bluuebunny/crossref_metadata_2025_split huggingface dataset:
To Modeling of Dual-Porosity Reservoirs
Authors: Lugumanov Timur 
Published: October 2018

Abstract
Simulation of naturally fractured reservoirs is a challenging task. First of all, due to complexity of the geological structure and the structure of the pore space. Anisotropy of fluid flows and difficulty in assessing the recoverable reserves are results of the complex structure.
Naturally fractured reservoirs can be classified into five types according to capacitive and conductive properties of fracture network and porous matrix blocks. Reservoirs, in which capacitive and conductive properties predominate in the fractured medium.Reservoirs, in which the capacitive properties predominate in the matrix medium, and the conductive properties predominate in the fractured medium.Reservoirs, in which the capacitive properties predominate in the matrix medium, and the conductive properties are strong enough in both the fractured and matrix medium.Reservoirs, in which the capacitive properties predominate in the matrix medium, but at the same time the pore volume of the fractured medium also has a significant influence on the reserves, usually due to the cavernous nature of the fractured medium. The conducting properties in such reservoirs are strong enough in both the fractured and matrix medium.Reservoirs, in which only the matrix medium has the capacitive and conductive properties, and fractures act as barriers.
The first two types of reservoirs are modeled by dual-porosity model. The third and fourth types are modeled by dual-permeability model. And the fifth type can be represented by the single-porosity model with features, description of which is beyond the scope of this article.
In this paper, on the basis of literature review and personal experience description of dual-porosity/ dual-permeability models are given. The filtration equations of dual-porosity / dual-permeability model and the description of the mechanisms of flow between the pore medium and the fractured medium are presented.
The sensitivity analysis was carried out. It demonstrated that the effective permeability of the fractured medium depends on the absolute permeability of the pore medium in numerical simulation.
Methanol Delivery Recycle Systems Development at Complex Gas Treatment Unit of Achimov Deposits of Urengoyskoe Oil and Gas-Condensate Field
Authors: Koryakin Alexander , Ermolaev Aleksander , Kagarmanov Aidar 
Published: October 2018

Abstract
When developing hydrocarbon deposits, an important task is the development and implementation of energy- and resource-saving technologies. Prospects for the development of Gazprom dobycha Urengoy are associated with the commissioning of deposits of the Achimov stratum. For the preparation of gas from these deposits, the design solutions include the use of low-temperature separation units with a recirculation scheme for the use of methanol.
The article describes the development and implementation of technical solutions on improvement of recirculation schemes of the use of methanol in the Achimov gas fields. The design solutions on optimization of methanol consumption at the gas treatment plant of the area 2A of the Urengoy field were not fully realized because of the hydrate deposition when feeding liquid from the intermediate separation stage to the low-temperature stage. The analysis of methanol distribution between the outgoing streams of the complex gas treatment plant showed that the main methanol losses occur with unstable condensate.
Specialists of Gazprom dobycha Urengoy LLC developed two technical solutions aimed at reducing methanol consumption. The first solution involves feeding the liquid phase from the intermediate separation stage to the low-temperature stage by means of an ejector. The second solution is based on the aqueous extraction of the reagent from the condensate with a mixture of formation water and the aqueous phase after methanol utilization in the stripping column. The implementation of these technical solutions makes it possible to reduce methanol consumption in gas treatment plants by about twice. A list of activities on improving the recirculation technology of the use of methanol in Achimov gas treatment plants has been determined. The first technical solution has already been implemented in the gas treatment plant of the area 2A and has proved its effectiveness
Digital Integrated Modeling for Waterflooding Management
Authors: Povyshev Konstantin , Valiev Rinat , Rechkin Mikhail 
Published: October 2018

Abstract
Gazprom Neft has set an ambitious strategic goal: reach up a production plateau at 100 million TOE per year. To achieve this goal, the company will need to increase the resource base, develop and commission new fields, and work with the basic production at the existing assets.
As of today, 95% of the company's fields are produced with a reservoir pressure maintenance (RPM) system. The reservoir pressure maintenance system is the key to ensuring sustainable production of an oil field. Condition and operation of this system have immediate effect on the reservoir behavior, displacement parameters, and, therefore, oil production profile. However, almost all of Gazprom Neft's subsidiaries are facing the problem of analyzing and interpreting field performance data because the process is too long and complex while its results are not obvious and unambiguous. For this reason, it may not always be clear in what part of the system there is a problem: the reservoir, the well or the infrastructure.
Let us turn to the widely known formula used to determine the oil recovery factor (ORF) (1): (1)ORF =KsweepxKdispl.
where Ksweep is the sweep efficiency (factor), and
Kdispl. is the displacement efficiency (factor).
Ksweep is the ratio of the volume of the reservoir being drained by the wells to the total volume of the reservoir. The sweep efficiency characterizes the effect of reservoir discontinuity (alternation of permeable and impermeable bodies) on the filtration parameters, i.e. how the drained volume of the reservoir is reduced compared to the case when the reservoir does not contain any impermeable bodies in it.
The main task when developing the reservoir then is to ensure full involvement of its entire volume in the process of drainage. But with a high degree of heterogeneity or a significant difference in mobility of oil and the displacing agent, flooding efficiency decreases which is expressed in lower sweep efficiency too. The main reason for that is the uneven propagation of the injected water front over the area and cross-section of the reservoir.
Kdispl. is the ratio of the volume of oil displaced by water from a reservoir rock sample or reservoir model till 100% water cut to the initial volume of oil contained in the rock sample or reservoir model.
Redefining Bakken Completions – A Tailored Approach to Stimulation
Authors: Trainor Kyle , Vincent Mike , Finch Ron 
Published: October 2018

Abstract
The economic boundaries of the Williston Basin are being expanded with improved practices. This paper discusses advances in reservoir characterization coupled with the implementation of refined stimulation techniques that have achieved strongly compelling results in an area of the Williston Basin that was previously perceived to be marginally economic.
After more than a decade of intense development, the remaining undrilled acreage in the core of the Bakken has been drastically reduced. Consequently, there is strong motivation to identify additional economically viable drilling locations. Hydraulic fracturing treatments incorporating increased volumes of fluid and proppant in more closely spaced clusters have successfully increased well productivity in many resource plays across the industry. The contemporary slickwater and slickwater hybrid designs implemented in the Bakken have spurred a renaissance of continued development throughout the basin. While these increasingly large frac treatments improve well productivity, in some parts of the basin the high treatment expenses and resulting elevated watercuts challenge the economic viability of development.
Rote application of the "bigger is better" completion strategies developed for the core of the basin has been unsuccessful in some portions of the Bakken. This paper describes the unique geologic characteristics of the study area and the stimulation strategy that has been adapted to accommodate the geologic differences while achieving excellent economic results. Implementation of completion designs tailored to the area has yielded a 300 to 400% production increase compared to offset wells. This "right sized" completion strategy customized for the area achieved highly productive wells with substantially lower capital costs than were budgeted based on strategies currently popular in the core of the Bakken. Although treatment designs continue to evolve and additional improvements are anticipated, the summary of experimentation and learnings from seven sequential wells may be helpful to others pursuing assets considered "marginal".
A Fast-Paced Workflow for Well Spacing and Completions Design Optimization in Unconventional Reservoirs
Authors: Belyadi Hoss , Smith Malcolm 
Published: October 2018

Abstract
Well spacing optimization is one of the most important considerations in unconventional field development. The Appalachian basin development has been increasingly prevalent in the last decade due to substantial production performance from Marcellus, Upper Devonian, and Utica/Point Pleasant Shale plays. The majority of operators have been in a manufacturing mode, where a standard well spacing and completions design have been applied to a field with less emphasis on optimizing the net asset value of the field. NAV can be improved through modeling and various optimization workflows such as numerical simulation, machine learning, and linear programming. The essence of field development and optimization is to use completions design, as well as well spacing, to optimize the net present value of the field based on current commodity pricing, capital expenditure, operating cost, cycle time, and net revenue interest. A substantial change in any of these essential factors must be studied to make sure the appropriate changes are accounted for in the field development and optimization.
Determining the optimum well spacing that coincides with the completion design can often be challenging and time consuming due to complexity of some governing factors such as geology, engineering, and economic analysis. For instance, if optimum well spacing and completions design were developed in a geologically noisy and complex reservoir, the outcome may no longer be valid in a discreet and quiet area. In addition, if well spacing and completions design were developed for a high commodity pricing environment, performing the same workflow and evaluation at a lower commodity pricing would yield an increase in well spacing. The dynamic nature of the oil and gas industry, specifically these essential factors, could cause complications with selecting the optimum well spacing and completion design to maximize the shareholder's value. Therefore, a fast-paced and dynamic workflow has been developed, that can be applied in different shale reservoirs, to maximize the present value of these assets. This paper will walk through the step-by-step process that can be applied to any unconventional shale play to optimize the field considering geology, engineering, and economic analysis.
The objective of this paper is to go through a fast-paced optimization workflow, starting with a fracture model, coupled with a production model using numerical simulation to obtain a calibrated model, and finally performing detailed economic and sensitivity analysis to obtain the optimum well spacing and completions design, which would yield the highest net present value of the field.
Characterization of Fracture-Driven Interference and the Application of Machine Learning to Improve Operational Efficiency
Authors: Klenner Rob , Liu Guoxiang , Stephenson Hayley , Murrell Glen , Iyer Naresh , Virani Nurali , Charuvaka Anveshi 
Published: October 2018

Abstract
Frac hits are a form of fracture-driven interference (FDI) that occur when newly drilled wells communicate with existing wells during completion, and which may negatively or positively affect production. An analytics and machine-learning approach is presented to characterize and aid understanding of the root causes of frac hits. The approach was applied to a field data set and indicated that frac hits can be quantitatively attributed to operational or subsurface parameters such as spacing or depletion. The novel approach analyzed a 10-well pad comprising two ‘parent’ producers and eight ‘child’ infills. The analysis included the following data types: microseismic, completion, surface and bottomhole pressure, tracers, production, and petrophysical logs. The method followed a three-step process: 1) use analytics to assess interference during the hydraulic fracturing and during production, 2) catalogue or extract feature engineering attributes for each stage (offset distance, petrophysics, completion, and depletion) and 3) apply machine-learning techniques to identify which attributes (operations or subsurface) are significant in the causation and/or enhancement of inter-well communication. Information fusion with multi-modal data was also used to determine the probability of well-to-well communication. The data fusion technique integrated multiple sensor data to obtain a lower detection error probability and a higher reliability by using data from multiple sources. The results showed that the infill wells completed in closest proximity to the depleted parents exhibit strong communication. The machine-learning classification creates rules that enable better understanding of control variables to improve operational efficiency. Furthermore, the methodology lends a framework that enables the development of visualization, continuous learning, and real-time application to mitigate communication during completions.
Thru-Tubing Workover Motor Load Measurements and Analysis
Authors: Landry Miles , McEntire Caleb Mac 
Published: October 2018

Abstract
By some industry estimates over 80% of hydraulically fractured land wells in North America employ the plug-and-perf method for zonal isolation. The dominant method for composite frack plug removal is through the deployment of a tubing conveyed hydraulically powered motor, or workover motor (WOM), to mechanically drill through plugs and remove the debris from the wellbore. Over 90% of Thru-Tubing Intervention (TTI) service companies provide to its customers is the application of WOMs to remove composite frack plugs. The effects of a mechanical failure in one of these motors during drillout operations is costly to both the customer and the respective service company. In many cases, a mechanical failure can cost several days of non-productive time (NPT) and more than double the financial burden of a drillout operation for both parties. A need was identified to validate traditional industry assumptions and refine drillout procedures by measuring and analyzing loads experienced by WOMs during live operations.
The purpose of this project is to measure and analyze the actual forces experienced by a WOM downhole during a live coil tubing conveyed drillout operation in order to experimentally prove or disprove industry tribal knowledge regarding the effects of traditional drilling parameters and procedures on downhole equipment and operational efficiency. The project involves the use of a data logging sub capable of measuring these forces in the bottom-hole-assembly (BHA). By examining the collected data; patterns and trends will be identified which give insight the most efficient procedures and drilling parameters as well as validate whether equipment is being utilized within operational limits under traditional assumptions. Additionally, the collected data could be used to identify additional opportunities to further improve the design, manufacturing, maintenance and operation of WOMs to meet the evolving challenges of drillout operations involving increased lateral lengths and stage counts.
These improvements to plug drilling procedures will reduce risk, operational time, and cost at the well site as well as internal cost associated with repairing and investigating potential mechanical failures that arise from operating WOMs beyond their limits. Future operations that include the measurement of downhole forces will enable even greater advancements in product reliability across the TTI product portfolio to further reduce the risk of additional time and financial costs to service companies and their customers.
Analysis of Various High Viscosity Friction Reducers and Brine Ranges Effectiveness on Proppant Transport
Authors: Aften Carl 
Published: October 2018

Abstract
Friction reducers (FRs) are used to decrease the amount of horsepower required to move a hydraulic fracturing fluid through a formation at a fixed flow rate. Though FR viscosity is not a crucial consideration in proppant transport when used before the perforations in slick water applications, FR viscosity becomes a greater consideration in proppant transport from the perforations into the formation and an important qualifying criterion with the advent of High Viscosity Friction Reducer (HVFR) systems that require higher loadings than traditional FRs. Consistent viscosity measurement can vary greatly depending upon a number of factors, for example temperature, hydration approach, polymer concentration, brine composition, and additive interaction. A study was developed and implemented to determine the influence of HVFR by concentrated particulate and bead settling.
This study investigated the viscosities of five HVFRs applying eight variables using response surface methodology. Initial study criteria were establishing consistent hydration with unique apparatus design and viscosity measurement verification. Once established, this method examined the effects of 1:1, 2:1, and 2:2 salts, singularly or in various concentrations and combinations. Experimental designs under fresh water conditions were also conducted with varied HVFR loadings (1.0 to 6.0gpt), blender RPM (600 to 12,000), and blender mixing times (0.5 to 8.7 minutes). Viscosities were measured from 200 to 6000 (1/sec). Static settlement testing in ranges of 0.87 to 3.50 pounds per gallon in 0 to 140,000 total dissolved solids (TDS) brines was conducted. Single bead settling measurements were performed in fresh water and API brine.
Specific HVFR and salt matrix combinations tested resulted in highly correlated response surfaces exhibiting consistent trends. The TDS and hardness had a minor to major influence on viscosity based upon the specific HVFR examined. Brines were predominately antagonistic with respect to viscosity with few synergistic results. The influences of HVFR dosage and mixing correlated highly to the viscosity of all HVFRs, and extended mixing time durations had no influence on some HVFR combinations indicating a viscosity reduction limit. In certain regions of the design space, settling rates were related to viscosity.
Selection of an HVFR system precisely tailored for a specific brine composition guaranteeing maximum friction reduction and proppant transportation performance was vital. The influence of pumping and tubular transport on the HVFR viscosity is continuous and quantifiable. Additionally, the viscosity of the HVFR in a downhole brine environment provides discernable data for assessing far end well bore proppant transport and damage potential. This study established a reliable method for gauging performance and examining measurable field variables of HVFR systems.
A Fast EDFM Method for Production Simulation of Complex Fractures in Naturally Fractured Reservoirs
Authors: Xu Feng , Yu Wei , Li Xiangling , Miao Jijun , Zhao Guoliang , Sepehrnoori Kamy , Li Xianbin , Jin Jianli , Wen Guangyao 
Published: October 2018

Abstract
Natural fractures are the main producibility factor in the weathered granite reservoirs (basement rock) and volcanic-rock reservoirs. Production practices show that these reservoirs could have high production rate, but the difference of well productivity between single wells is obvious. These reservoirs have complex natural fractures oriented at medium-high angles, which could bring high complexity and heterogeneity to the reservoirs, adding anisotropy to reservoir permeability. It is very hard to effectively simulate complex fractures in naturally fractured reservoirs and study the applicability of different well type and well pattern by using common reservoir simulators. A fast EDFM (Embedded Discrete Fracture Model) method was put forward for production simulation of complex fractures in naturally fractured reservoirs. The EDFM processor combining commercial reservoir simulators (ECLIPSE or CMG) is fully integrated to forecast production performance of the weathered granite reservoir. With a new set of EDFM formulations, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. So complex dynamic behaviors of natural fractures can be captured, which can maintain the accuracy of DFMs (discrete fracture models) and keep the efficiency offered by structured gridding. In this paper, a 3D model with complex natural fractures was built to model the performance of different well types and well patterns. The results show that wells with higher density of natural fractures produce higher oil production, and horizontal wells with higher density of natural fractures have larger oil production than vertical wells because horizontal wells have a larger contact area than vertical wells. What’s more, heterogeneity and anisotropy have a great effect on well pattern and well type, which need to be studied carefully in the oilfield development.