bluuebunny/crossref_metadata_2025 huggingface dataset:
Safe Drilling Technology for Horizontal Wells in Ultra-Thick Salt-Gypsum Rock in The Right Bank of The Turkmen Amu Darya
Authors: Li Wanjun , Zhou Haiqiu , Wang Wei , Wang Gang , Gu Yixin , Xiang Hua , Lin Jiahua , Mu Zihan
Published: October 2017

The formation of Section B, which is on the right bank of the Amu Darya consist of high pressure salt and gypsum formation. The average thickness of the salt-gypsum layer is about 900 meters, the maximum pressure coefficient is 2.3 g/cm3, the salt rock is easy to creep, resolve, and crystallize. The salt layer is close to the reservoir. Wellbore path is difficult to control. The drilling accident rate is 34%, and the success rate of high pressure brine drilling is 0, which leads to the fact that no horizontal well drilling has been carried out. In order to develop the safety technology, it is necessary to carry out the large angle orientation drilling method in the high-pressure salt water and salt-gypsum layer. However, this kind of method has not been widely used, so it is urgent to solve the safe drilling problem and orientation problem of the high pressure salt paste layer.

The proper proportion of drilling mud in the salt-gypsum layer is optimized by establishing the bore shrinkage equation and using the layer control method to determine the pressure of the salt-gypsum layer.

After that, the unsaturated saturated brine drilling fluid system compatible with the salt rock layer is selected. After the salt-gypsum layer is sealed with casing tube, the reservoir will be re-drilled. The slope will be designed in the salt layer, and the tricone bit control will be carried out by adding the cone bit and selecting the MWD directional drilling tool combination.

The proper density of the well drilling mud will prevent the salt rock from creeping and high pressure salt water from flooding. The stable saturated brine drilling mud will then be controlled effectively, and the stability of the well bore caused by salt losing is effectively controlled. The well bore expansion rate dropped from 19% to 2%; with salt-gypsum layer is sealed with 250.8mm thick anti-extrusion casing, and the water expansion packer is installed, which effectively prevent high pressure salt water channeling and casing tubes collapsing. After that, it is easy to control the drill direction angel in the high-pressure salt gypsum formation between 0° and 80°. After putting the directional drilling tool in the centralizer position and combined with other skills, the drilling speed has been increased by 8.7%.

Up till now, the horizontal drilling technology has been widely used in the zone. 50 wells have been using this drilling technology and goes on well.
New Ridge Diamond Elements Improve PDC Bit Efficiency
Authors: Gumich D. , Pak M. , Lomov A. , Gorobchenko M.
Published: October 2017

Rate of penetration is one of the key performance indicator for drilling process. PDC bits have the most efficient rock fracture mechanism: PDC cutters penetrate a rock and shear it layer by layer. Different PDC bit designs are created for special geological conditions during the optimization process. However, it’s not enough just developing bit designs, because the whole potential of diamond cutter elements are uncovered. Researching activity brought us new Ridge Diamond Element (RDE). It has tungsten carbide substrate like a conventional PDC cutter. Unique ridge shape of diamond table is a RDE distinguishing feature. This profile allows RDE to engage the rock more efficiently versus conventional PDC cutter. There is combination of two rock fracture mechanisms – shearing and crushing. Laboratory tests have shown high performance of new diamond element: durability increasing, lower weight for cutter penetration the rock, bigger size of cuttings and higher rate of penetration. Efficiency of this new technology was proved by field tests in different Russian oil and gas regions.
Hybrid Drill Bit Mitigates Downhole Vibrations, Improving Drilling Efficiency in Challenging Curve Section of a Highly Interbedded Formation
Authors: Simiao Sheng , Jun Zeng , Ming Li , Yubao Shi , Chunliang Gao , Jin Hui , Wang Changhao , Wang Chen , Qi Yue , Li Deqing
Published: October 2017

As the demands of natural gas increase, the quantity of deep natural gas horizontal wells rises by 33% each year in Northeast China. Highly interbedded formations containing claystone and sandstone are located in a curve section that can result in harmful drilling vibrations. Tool face control and downhole tool failure are the key problems in these wells. Various downhole tools and drill bits have been tested for this application, and new design hybrid bits have proved to be the best choice to mitigate harmful vibration and improve drilling efficiency.

Normal polycrystalline diamond compact (PDC) bits often experience strong vibrations and accelerated wear. While roller-cone bits are less aggressive, they deliver lower rate of penetration (ROP) and drill limited distances due to their short bearing life. Because of this, a new technology hybrid drill bit, which combines the advantages of a fixed-cutter and roller-cone bit, was tested in this field. Based on the performance of the first-generation hybrid bits the cutting structure was upgraded to maximize the drilling efficiency and durability, achieving higher penetration rate.

After two years of development and evaluation, the new design hybrid bit has proven to mitigate these harmful vibrations, solving tool face control problems, mitigating downhole tool failures and significantly improve the drilling economics. The new hybrid drill bit increased ROP by a record 2.6 times, with a 160% increase in footage drilled compared to roller-cone bits with the IADC of 627 in the same group formation but drilled in the vertical section. This revolutionary new hybrid design also drilled 1.6 times faster and 1.7 times longer than the original hybrid design. In addition, the bit increased the borehole quality, which would help with casing job in the future operation.

This paper presents a case study of two hybrid bits utilized in the directional and horizontal section in Northeast China. Analysis of the drilling data and the detailed operation situation show the economics and the potential of the new hybrid technology as a tool to mitigate harmful vibrations and step-stage improve in drilling efficiency and rate of penetration.
Performance Challenge Upgrade: 16-in.TCI Design Achieves Multiple Drilled Wells Through Highly Interbedded Anhydrite, Shale, and Carbonate Formations
Authors: Al-Enezi D. , Al-Shelian J. , Muqaddes Z. , Beheiry K. , Linnerud B. , Heiny A. Al , Maouche Z.
Published: October 2017

Drilling a 16-in. section in southeast Kuwait presented several challenges. The formation is highly interbedded with significant variations in compressive strength ranging from 3 to 25 kpsi. Potential loss of circulation zones complicated drilling performance and required the flow rate and other drilling parameters to be controlled. Bit balling of the bit cutting structure was expected in some intervals where water-based mud was typically used. The drilling assembly was a pendulum rotary design.

The variation in formation compressive strength and formation hardness in addition to the highly non-uniform lithology created high impact forces on the roller cone inserts. Additionally, insufficient hydraulics and the high weight-on-bit necessary in the Dammam to Ahmadi carbonates led to the premature failure of the cutting structure and bearings. A durable and reliable bit design was necessary for drilling the entire interval as well as the subsequent well to help reduce overall drilling costs.

Collaboration between the operator's drilling team and the bit supplier resulted in successfully drilling a 16-in. challenging section and multiple additional wells. Rock types and compressive strength were analyzed using an advanced software program to determine the high-impact intervals and expected loss zones with insufficient hydraulics. Previous performances in the interval, as well as bit conditions, were thoroughly analyzed. These studies and finite element analysis were used to develop the new tungsten carbide insert (TCI) bit design featuring improved hydraulics configurations, durable and robust rubber seals, and advanced cutting structure materials. The design was dynamically tested in the laboratory in a similar application environment.

The new bit design exhibited exceptional performance in multiple wells in the 16-in. section in southeast Kuwait. The bit was used to drill three wells with a cumulative footage of more than 9,000 ft in more than 240 drilling hours. Approximately two million revolutions were achieved with effective bearings and slight normal wear to the bit cutting structure elements. The new bit design helped drill longer intervals and multiple wells with no risk of premature failure and helped reduce drilling time and bit costs.
Integrated Casing Surface Casing String Cementing Procedure under the Conditions of High-Intensity Process Liquid Absorption in the Eastern Siberia Oilfield
Authors: Bykov V. V. , Paleev S. A. , Zakharenkov A. V. , Samoylovich A. V. , Medvedev Y. V. , Kolesnikov S. G.
Published: October 2017

Throughout the entire oil fields' development drilling period on the territory of the Eastern Siberia, one of the main problems appearing in the process of well construction remains highly intensive, down to catastrophic, process liquid absorption. Loss of circulation during the well drilling can lead to a number of complications related to the bore-hole stability, possible losses in the mobility of the bottom-hole assembly (BHA), and other complications. To meet the current problems, drilling enterprises constantly test various technologies and materials aimed at solving the problem of well construction in the conditions of high-intensity absorption. The technology using an aerated process liquid and running off intermediate casing strings (directions) was chosen as the basic technology used in drilling the surface casing string interval under conditions of emerging absorptions at the oil fields in Eastern Siberia. When working with this method, there was a possibility of poor-quality casing string cementing in the conditions of absorption of process liquids, leading to significant complications and a decrease in the service life of the well.

The main goal of this work was to identify an approach aimed at solving the problem of low efficiency of standard methods and bridging materials used for surface casing string cementing jobs under the conditions of absorption. An analysis of a number of bridging materials was carried out, the most suitable product was determined, the existing technologies for eliminating the absorption and the possibility of their application in the fields of Eastern Siberia were considered.

This work represents the results of laboratory tests of plugging compositions, pilot-industrial works carried out in a number of fields on the use of complex cementing technology for the surface casing strings in the presence of absorbing horizons, using visco-elastic mud and developed cement-and-gypsum compounds.
Improving Production Efficiency of Liquid-Loading Gas Condensate wells with ESPs at North Urengoy Field
Authors: Epryntsev Anton , Minikaev Farid , Sullagaev Alexey , Yazkov Alexey , Khachaturyan Benik , Vildanov Eldar , Fastovets Andrey , Erdman Andrey , Selivanov Sergey
Published: October 2017

Frequently, production from gas and gas condensate wells is negatively impacted by the wellbore accumulation of liquid – a mixture of water and condensate. As reservoir pressure and tubing gas velocity decline and produced water cut increases, heavier liquids can no longer be effectively removed from the wellbore, resulting in the liquid column build-up at the bottomhole. This creates additional backpressure on the producing formation and leads to gradual production decline, until the well completely stops producing – the condition widely known as "liquid loading". Use of smaller size tubing (velocity string) is often the simplest and most straightforward solution, but depending on reservoir properties (water cut, productivity and pressure) and well completion (vertical, slanted or horizontal) this approach may not be efficient. This paper describes the technical approach to resume continuous production from liquid-loading gas condensate wells at North Urengoy field. It is shown that Electric Submersible Pumps (ESPs) can be successfully applied to unload horizontal wells producing large amounts of water. In this application, water and condensate is lifted by the pump through the tubing string, while gas and condensate mixture is simultaneously produced through the annular space between the tubing and the casing. Reviewed in detail are the technical challenges of modeling the well and pump performance using dynamic multiphase flow simulators, and the ESP design for the pilot application in deep, horizontal gas condensate well in Russia.
Peculiarities of the In-Field Gas Gathering Systems at the Latest Stage of the Development of Cenomanian Deposit Yamburgskoye Gas Field
Authors: Kudiyarov G. , Istomin V. , Egorichev A. , Stonozhenko I. , Rotov A. , Sergeeva D.
Published: October 2017

The latest stage of gas field development is characterized by some exploitation complications, related to reducing of gas rates and as a consequence a water accumulation in gas-gathering systems (in-field gas pipelines). It leads to a formation of ice and/or hydrate deposits in contact with a cold wall of pipeline with negative (on Celsius) temperature as a result of an environmental impact.

Analysis of gas-gathering systems of the Yamburg field (Cenomanian horizon) revealed qualitative differences between ice and hydrates deposition. For instance, ice formations are characterized with higher locality due to significant water accumulations on the lower section of the pipeline and ice growth at the wall of pipeline. Thus, liquid plugs play a key role in the formation of ice plugs that block pipeline's cross-section, reduce the stability of gas collection system's technological regime and gas production.

The purpose of this work is to discuss some technical solutions, efficiently eliminating the accumulation of liquids in gas-gathering systems while having a low exploitation expenses, simple realization and flexibility of applications compared to existing ways.

A technical solution for local diameter reduction facilitates the water plugs removal at most critical in terms of ice formation. An approach, based on the application of lay-flat polymer sleeve for local pipe diameter reduction allows the increasing velocity of gas-liquid flow at a given pipe sector for providing stable liquid removal without its accumulation. Target pipe areas suitable for the technology are chosen based on hydrodynamic modeling, accounting for the actual pipeline route.

Application of an ejector unit and in-tube separator enables to independently decrease pressure at the pipeline by 1.5-3.5 times. This leads to increase of gas-liquid velocity by 2-3 times, which leads to liquid removal. This allows reduction of methanol consumption, which is used for water freezing prevention.

The proposed technologies allow variations in realization dependently on requirements for exploitation modes and for time-changing parameters of gas-gathering systems operation. These technologies can be considered as a part of a complex strategy for gas-gathering system reconstruction at the stage of production drop.
Development, Implementation and the Results of Implementation of Novel Dual Completion Technology, and New Methods of Evaluation of Oil Wells Layers during Dual Completion
Authors: Isaev A. A. , Takhautdinov R. Sh. , Malykhin V. I. , Sharifullin A. A.
Published: October 2017

During operation of oil wells with multiple pay zones having a common filter, a negative factor may occur due to the crossflow of formation fluid from the high-pressure reservoir to the low-pressure reservoir, which leads to insufficient oil production. Currently, different types of dual completion (DC) arrangement are used to operate more than two pay zones. In PJSC Tatneft, dual-lift [1-6] and single-lift units are widely used [7]. But dual-lift DC systems have drawbacks such as high costs on capital investments and maintenance. The drawbacks of a single-lift unit are the following: the high cost of upgrading, as the unit consists of two pumps of the same type and size; plunger twist-offs occur at the place of their connection; there is a difficulty in separating the cylinder depending on the productivity of the formations in case production rate of at least one of the formations changes; the unit can only operate two pay zones apart from each other.
Case Study: Application of On-Off Adaptive ICDs with Inner Sliding Sleeves in a Horizontal Well in Saudi Arabia using 2 3/8-in Coiled Tubing
Authors: Anopov Alexey , Alomair Ahmed , Aseeri Mohammed A. , Ahmed Danish , Molero Nestor
Published: October 2017

Inflow Control Devices (ICDs) are completion hardware often used in horizontal wells to balance flow rates across the completion for the entire length of the interval. This is accomplished by creating an additional pressure drop on each ICD to equalize pressure drawdown along the reservoir to achieve a more homogenous flow profile along the horizontal section. ICDs are also used for selective zonal isolation and for delaying the flow of unwanted fluids such as water and gas into the horizontal wellbore.

The conventional method to shift the ICDs uses a downhole tractor conveyed with an electric line (e-line) cable or a standard coiled tubing (CT) string; the shifting activates the production of horizontal wells equipped with these devices. However, there are some challenging cases, for which neither of these traditional methods represents a reliable alternative to actuate the ICDs for several reasons, including Drag and buoyancy forces encountered in the wellbore close to the operational limits of the e-line cableWellbore severity, tubular restrictions, and well configuration, which hinders the ability for electric line cable to access target depth, even with the use of a downhole tractorThe absence of downhole measurements in standard CT use for accurate depth control and confirmation of ICD status and shifting tool performance.

In a well in Saudi Arabia, electric line was unable to reach target depth, and conventional CT did not provide the confidence needed to act. In this well, CT equipped with real-time downhole measurements was successfully used to actuate up to 10 ICDs in a horizontal well. The real-time downhole measurements included pressure, temperature, depth from a casing collar locator, and tension and compression from a tension-compression sub. The experience gained with this technique in the successful operation in Saudi Arabia yielded recommendations for future similar operations.
New Possibilities of Well Testing and Production Logging in Horizontal Wells with Non-Uniform Inflow Profile
Authors: Kremenetsky M. I. , Melnikov S. I. , Ipatov A. I. , Kolesnikova A. A. , Shorohov A. A. , Buyanov A. V. , Musaleev K. Z.
Published: October 2017

This paper discusses the integrated interpretation of well log data collected in horizontal production (injection) wells with low flow rates and non-uniform inflow (injectivity) profiles. A factor analysis is performed and information value of these methods in horizontal wells is defined.
Development of Automatic System for Decline Analysis
Authors: Kotezhekov V. , Margarit A. , Pustovskih A. , Sitnikov A.
Published: October 2017

Traditional well testing methods applied for production wells for estimation of reservoir porosity and permeability, pressure, and other parameters imply the shutdown of wells to carry out pressure build-up tests. These tests entail significant losses in oil production and, in many cases, do not provide enough information in the event of low-permeability reservoirs because of the insufficient duration of the testing. An alternative to the pressure build-up test is an estimation of well and reservoir parameters based on production data (decline-curve analysis) carried out by means of special software. As compared to the pressure build-up test, the interpretation of decline-curve analysis allows to decrease losses in oil production during shutdowns, assess well interferences and boundary conditions, etc. (Ipatov and Kremenetskiy, 2008). Because of the growing number of wells equipped with high-precision pressure sensors for downhole telemetry and due to ongoing tasks related to monitoring and control of the development process, it is necessary to reduce labor hours required for production data processing.

This thesis provides a description of the system designed to introduce automation into the interpetation of production data by means of the machine learning techniques.
Borehole Acoustics as a Key to Perfect Hydraulic Fracturing in Achimov Formation
Authors: Metelkin D. A. , Snokhin A. A. , Tikhomirov I. A. , Karpekin E. A. , Eremeev A. A. , Korelskiy E. P. , Kalinin V. , Jocker J.
Published: October 2017

For economic production, the heterogeneous low-permeability Achimov formation of the Urengoiskoe field requires stimulation with high-volume hydraulic fracturing. Shales acting as stress barriers are present within the reservoir, dictating the necessity of fracture geometry monitoring and design accounting for local changes in mechanical properties. A new slim dipole sonic tool enables a reliable identification of fracture geometry in the near-wellbore region. The tool dimensions allow it to be run in environments unsuitable for conventional-sized sonic tools such as completions with a small inner diameter.

Analysis of sonic data in three wells reliably identified unintended fracture growth from the lower target Ach6 reservoir through the shale barrier into the upper Ach5 reservoir. Calibration of the fracturing model using the measured fracture height reveals that the main uncertainty in fracture geometry prediction originates from the input formation mechanical properties and stress profile. Therefore, fracture design optimization should include updates to the geomechanical model with account for the presence of structural VTI-anisotropy as well as justified dynamic-to-static conversions, refined pore pressure profiles, etc.

This paper demonstrates the use of dipole sonic pre- and post-frac logs to determine the real fracture height as well as the corresponding impact on the calibrated fracture model. A way forward is proposed to improve geomechanical models by including sonic-based anisotropy parameters to improve fracture geometry predictability in target zones.
Dynamic Reservoir-Pressure Maintenance System Study in Carbonate Reservoir with Complicated Pore Structure by Production Analysis, Production Logging and Well-Testing
Authors: Aslanyan A. , Gilfanov A. , Gulyaev D. , Krichevsky V. , Timerbaev M.
Published: October 2017

To discover remained reserves and recommend production enhancement operations in a carbonate reservoir with long production history it is important to perform not only production analysis, water breakthrough areas, but also areas, that took a lot of injected water during injection history. It's not an easy task in case of complicated formation pore structure especially than injection were carried on with high pressures and overbalancing.

Combined approach was used for remained reserves localization and production enhancement operations. It included complex geology study, production history and surveillance data. Well interference was examined by novel technology - multi-well deconvolution (MWD).
Oil Fingerprinting Technology for Well and Reservoir Management
Authors: Pavlov Dmitry , Vasiliev Anton
Published: October 2017

Oil fingerprinting is a common name for techniques based on geochemical analysis of hydrocarbon fluids composition which could provide valuable and unique information for well and reservoir management. Hydrocarbons in oil and gas deposits are affected by different processes, such as: biodegradation, gas flushing, water washing and evaporation. The degree of change depends on many factors: temperature, reservoir compartmentalization, tectonics, aquifer activity etc. Consequently, hydrocarbons initially migrated from one source rock become different in different reservoirs and compartments. Evaluation of changes in composition allows identification of hydrocarbons from different reservoirs, in other words to identify unique "fingerprints" of hydrocarbons. This information can be very valuable for production allocation between reservoirs and for needs of well and reservoir management. This article summarizes the results of a pilot oil fingerprinting project on Astokh oil field based on High Resolution Gas Chromatography (HRGC). The primary objective of this work was to develop a methodology for production allocation in comingled oil producers based on HRGC as applied for the Astokh area. In the course of work some more opportunities were identified, for instance monitoring of reservoir dynamics which could turn out to be more powerful than the primary objective.
Automated Interwell Connectivity Measuring in the Presence of Self-Induced Fracturing Effect
Authors: Ivaschenko D. S. , Kravets D. A. , Mumber P. S. , Musin A. A. , Sakhibgareev E. E.
Published: October 2017

The paper presents results of injector-producer connectivity analysis provided by means of the specialized software according to the field data – production and injection rates, producer bottomhole pressures. The "capacitance-resistance" model and its integrated modification are used. The suggested method is applicable to low-permeability reservoirs exhibiting self-induced fracturing effect. The problems of producer watering source quick searching and self-induced fracturing risk forecasting in kickoff horizontal sidetracking zones might be considered using this approach.
Improvement of Reservoir Management Effectiveness through Optimization of Bottomhole Pressures of Wells
Authors: Iktissanov Valery , Bobb Irina , Khalimov Rustam , Ganiev Bulat
Published: October 2017

The existing methods of reservoir management based on bottomhole pressure control imply setting of limited bottomhole pressures that are determined either through equations or based on pressure transient analysis (PTA). However use of project profitability metrics commonly applied in oil industry–cumulative oil production and net present value (NPV)–yields more valid results. In doing so, all basic aspects must be taken into consideration: geological setting, current reservoir performance, reservoir fluid properties, well interference, and others. This can be achieved through application of 3D flow simulation and inverse modeling methods.

To this end, we have developed an algorithm and created a few pilot models with different reservoir characteristics and fluid properties identical to conditions of actual reservoirs operated by the Company. The calculation results were analyzed considering specific reservoir conditions. We have revealed some principles and tendencies that can be applied to improve performance of oil and gas fields. The research results show that the choice of optimal bottomhole pressure is largely dictated by presence or absence of gas-cut fluid flow. In case the bubble point pressure is close to the initial reservoir pressure, optimal bottomhole pressures differ significantly from limiting bottomhole pressures and, thus, should be calculated. In case the bubble point pressure is lower than the original in-situ pressure, limiting bottomhole pressure is the right choice for production wells. We also found that in fractured-porous reservoirs the right time of putting injection wells into operation is of critical importance. The revealed principles and recommendations can be applied to improve the effectiveness of reservoir management operations and increase final recovery.
A Tool for Achieving the Base Production Potential
Authors: Zhdanov I. A. , Andzhukaev Ts. V. , Margarit A. S. , Pustovskikh A. A.
Published: October 2017

The achievement of the well potential in the majority of Russian oil companies is monitored on an advisory basis using low-integrated approaches and tools. These processes are not automated enough [1]. As a result, 80% of the labor is spent on performing routine operations: collecting and preparing input data for analysis. This leads to suboptimal and untimely decisions to manage the development of current assets, and consequently, to lost production, increased water cut, an increase in the time to achieve the estimated oil recovery factor (oil RF), and unproductive injection into induced fractures. Thus, the purpose of this paper is to develop a decision support tool for a reservoir engineer.

This paper describes the methods and functionality of the tool used to achieve the potential of the base production, which makes it possible to automatically, systematically and efficiently formulate recommendations for injection control, to select wells that are optimal for conversion to injection, to select candidates for treatment of the bottomhole zone, remedial cementing, well logging, and flow tests.
Building and Application of Integrated Model of a Large Sakhalin Offshore Oil and Gas Condensate Field
Authors: Kuzevanov M. A. , Skvortsov D. O. , Karmazin M. S. , Buchinskiy S. V.
Published: October 2017

Integrated modeling is a tool of managing a process of hydrocarbon production from an asset, which consists of downstream and upstream elements. Integrated model subsequently covers complex relationships between reservoirs, wells, pipelines and elements of subsurface infrastructure. In many ways, efficiency of oil and gas field development depends on these relationships [1]. For this reason, modeling of a hydrocarbon production process should embrace a whole chain (from upstream to downstream) and integrated modeling is best suited for this task [2]. The main purpose of this work was to evaluate the possibility of well operation condition optimization with account of subsurface infrastructure using integrated modeling tools.

The paper gives a review of a modern approach to modeling a large Sakhalin offshore oil and gas condensate field, the X Field. Oil producers have been drilled from the shore into oil rims of reservoirs with record-breaking horizontal offset in the oil and gas industry. Initial oil rates exceed 3000 ton/day. However, the field development is complicated at the moment, due to gas breakthrough from the gas cap which leads to a critical decline in well performance. An integrated model includes simulation models of two oil/gas reservoirs, well models, and a model of single gathering system. The paper briefly describes the approach to building and matching the integrated model.

After building and history matching of the integrated model, sensitivity of oil production to a change in well operation condition was analyzed. Also, mutual well influence on the gathering system level was evaluated. As a possible scenario for well operation condition improvement an intermittent well operation was considered. The results of model runs demonstrate that a change in well operation conditions won't positively affect oil production in short period.
Integrated Modeling as an Instrument for Unique Gas Condensate Field Development Concept Choice
Authors: Gataullin T. I. , Poushev A. V. , Prokopenko A. V. , Sullagaev A. V.
Published: October 2017

One of the most important challenges of the current stage of the field development is selection of concept of infrastructure system development and solution of classical problem of optimization:

Minimization of capital expenditures for infrastructure development, Minimization of cost of production, treatment and intra-field transportation of the raw material to the LNG plant, Ensuring of high reliability of the entire infrastructure system for continuous flow of raw material to the LNG plant trains. Reaching of the field performance targets, namely: - Duration of the period of continuous gas production - Hydrocarbons recovery factors

Besides, in designing of the infrastructure system and accordingly, in selection of the solution, it is necessary to take into account the following factors representing complexity of the future industrial activity in general:

Geographical location of the field in the area with challenging climatic (arctic) conditions which calls for the necessity of maintaining of high level of self-sustainability in the field; Considerable differences in values of formation and accordingly, wellhead pressures of the production wells stock;

Taking an optimal decision in part of concept of infrastructure development in these challenging conditions is possible only on the basis of the complex integrated digital model "Well - Reservoir - Gathering network - Treatment system" allowing for correct evaluation of engineering parameters of field development with account for the effect of existing limitations related to reservoir, well design, downhole equipment, gathering system and production treatment.

Solving of this problem using the up-to-date modeling technologies accounting for mutual effect of all elements of the system on the basis of multi-disciplinary teams includes the following:

Generation of the integrated models "Reservoir - Wells - Gathering system - Treatment system - In-field transport system to the LNG Plant Inlet", Separation of individual types of process design calculations for analysis with consequent incorporation into the integrated model, Carrying out of multi-option calculations of engineering parameters of development and infrastructure, Assessment of the results of calculations of engineering parameters of options by specialists of the multi-disciplinary team, Economic assessment of costs of implementation of the studied options.

Using the above mentioned approach with involvement of the integrated field model, multi-option calculations of location and parameters of production treatment facilities and dynamic calculations of flow lines operation parameters for various scenarios of the LNG plant were performed.
Analysis of Geological and Hydrodynamic Uncertainties in the Design of Field Development Indicators
Authors: Kravtsov A. I.
Published: October 2017

For the most objective evaluation of deposits with low geological knowledge and obtaining the scope of the most likely development results, the use of uncertainty analysis tools is necessary. This type of analysis includes the maximum possible set of geological and hydrodynamic parameters that have a major impact on hydrocarbon production levels, where each of them has uncertainties that affect the final result to varying degrees. All these parameters are subjected to probabilistic estimation in terms of compliance with available information on well testing. To solve the problem of a large number of estimation options, the most optimal methods for creating model implementations and using proxy modeling are applied. The application of the developed algorithm allows to evaluate both the hydrodynamic and geological parameters of the model for the probabilistic distribution of hydrocarbon reserves by strata and the results of production in the field as a whole. The performed works allow to make detailed recommendations on the removal of the most critical uncertainties for the objects of study.
Hybrid Approach to Reservoir Modeling Based on Modern CPU and GPU Computational Platforms
Authors: Telishev Alexey , Bogachev Kirill , Shelkov Vasilii , Eydinov Dmitry , Tran Hau
Published: October 2017

For modern day reservoir simulators, it is essential to provide realistic physical description of reservoirs, fluids and hydrocarbon extraction technology and guarantee excellent performance and parallel scalability.

In the past, the advances in simulation performance were largely limited by memory throughput of CPU based computer systems. Recently, new generation of graphical processing units (GPU) became available for general purpose computing with the support of double precision floating point operations, necessary for dynamic reservoir simulations. The graphical cards currently available on the market have thousands of computational cores that can be efficiently utilized for simulations.

In this paper, for the first time we present results of running full physics reservoir simulator on CPU+GPU platform and discuss implications of this modern technology on the existing reservoir simulation workflows. We discuss challenges and developed solutions for running reservoir simulations using modern CPU+GPU hardware architecture and propose a methodology to distribute the workload between various parts efficiently. The approach is tested on several data sets on various computational platforms, such as personal computers and clusters with and without GPU's involved.

The technology proposed in this paper demonstrates multifold speed up for models with substantial number of active grid blocks. The speed up due to GPU utilization can in some cases reach as high as 3-4 times compared to the traditional GPU-based approach. Considering the recent progress in the GPU development, this factor is expected to grow in the near future, and the hybrid CPU+GPU based approach allows to utilize the exciting potential of the hardware evolution. The results, advances and potential bottlenecks combined with detailed analysis of the performance and the ‘value for money’ of the modern hardware solutions are discussed.
Reactive Flow Modeling at Pore Scale
Authors: Beletskaya A. , Ivanov E. , Stukan M. , Safonov S. , Dinariev O.
Published: October 2017

Design of acidizing job involves application of reactive flow modeling. Most of the existing research and commercial codes for reactive transport modeling are based on Darcy-scale continuum representation of porous media. Such kind of simulations requires application of tuning coefficients, which, if not chosen properly, lead to inappropriate design of acidizing job. To overcome this issue, we have proposed direct reactive flow modeling approach at a pore scale using exact pore geometry.

The approach developed in this work is based on the combination of principles of chemical kinetics/thermodynamics and density functional theory applied for hydrodynamics (DFH). Chemical reactions are introduced to hydrodynamic simulation within the framework of partial local equilibrium assumption.

In the current study, it is demonstrated that developed approach adequately describes dissolution of porous dolomite rock by solution of hydrochloric acid. Simulations have been performed using 2D model of dolomite granule, 2D model of porous structure and 3D model of Silurian dolomite microstructure. Upon acid injection, the geometry of a rock is gradually changing in the area of acid penetration. As a result of modeling of dissolution of dolomite non-porous granule by solution of hydrochloric acid it is shown that the rate of dolomite dissolution depends on the rate of fluid injection. The average rate of dissolution is increased from 0.07 to 0.23 kmol/(m3·s) with the increase of Péclet number from 0.28 to 46. Similar correlations for porous rock with exact geometry can be utilized for corrections of the reaction rate constants which are used in Darcy scale simulations. Developed approach allows to perform modeling of dissolution reactions at pore scale and paves the way for increasing the consistency between the models used in reactive flow modeling and pore structure features of real rocks which will lead to improvements in acidizing job design.
Modeling Gas Condensate Reservoir Productivity via Industrial Software Solutions in Consideration of Trapped Phases and Closed Pores
Authors: Mikhailov N. N. , Voronich I. V. , Shelepanov S. S.
Published: October 2017

The aim of this work is to study the effect of the capillary trapping of phases in gas-condensate formations on the pattern of fluid filtration and, consequently, the productivity of gas condensate wells. The article proposes a method for increasing the accuracy of filtration modeling in gas condensate wells by including the effect of the capillary trapping in the filtration model.

In this paper, the Forchheimer's equation was used as the filtration law, which is most often used in the modeling of gas and gas condensate reservoir, since it describes the filtration with high-pressure gradients and high velocities quite accurately. The cases were simulated with various nonlinearity coefficients in the form of empirical functions of porosity and permeability described in the literature. Additionally, the work took into account the effects of capillary trapping of phases, the effects of compressibility of the reservoir and the effects of mudding of the wellbore zone. The residual saturation of each phase was calculated by the empirical function of the capillary number.

A solver for open-source software OpenFOAM, which is an integrated platform for computational fluid dynamics problems, was written and verified. The numerical model of this solver allows taking into account such effects as, for example, capillary trapping of phases, mudding of the near wellbore zone and other effects that impair the productivity of gas condensate wells. As a result of numerical calculations, a significant influence of the capillary trapping effect on the performance of gas condensate wells was revealed. The non-additivity of the discussed effect and other effects affecting filtration in the gas-condensate reservoir was shown. Accounting for one-side open pores in numerical simulation also made a significant contribution to the performance of gas condensate wells. The possibility of improving the accuracy of filtration modeling for industrial numerical calculations conducted via special software on supercomputers was shown.

A method for significantly improving the accuracy of fluid filtration modeling in gas-condensate reservoirs by including the effects of capillary trapping and one-side open pores into the numerical model is proposed. Such corrections of the numerical model does not lead to its significant complication and the speed of the computation increases slightly. Thus, the proposed method can be widely used for numerical calculations in the oil and gas industry.
Special Features of Geological Modeling of Shelf Sediments by the Example of East-Urengoy and North-Esetinsk Fields
Authors: Natchuk N. , Uraev O.
Published: October 2017

The work objective of research is improving the quality of the reservoir modeling of the shelf deposits in the Neocomian clinoform complex by means of identification the peculiarities of geologic structure of the layers, and using of them for create the geological models oil and gas reservoirs. The subject of research is BU16-18 layers in East-Urengoy and North-Esetinsk field. The main peculiarities of BU layers are lenticular body, the vertical and the lateral anisotropy of reservoir properties in the reservoir volume, the presence of transition water-oil zone in consequence of layer`s heterogeneous.

For identification and reservoir modeling of the peculiarities of geologic structure the shelf`s genesis layers used the results of seismic attribute analysis, fractional and mineral analysis of the rocks, conceptional model analysis about accumulation shelf sediments.

The result of the research are detecting all the peculiarities of geologic structure the shelf`s genesis layers such as lenticular body, the anisotropy of reservoir properties, the presence of transition water-oil zone. All peculiarities was introduced for create the geological models: structural framework building, expansion of the reservoir properties in the interwell space, saturation modeling taking into account transition water-oil zone parameters.
An Application of Proxy-Modeling Framework for Numerical PVT-Models Matching on Laboratory Measured Data
Authors: Tigran Ambarian , Dmitriy Olenchikov
Published: October 2017

The paper presents a new automated method of matching the equation of state (EOS) of multicomponent system to the laboratory measured data. The method is based on the idea of using a statistical estimator, which allows you to replace the entire space of possible PVT-models that correspond to different parameter values by a simplified, piecewise-polynomial proxy-model. During the application of the method, the proxy model is refined based on the results of intermediate calculations and a global search for the optimal solution is perfomed.

The new approach avoids the drawbacks of the traditional approach using the linear regression or gradient descent methods. The reason is that in highly non-linear problem traditional methods often finds only a local minimum and does not allow us to obtain a solution with an acceptable degree of accuracy. The proposed method allows to effectively adjust the PVT-model to actual data, and mostly times, with higher accuracy than the traditional method.

The application of this method to adjust the equation of state for laboratory measured data is shown by the example of one of the gas condensate field sample. This allowed to reduce the PVT-model error more than 5 times in comparison with the result of using linear regression.
Construction of a 3D Geomechanical Model for Development of a Shale Gas Reservoir in Sichuan Basin
Authors: Xie Jun , Qiu Kaibin , Zhong Bing , Pan Yuanwei , Shi Xuewen , Wang Lizhi
Published: October 2017

Currently, there is large-scale shale gas exploration and development in the Sichuan basin, western China. Due to high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan basin has encountered many difficulties, such as difficulty in placing sufficient proppant, poor production performance for some wells, and ambiguity as to the factors controlling production of the reservoir. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs places a major obstacle to effectively addressing these difficulties.

A 3D full field geomechanics model was constructed for Changning shale gas reservoir in Sichuan basin through integrating seismic, geological structure, log, and core data by following a newly formulated integrated workflow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. 3D pore pressure prediction was conducted using seismic data and calibrated against pressure measurements, mud logging data, and flowback data. A discrete fracture network model, which represents multiscale natural fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural fracture systems.

The 3D pore pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.

The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir and explains how the 3D geomechanical model is used to understand the root cause of poor proppant placement encountered during hydraulic fracturing and events such as mud losses during drilling. Hence, the modeling provides a critical opportunity to improve reservoir stimulation in the shale gas reservoir.