bluuebunny/crossref_metadata_2025_split huggingface dataset:
After Closure Analysis as an Appraisal Approach
Authors: Usmanova A. , Smith P. , Rylance M. 
Published: October 2016

Abstract
Conventional appraisal consists of drilling, completing and producing a number of wells, with each of these wells being required to establish a production history and sufficient offtake to demonstrate a substantial connected volume. The technique of After Closure Analysis (ACA) offers a complementary or alternative approach to conventional testing, to establish important formation characteristics such as transmissibility (kh//), pore pressure and connected volumes. The principal advantage being that the approach is substantially less time consuming and costly than conventional approaches, particularly in the case of tight formations where substantial enhancement/stimulation may be required in order to establish any sustainable production in the first place.
ACA consists of injecting a fixed volume of fluid above fracturing pressure and at relatively low rates, and then subsequently monitoring the pressure decline response. This approach potentially allows for the calculation of a highly accurate assessment of the transmissibility and combined with formation fluid data the effective kh to this formation fluid. While this technique has been utilised for some time, the application of ACA has been fairly limited in established fields as a reasonably accurate reservoir pressure is required for a meaningful result and therefore depleted environments can present issues. However, in the case of Exploration and Appraisal, formation pressure is typically undisturbed and therefore this approach is well suited and in fact ideal in this case.
The paper will present a series of case histories in a variety of hydrocarbon bearing environments and work the details from the initial concept through demonstration of the results. Additionally, a suite of complimentary pressure transient analyses using conventional approaches will demonstrate the validity of the results. The case histories will clearly demonstrate the relative value that can be achieved by this technique, with direct comparison to conventional approaches. The value of the approach in tighter rock environments will be directly demonstrated. Additionally, a suite of type-curves and selection graphs will be presented that can be used to determine pumping-stage design and decline period requirements. Finally, a suite of lessons learned and operational considerations will be provided in order to maximise the overall efficiency of the approach.
Conventional appraisal approaches require extensive flow-periods and substantial fluid offtake to determine the immediate region of influence/connectivity. The use of ACA offers a supportive and complimentary technique that in combination with a reduced set of conventional test wells offers to augment the datasets available for interpretation at just a fraction of the cost/time of conventional methods. In remote and hard-to-recover areas where such conventional tests can prove inefficient, this technique offers an alternative and complementary means of appraising formations.
Multiphase Inflow Quantification for Horizontal Wells Based on High-Sensitivity Spectral Noise Logging and Temperature Modelling
Authors: Ipatov A. I. , Nemirovitch G. M. , Nikolaev M. N. , Shigapov I. N. , Aslanyan A. M. , Aslanyan I. Y. , Petrova I. A. 
Published: October 2016

Abstract
A pilot project comprising several closely-spaced wells from one pad was carried out in the green East Messoyakha field for further study of properties in this field. The target zone in this field is the oil rim of a highly stratified reservoir containing a gas cap and an aquifer. The field is developed with a system of horizontal wells with horizontal sections up to 1000 m long. Development of such reservoirs always calls for monitoring inflow zones and inflowing fluid composition for timely prevention of gas and water ingress into the wellbore resulting from coning or lateral breakthroughs through the highly permeable zones and for assessment of the reservoir depletion. Horizontal wells in this field are completed with uncemented liners and packers, which makes the task of reservoir flow analysis even more complicated due to the complexity of flow geometry behind the liner.
Accordingly, logging techniques that have a sufficiently deep radius of investigation to be able to collect the required information about the reservoir, such as spectral noise logging (SNL) and high-precision temperature logging (HPT) were used for profiling inflows from the reservoir into the horizontal wellbore section. The SNL tool captures noise signals produced by reservoir fluid flows and has a radius of investigation up to several metres. Such noise signals have a distinctive frequency signature and can be therefore extracted from the entire noise spectrum recorded in the well. Identification of flowing zones using SNL technique is based on this principle. To quantify inflows from the formation, a temperature log analysis is performed using TermoSimTM software system that can simulate thermal processes in the wellbore, surrounding rocks and flow units, and estimate inflow rates by solving the inverse problem. As the survey was conducted in closely-spaced wells, numerical simulations were run with the same subset of input parameters (such as initial temperature distribution etc), which greatly improved the inflow profile reliability.
As a result of the derived inflow profiles analysis, the sources of water encroachment and high gas content in oil during well operation were identified. The inflow profile correlation analysis applied to a group of closely-spaced wells helped to understand the general principles of reservoir-to-wellbore flow geometry in specific geological environment. Data interpretation results were used for planning well interventions with the purpose of improving the performance of production well. The resulting inflow profiles might be incorporated into the field hydrodynamic model to enhance its predictive ability.
Intelligent Control System for Gas-Condensate Field: A Holistic Automated Smart Workflow Approach
Authors: Fomin Vitaliy , Kushmanov Pavel , Purwar Suryansh , Aksenov Mikhail , Durygin Nikolay , Golovin Oleg , Solovyev Iliya , Govorkov Denis , Vedernikova Yuliya , Iskakov Daulet 
Published: October 2016

Abstract
Gas condensate fields present unique challenges regarding data acquisition, data quality, exception-based surveillance, flow modeling, nodal analysis, well testing, allocation, and visualization. Although existing tools and methods address many of these aspects, it is possible to streamline processes and explore increased production efficiency methods. This paper addresses these challenges; it presents a case study of an intelligent control system implementation for a gas-condensate field based on a unified data model, integrated modeling, and cross-domain workflows.
This paper presents a transformative, intelligent, and automated work process, referred to here as "smart workflows." As part of these workflows, virtual gauges are used that are based on inflow models and lifts, adjustable valves, and modular networks. The workflows are implemented on a truly open end-to-end platform that enables the coupling of multiple databases, streamlining of data for an integrated analysis of the measurements and model calculations, and ascertaining the mismatch between the two. The workflows also initialize adaptive self-tuning procedures.
The smart workflows enable engineers to achieve various improvements, including an integrated structure of process data model to enable quick access to validated data, monitoring and control functions to a gas-condensate field in real time, and reduced downtime and operational costs. The smart workflow also supports functions that include collection and verification of measurement data, configuration of the integrated solution component models, evaluation of the action of root causes, and planning of operation scenarios.
As part of the implemented system, an integrated information system data structure sets the degree of relatedness of tasks, each of which can be initialized depending on work situations and/or operator commands.
Such comprehensive analysis of the data provides reliable integrated system configuration parameters of the model, which increases the accuracy of the calculations used in the optimal planning of the operational scenarios.
Modelling of Hydraulic Fractures Propagation in the Layered Elastoplastic Media
Authors: Stefanov Y. P. , Bek D. D. , Akhtyamova A. I. , Myasnikov A. V. 
Published: October 2016

Abstract
One of the understudied problems of hydraulic fracturing are patterns and mechanisms of cracks propagation in the media containing plastic enclaves and layers. The importance of this problem is related to the development of unconventional reservoirs, which may contain a significant amount of clays and kerogen. Apparently, under specific conditions, such formations manifest plastic properties and failure mechanism is of viscous nature and is attended by remarkable plastic deformations. Thus, the question about crack propagation pattern in the layered formations with great contrast in strength and elastoplastic properties is arisen.
Bazhen shale formation could be referred to such unconventional reservoirs. The formation covers an area of almost one million square kilometers and contains about 18 trillion tons of organic matter. The reservoir is built up of interstratification of clay, siliceous and carbonate layers with kerogen, organic matter and other minerals particles, which results in the heterogeneous distribution of mentioned above characteristics of massive.
The goal of this research is the investigation of specific of cracks propagation in the media, containing plastic layers and layers with contrast strength properties. The study was carried out by using the numerical simulation of deformation and failure process of medium with the initial crack of a given length. Calculations were performed using software package where the system of equations of continuum mechanics including equations of motion and consistency and constitutive relations of material behavior were solved numerically. Material behavior is defined in terms of modified Drucker-Prager model with unassociated flaw law.
The emphasis is on the investigation of crack propagation character in the medium with various properties and revealing the conditions under which branching of cracks may occur. As leading factors affecting the cracks propagation character, strength and elastoplastic properties, thickness and relative position of layers and initial stress distribution are considered. Further significant factor defining character of cracks propagation is rate of load application in terms of pressure increasing rate and its changing on the tip of the crack, which as a result determine distribution of pressure in the growing crack
Shale Poroelastic Behavior Determination by a Novel Tensile Strength Test
Authors: Borglum Scyller J. , Stetler Larry D. 
Published: October 2016

Abstract
This research proposes to answer the question, what are the directional dependencies of the poroelastic properties of shale? To fully answer this question, the following tasks will be completed. First, determine shale properties: strength, elastic and permeability. Second, determine what effective stress(es), or range, exceeds the shale's tensile strength. Lastly, determine a theoretical model for fracture propagation in shale. A large-scale laboratory experiment has been designed to subject shale to pore over-pressurization and induce tensile fractures bringing the sample to failure. It is anticipated that the pressure differential, elevated pore pressure in a low permeability rock sample, and concomitant bleeding off of confining pressure will induce tensile fractures affected by poroelastic properties of the rock. The results from this experiment will be used to calibrate a forward finite element numerical model, which can then simulate the tensile fracturing process and answer the above question. With rare exception, tensile strength is determined using the indirect method, a method that is industry standard, but by definition cannot describe uniform internal failure as it is intended to fail a sample diametrically. This project will use laboratory experiments to simulate the physical processes of initiating a tensile fracture with excess pore pressure. A numerical model will be constructed that simulate the laboratory experiments to illustrate the coupling of pore pressure, matrix stress and fracture initiation. The laboratory experiment is designed to provide data to with which to calibrate the model and validate the model's output. This model can then be used on the one hand to better design completions programs for hydraulic fracturing and, on the other hand, how to design safer storage caverns in shales. This research will make use of the coupling between a shale's matrix properties and the fluid properties contained within the pore space in order to evaluate the shale's usefulness for various applications: 1) completions engineers in the petroleum industry who endeavor to hydraulically fracture shales, and 2) those who do not seek to fracture shales, such as engineers designing shale caverns to store natural gas or carbon dioxide.
Horizontal Well Water Cut Estimation due to Water Coning in Heterogeneous Formations with Vertical Flow Barriers
Authors: Safin D. A. , Korobkin A. P. , Sitnikov A. N. 
Published: October 2016

Abstract
Water coning and cresting process complicates oil production from reservoirs with bottom water by severe water cut increase after water breakthrough and amplify the load on surface fluid processing equipment. Volume of easy to recover oil reserves declines gradually, thus creates the need in the instrument for economic evaluation of the profitability of such reserves, taking into account the possible geological risks.
This instrument must account for formation heterogeneity and flow barrier distribution, wellbore trajectory and well spacing. It should be noted that oil production with drawdown below critical in most cases is not economically feasible, so water cut estimation after water breakthrough is an important factor.
Water coning in horizontal well is a complex process indescribable by analytical models derived for homogeneous formations. Semi-numerical model of water cut estimation based on series of numerical calculations is presented. Model accounts for vertical flow barriers distribution and is compared with existing analytical and empirical solutions.
To consider the impact of formation heterogeneity and flow barrier distribution the combination of geological and flow simulation software were used to produce a large series of simulation runs. Data analysis produced stable relationship of recovery factor to water cut for a simplified field block considering variations in facies distribution parameters and dip angle. Due to complexity and uncertainty of real field geological properties a statistical approach was used to achieve most accurate well production profile estimation. Water cut descriptive function was derived to allow model application in semi-analytical production profile estimation.
After analysis of over 150,000 simulation runs with different reservoir parameters a reliable function of water cut to recovery factor for field block with horizontal well was achieved. This function takes into account flow barrier distribution through variogram stochastic distribution method, reservoir dip angle, oil column thickness, well construction and offset. Derived function allows exclude production rate and relative formation properties by usage of block recovery factor. Resulting model allows calculation of water breakthrough time and following water cut for horizontal well due to water coning process for various types of reservoirs. Large number of runs provides probabilistic estimation of well production profile (P10 P50 P90) for each reservoir properties combination.
Exploring through Fracturing in Eastern Siberia: Defining Gas Production Potential from Low-Temperature Sandstone of Chayandinskoe Field
Authors: Yudin Alexey , Paskhalov Maxim , Butula Kreso Kurt , Astapenok Vladimir , Vernigora Denis , Gennadievich Kreknin Sergey , Pushnikov Konstantin , Zykov Alexey , Borovinsky Yuri 
Published: October 2016

Abstract
With reserves of over 1 trillion cubic meters, Chayandinskoe oil, gas, and condensate field (OGCF) is one of the strategic fields in eastern Siberia. The field is currently in the exploration stage. Geological properties of the formations vary significantly, and it is necessary to define appropriate methods of well construction and completion prior to switching to a field development stage. One of the prospective options is to implement hydraulic fracturing in low-permeability areas of the Chayandinskoe. A pilot stimulation campaign was executed in 2015–2016 to test the efficiency of hydraulic fracturing in vertical wells and in one subhorizontal multilayer well.
The geology of eastern Siberia formations is unique. In particular, producing formations of Chayandinskoe field have extremely low temperatures (8 to 13°C) that require a principally different approach to fracturing fluid design compared to the majority of the operations in western Siberia. One challenge is to achieve a fluid that is stable but that can break within a few hours after the treatment. Laboratory research was a significant part of the project preparatory stage; enzyme breakers, in particular, were included to the recipe. Methane hydrate creation is another common challenge in these reservoirs; special inhibitors under high concentrations were integrated within the fluid formulation.
Within two winter campaigns (a total of five fracturing stages), there were three wells stimulated. The Khamakinskiy producing formation was tested in all three wells, and the Botuobinskiy and Talakhskiy formations were tested in a subhorizontal well in 2016. Advanced logging suites were run in both the pilot and lateral holes of the wells to optimize fracture modeling and placement. This paper contains detailed description of the core and laboratory testing performed in the laboratory for fluid optimization. The specifics of completion of a subhorizontal well with a multistage stimulation assembly is described. In this well, premium ports were used to allow for selective interval isolation. Well cleanout and nitrogen kickoff via coiled tubing were done to minimize near-wellbore damage and prevent hydrate creation during fracturing fluid flowback. The flow profile was measured using a special multiphase imager run with fiber-optic-enabled coiled tubing. Results have shown that fracturing as a method of field development is effective, but requires a complex preparatory stage in the laboratory and further optimization to local logistics and geological conditions.
The project is one of the first gas fracturing campaigns in eastern Siberia. The methods developed and the lessons learned in this project are of paramount value for future stimulation campaigns for field development in the region.
Estimation Viscosity and its Heterogeneity by NMR Logging Tool in Reservoir Conditions in Oilfield with Heavy Oil: Practical Results
Authors: Musin K. , Abdullin T. , Shipunov T. , Khisamov R. 
Published: October 2016

Abstract
Heavy oil reservoirs are expected to have viscous anisotropy, both vertical and lateral, with viscosity value varying in the range of several orders of magnitude. Today, there is no any reliable technique to define viscosity anisotropy and to estimate oil viscosity in-situ. The existing methods cannot evaluate the viscosity of crude oil without its lifting to the surface. The solution is the Nuclear Magnetic Resonance (NMR) process which is capable of both reservoir characterization and formation fluid properties analysis.
Oil samples in such a case should be collected from reservoir zones that have not been exposed to heat or chemicals. Such samples can be derived, particularly, from oil-saturated core material recovered while drilling wells in newly discovered fields or in untreated reservoir areas. Centrifuge method (HSC) turned out to be the most successful and less laborious. The obtained by HSC samples most accurately reflect the intrinsic properties of potentially recoverable fluid.
Methods whisch can determine mobile oil viscosity from relaxation time is existing. However, all the earlier empirical equations fail to determine oil viscosity higher than 1000 MPa•s. It has been shown that the logarithmic mean spin-spin relaxation time demonstrates the best correlation with oil viscosity, which in combination with a calculated time cutoff, yields over 80% accuracy in viscosity estimation. The developed technique determines oil viscosity distribution from high-field NMR-logging data after calibrating correlation factors.
Considering oil viscosity anisotropy yields a significant economic benefit including the reduced costs of steam injection and increased cumulative oil production.
The Differentiated Approach of the Reserves Estimation for Source Rock Formations
Authors: Alekseev A. D. , Antonenko A. A. , Zhukov V. V. , Strizhnev K. V. 
Published: October 2016

Summary
Today, it has become pretty obvious that the rocks that were conventionally believed to be source rocks are, in many cases, oil bearing rocks. This oil bearing potential can be attributed to both filtration of the hydrocarbon fluids in the reservoir and artificial generation of liquid and gaseous hydrocarbons by heating the solid organic matter underground. The suggested differentiated approach to estimation of the resource base allows identifying and assessing oil bearing potentials for various reservoir stimulation techniques: drawdown (due to natural reservoir properties of the rock), creation of artificial permeability, and generation of hydrocarbons by in-situ pyrolysis of the organic matter.