing only), or long term with conductive links. The latter can cause immediate production interference. Another less severe type of interaction is fracture shadowing, which may cause delayed production interference.

Paper discusses how these interactions are influenced by the stress environment, formation mechanical properties, type of completion (openhole liner, cemented liner, single fractures vs. multiple fractures), fracture orientation and spacing, well spacing, and perforation schemes. It presents completion steps that reduce the uncertainty in fracture growth path and location of longer fractures. It also shows how and why combining these steps with simultaneous and zipper fracturing can reduce damage to the wellbores and the extent of production interference.

On the positive side, analysis of fracture interactions can also provide valuable information about fracture characteristics; including estimates of length, orientation and conductivity, etc. With proper preparation, the information can also be used for real-time evaluation of the created fractures and treatment modifications to reduce severity of production interference.
Managing the Drilling Function
Authors: Willis John , Jackson Richard , Swartz Harris
Published: October 2018

An international company with multiple drilling groups in separate business units on three continents created a global drilling function that increased organizational capabilities and minimized overhead costs. The organization has encompassed up to 13 separate drilling groups and a headquarters staff organization. The new structure, primarily involving land operations, has demonstrated success for more than 5 years.

The processes and systems described herein have some special design feature for drilling, or are unique among the functional organizations of the company. These include identification of important areas, the role of the headquarters group, drilling group structure, systems, and systems components. The processes used in the drilling function that are common to all large organizations are not covered.

Several important conclusions have been demonstrated. Standards and guidelines must provide balance between risk management, innovation, and allowance for unusual situations. Consistency of positions, responsibilities, and processes across all business units enables efficient, standardized global processes. An organized system to create communication between business units can stimulate exchange of ideas, experiences, and technology that otherwise would not be communicated, not for lack of desire, but simply due to the demands of the day-to-day business.

Technically complex systems managed globally justify greater investment and support, and deliver superior results to specialized local systems. Non-complex systems that require low-level customization for separate units may be more effective and economical when managed locally. Management of staff movements and career development across business units provides more consistent opportunities and global optimization of staff capabilities.

Given the number of large oil companies, it is safe to presume that many approaches to managing the drilling and other functions have been used. However, few approaches are published. This paper presents a comprehensive overview that can aid in the development or refinement of functional organizations.
Well Log Analysis for Reservoir Characterization of Famenian Carbonates with Criterion of Texture Heterogeneity
Authors: Minigalieva Gulnaz , Nigmatzyanova Albina , Burikova Tatyana , Privalova Olga , Akhmetzyanov Ruslan , Kinzikeeva Aigul
Published: October 2018

Most carbonate rocks are characterized by high heterogeneity which implies changes in their vertical and lateral distribution, geometry and properties based on special aspects of their generation, depositional history, evolution and influence of exogenic processes.

The oil-bearing carbonates of the Famenian in the study area tend to occur as complex reservoirs characterized by heterogeneous storage and flow potential. Diagenetic secondary changes resulted in various types of rocks differentiated by the configuration of the void space. The most extensive secondary changes evident to a greater or lesser degree in all the cored sections of the analyzed wells were caused by leaching which in its turn modified the carbonate fabrics and created heterogeneity. The configuration of the void space formed the foundation for the differentiation of petrophysical rock types.

The findings obtained from the detailed lithological and petrophysical description of the Famenian rocks were used to group the identified reservoirs into the following classes based on the prevailing configuration of the void space, i.e. porous, vuggy-porous and fractured-vuggy-porous[1]. While the porosity values are comparable, the fractured-vuggy-porous type has the highest flow potential (maximum permeability values of the three types) due to leaching whereas the vuggy-porous type is characterized by average permeability and the porous one has the lowest flow potential (Figure 1). The type of the void space also predetermines the shape of the capillary pressure curve and respectively the pore throat radius distribution (Figures 2 and 3) as well as electrical and acoustic properties of the rocks.
Methane Flow in Shale Nanopores with Kerogen Microstructure by Molecular Simulations
Authors: Wu Tianhao , Firoozabadi Abbas
Published: October 2018

We perform a systematic molecular investigation of construction of the kerogen matrix and simulation of gas flow. The kerogen matrix is constructed by 60 Type-II kerogen macromolecules. The pore space is generated by means of dummy atoms. The porosity, surface area, and transport diffusivity are analyzed. In the past, the simulations of methane flow have been performed assuming rigid molecules in the kerogen matrix. We extend the simulations from rigid molecules to flexible molecules in the kerogen matrix. The gas flow simulation is performed based on the boundary-driven method. The results show that the relaxation of the generated kerogen matrix after the deletion of dummy atoms should be part of the process. Without the relaxation, the pore volume will be overestimated significantly. The transport diffusivity in flexible kerogen matrix is generally higher than in rigid kerogen matrix. The flux is mainly contributed by the adsorbed methane molecules. There is additional flux through the occasionally opened pores in the flexible kerogen matrix.
Evolution of Well Logging Technologies in the Development of Deposits on the Caspian Shelf
Authors: Shtun Sergey , Golenkin Mikhail , Rakitin Mikhail , Shtepin Daniil , Mityagin Artem , Cheprasov Alexey , Golubtsov Ruslan , Kuzakov Vittaly
Published: October 2018

It is difficult to imagine modern exploitation of deposits without drilling horizontal wells. The choice of the direction of drilling of horizontal trunks depends on the study of the deposit, which is based on seismic and exploration data. The drilling conditions onshore is somewhat easier than in the sea, as there are a sufficient number of vertical and horizontal wells on the ground that carry enough information to select the optimal direction of the horizontal production well. There is a completely different situation with drilling offshore production wells. As a rule, there are not enough vertical exploratory wells in the fields located at sea, which make it difficult to develop and operate offshore deposits.

Complex drilling conditions require a deeper and more comprehensive technological approach to the well planning process. Modern technological solutions allow solving a wide range of tasks for obtaining geological information about the field, reducing risks, and, as a result, reducing the time of drilling and completion of wells. In this paper, we describe the range of geological and technological problems that were solved due to the introduction of new technologies for well logging.
Approaches for Petrophysical Modelling and Logging Interpretation of Thin Laminated Achimov Deposits Reservoir
Authors: Fattakhov Emil , Timirgalin Azamat , Zhukov Vladislav , Oshmarin Roman , Mukminov Iskander , Kondratiev Artem
Published: October 2018

Resume

Currently, due to the depletion of terrigenous oilfields with thick reservoirs, more oilfields with worse formation properties are being involved into production. One of the example of such implementation is Achimov layer, which is shaly-sand deposits of deepwater genesis, associated with the fondoform part of clino-cycle on the Neocomian age. Difficult geology aspects, high degree on unexploration contributes to the presence of various problems in the development of these sediments. Some problems also has historical background: in the past Achimov deposits were the transition interval for more deep-located Jurassic deposits which leads to low representativity of core data and narrow complex of logging tools.

Achimov sediments represented by complex anisotropic reservoirs and usually have thin laminations of siltstones and sandstones. Vertical resolution of these laminations could vary from the first centimeters to the first dozen centimeters. Identification of perspective intervals and reliable estimation of their formation properties by the logging is assosiated with a number of difficulties, main of which is insufficient vertical resolution of tools. Althought there are a lot if articles written about laminated sediments, most of them offer solution in up-to-date logging methods and modern logging tools interpretation. Our aim is to extract the maximum amount of information using an existing data set.

Thus, we are faced with the task of finding an approach to petrophysical modeling and interpretation of highly laminated reservoirs depending on the completeness of the input data set.
Well Performance Modeling in Unconventional Oil and Gas Wells
Authors: Oyewole Adeoluwa , Kelkar Mohan , Pereyra Eduardo , Sarica Cem
Published: October 2018

The challenge facing reservoir and production engineers remains ensuring continued production from a well, including additional recovery with artificial lift methods. To accomplish this, means to determine the production performance of a well until the end of its life is desired. This challenge is even greater when dealing with production from unconventional formations. This paper presents a methodology to model the production performance of a well producing from an unconventional oil or gas formation.

Emphasis is placed on the use of readily-available information to production engineers for the day-to-day analysis and optimization of production from the field. For developing the model, traditional flow regimes observed during the production of a well are utilized. Using this information as well as superposition principle, a working model is developed, tested and validated.

Technical contributions of this paper include a procedure to implement this solution in any producing oil or gas well from an unconventional formation, and an Inflow Performance Relationship (IPR) framework for visualizing productivity changes with time of a particular well.
Complex Approach to Fault Description While Geosteering for Maximization Reservoir Contact in Horizontal Wells in West Siberia Oilfields
Authors: Krutko Vladislav Vadimovich , Yurkina Tatyana Alexandrovna , Kushnir Dmitriy Yurievich , Karpov Valery Borisovich
Published: October 2018

The paper presents an interdisciplinary approach to the tectonic dislocations description based on the results of interpretation of seismic data, petrophysical analysis of well-logging data in horizontal wells and the results of inversion of the multifrequency propagation tool. On the materials of seismic surveys and logging-while-drilling data in horizontal wells of one of the oil fields in Western Siberia a cinsistent approach to fault identification and description is presented.

Interpretation of seismic data allows predicting the fault presence along the horizontal well profile and gives preliminary estimation of the dipping and amplitude parameters of the fault surface. Utilizing the the logging-while-drilling data of a group of horizontal wells with the aim to improvement the geological model after fault crossing an approach including machine learning principles is proposed and tested. Application of inversion of the multifrequency propagation tool to one of the updated geological model with faults allowed to improve the estimations of the fault zone parameters.
Industry and University Collaboration Progresses the Concept of a Citizen Engineer
Authors: Battalora Linda A. , Brewer Linda Y. , Chen Jiaheng
Published: October 2018

The Society of Petroleum Engineers Sustainability Task Force (SPE-STF) was created in 2014 and immediately developed Sustainability content including a strategy, curriculum, and course offerings. The opportunity for a collaboration between SPE-STF and Colorado School of Mines Petroleum Engineering (CSM-PE) graduate students was quickly identified with beneficial outcomes for both parties.

Over a three-year period and with SPE-STF guidance, graduate students analyzed a variety of resource plays in global geographic locations and ultimately, the role of the Citizen Engineer in sustainable development. During this timeframe, students worked in multinational teams and researched probable technical and non-technical issues, potential interactions between those issues, and the options for managing those issues. SPE-STF provided feedback to students based on industry experience. SPE-STF and other industry representatives engaged with students in the classroom on topics of health, safety, security, environment and social responsibility (HSSE-SR), sustainability, stakeholder engagement, and risk identification.

In technical memoranda, final reports, and presentations, CSM-PE graduate students defined the role of the Citizen Engineer, provided integrated case study analysis including technical and non-technical risk assessments, recommendations for sustainable development, and the feasibility of the financial business case.

This academic and industry collaboration informed the SPE's growing sustainability conversation on integrating sustainable development into operational business plans and provided opportunity for improved sustainability competency and skill development for employees and students.
Low Tension Foam Flooding for Chemical Enhanced Oil Recovery in Heterogeneous Systems
Authors: Hahn Ruth , Spilker Kerry , Alexis Dennis , Linnemeyer Harry , Malik Taimur , Dwarakanath Varadarajan
Published: October 2018

Current chemical EOR technologies, such as surfactant polymer flooding, have limitations, such as, high temperature, high salinity, and/or low permeability reservoirs. Low tension foam flooding, however, can be performed at high or low temperatures, salinities, and permeabilities. Low tension foam reduces residual oil saturation and increases sweep efficiency. The current literature shows the effect of foam in corefloods and limited 2-D micro-model experiments. We investigate the ability of low-tension foams to successfully divert flow into lower permeability zones in both communicating and non-communicating heterogeneous systems.

During this laboratory study, a surfactant that has shown success for foam applications in the field was evaluated and used as a baseline to compare and evaluate low tension foam formulations. We measured resistance factors under constant pressure and constant flow conditions. In addition, we established benchmarks for flow diversion. The low-tension formulations were modified to display foaming abilities and compared against the baseline surfactant benchmarks. Phase behavior experiments were conducted to determine the oil solubilization ratio of each surfactant formulation. Foam floods with surfactant formulations with favorable solubilization ratios were conducted in heterogeneous systems to determine sweep efficiency and oil recovery.

Surfactant formulations were developed that showed favorable apparent viscosities during in situ foam floods and improved sweep efficiency in a dual-permeability communicating system comparable to the baseline foam. During oil recovery experiments in a heterogeneous system, the baseline surfactant recovered approximately 40% of the remaining oil while the low-tension formulation recovered over 70% of the remaining oil. This study indicates that we can use low tension foams to successfully divert flow from high permeability zones to low permeability zones in heterogeneous sand packs and recover oil at the same time.