bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Slug Simulation for Transient Multiphase Process Flow
Authors: Kudaibergenova Karlygash 
Published: November 2022

Abstract
Current paper represents water slug simulation details applied to realistic transient scenario of pigging gathering line that transfers oil and gas production to Tengiz Second Generation Plant.
Pigging as well as any dynamic multiphase flow creates a big challenge for receiving facility causing not only inlet separators level fluctuations, but also carrying a risk of process upset and plant facilities damage downstream due to water flooding. Big diameter long distance transportation lines significantly contribute to this risk. One of the triggers to start using OLGA dynamic simulation tool in TCO on constant basis, was water flooding event that damaged stabilizer internals. Modeling is able to predict water slug, considering conditions for water settling in the pipeline prior to transient event, and thus allows to prevent or minimize potential upset.
Several scenario results were reviewed and compared: one versus the other, including scenario with mitigation measures. Hilly underground profile and low flowrate through the line over certain amount of time appeared to be key factors in obtaining reasonable accumulated water content, whereas transient event speed defines how quickly this water will arrive as a slug. Recognizing processing facility handling limits, the control over impact could be maintained by increasing flowrate prior to event and/or reducing speed of change (pig velocity in this particular case). Besides getting realistic water slugs due to rigorous pipeline geometry and flow preconditions, slower actual historical pig movement (against earlier simulated with flat geometry) was finally explained.
Present research was done to demonstrate how accurate and detailed inputs and preconditions to the simulation case can improve software predicted water slugs and create safe guidelines to overcome negative consequences. This practically discovered simulation strategy established itself as credible over few years, is allowing to manage all dynamic operations safely.
Field Development Optimization Under Uncertainty and Risk Assessment of Carbonate Massive Reservoir in West Kazakhstan
Authors: Bigeldiyev Asfandiyar , Ramatullayev Samat , Kovyazin Dmitriy , Sidorov Dmitriy , Malyshev Vladimir , Vogtlander Gernort , Wall Graham , Lungershausen Dirk , Nauruzov Talgat 
Published: November 2022

Abstract
Reservoir modeling has become an indispensable tool in the oil and gas industry to measure risk associated with alternative production scenarios. It is no secret that nowadays more and more operators use deterministic approach for history matching but even so, the task remains technically challenging. Given a large number of uncertainties associated with subsurface models, it has become critical to produce a set of history-matched models and use them for risk assessment in predicting the future performance of the reservoir.
Quantification of uncertainties is a vital process in complex fields to ensure a proper field development plan (FDP) is in place. In this paper, we present a comprehensive workflow that incorporates all processes from building static and dynamic models to producing ensemble of history matched models. To assess the mismatch with historical production data, a number of geological realizations were created and simulated using a variety of uncertainty parameters. Based on the obtained mismatch value, the posterior probability distribution for uncertain parameters updated. Different optimization methods are used to find candidates with improved match quality, and this loop is repeated until a set of diverse history-matched models are generated. These calibrated reservoir models are then used to estimate prediction uncertainties for further FDP optimization.
This study is focused on automating workflows and generating multiple geological realizations that produce a set of history-matched models to probabilistically estimate prediction uncertainties and optimize FDP. We also show how these models are critical in the process of decision making and risk evaluation.
First Trial of Constant Bottom Hole Pressure Drilling Application in Kazakhstan
Authors: Aliyeva Aida , Higginson Tim , Amanbayev Yerlan , Felioune Mohammed , Ashour Waleed , Click Christian , Williams Joe , Uteev Kuat , Azar Scott , Hinson Chase , Katenov Alibek , Issayeva Inzhu , Takhanov Dastan , Naukhanov Adilzhan , Ismuhkambetov Anvar , Kamzayev Nurzhan , Zhakenov Rustam , Kabiyev Kuanysh 
Published: November 2022

Abstract
An increase in differential sticking events, due to depletion of the reservoir and high angle wells being actively drilled in recent years, was a primary driver to utilize Managed Pressure Drilling technology in the Tengiz field. MPD offers a more dynamic and rapid wellbore pressure control by being able to adjust the surface back pressure applied at the annulus for a given mud weight, decreasing the risk of differential sticking while maintaining constant bottom hole pressure conditions.
The paper describes the results of the first Managed Pressure Drilling application in the Tengiz field and experience gained during execution where drilling multiple formations together enabled the target depth to be reached without NPT. It further highlights the operational complexity and the challenges faced during the implementation of this technology while drilling formations with varying pore pressures. The reservoir hole section had different pressure intervals, which required higher mud weight and thus high potential of differentially stuck-pipe conditions. The successful field trial shows that the Constant Bottom Hole Pressure (CBHP) application provides flexibility to be able to manage annular pressures when applying surface back pressure using an MPD choke manifold.
The paper elaborates on the lessons learned and how CBHP was implemented continuously with regards to health, safety, and environment (HSE) during drilling operations. The short-term goals were to evaluate whether the application of MPD could avoid the risk of differential sticking and reduce pumps-off gas, enhance drilling performance by using lower ECD, reducing well control time by working as early kick detection tool and provide a potential for mud cost savings, along with a long-term goal of providing the option to optimize the casing design by reducing one liner section and combining drilling of two reservoir sections in one run.
E-line Deployed Robotics and Stimulation Workflow for Pilot Horizontal Well
Authors: Morrison Angus , Kinnear Campbell , Koishymanova Saltanat , Clayton Dave 
Published: November 2022

Abstract
This paper will outline the challenges faced and solutions employed to enable selective stimulation of a pilot horizontal well in the Tengiz field by mechanical manipulation of fracturing sleeves utilizing an electric line deployed tractor system. Specifically, how the robotic system enabled successful and selective stimulation of nine acid fracturing stages in a challenging operational environment. The scope reviews the planning and execution methodology utilized to enable selective stimulation and production along the lateral section.
While evaluating the concept of drilling a horizontal well through a deeper, previously undeveloped reservoir horizon, it was identified that multiple acid fracturing stages would be required along a 1,000-meter lateral section. The well objectives were such that each of the acid fracturing zones required the ability to be selectively stimulated and produced (selective shut-off of zones post-production if required). This design utilized an open hole completion with compartmentalization via swell packers and fracturing sleeves. Due to the trajectory and horizontal nature of the well, electric line deployed robotics were selected to access the fracturing sleeves.
The well was successfully drilled and completed in 2019 and stimulated in early 2021. All zones were effectively accessed utilizing the selected intervention and stimulation methodology. This was the first use of a robotics intervention technique in the Tengiz field. It was also the first horizontal well drilled and completed into the target reservoir horizon. Intervention challenges included high pressure/high temperature, H2S, well restrictions, drilling muds (with weighting agents), and of course the trajectory of the well with ~ 1,000m lateral section to traverse. The successful outcome was a result of the conceptual engineering, planning and execution of the intervention and stimulation work scope. Formal surface integration test (SIT) was required to identify the best sleeve shifting options, which supported the procedure for the intervention scope. Valued lessons learned and best practices specific to the completion design, tractor deployment and stimulation strategy were gained through the testing and implementation scopes that will be utilized for future similar projects.
Geosteering a Well in Considerable Structural and Stratigraphic Uncertainties Environment, a Case Study from Kazakhstan
Authors: Mukanov Yerlan , Chzhen Igor , Tagirov Anzor , Kulbayev Askhat , Kurmanbayev Yerkin , Zaripov Nurlan , Zhumabayev Assylbek , Makhambetov Aman , Nemushchenko Danil , Fedorov Anton , Ostapenko Ivan , Dmitriev Boris , Skorokhodov Damir 
Published: November 2022

Abstract
Horizontal drilling enables field development with less wells and smaller environmental footprint, reducing drawdown, increasing production and sweep area. Despite these advantages, horizontal drilling is not widespread in Kazakhstan, possibly due to limited information and limited knowledge of oil companies on available technologies and services that allow to manage geological risks related to horizontal drilling. The authors discuss an example showcasing geosteering with stratigraphic approach, more than one offset well and conventional non-azimuthal resistivity inversion to determine distance to boundary.
Comparison and Optimization of the Various Stimulation Methods: Case Study of Aryskum and Karabulak Fields
Authors: Abdrazakov Dmitriy , Kudalsha Aimurat , Mukanov Adil , Kassenov Duman 
Published: November 2022

Abstract
A comprehensive study of about 200 production stimulation treatments in carbonate and sandstone formations of Karabulak and Aryskum brownfields was performed. The stimulation methods analyzed in this study are propped fracturing, acid fracturing, matrix acidizing with different fluids (both in carbonates and in sandstones), ultrasound treatments, and thermobarochemical treatments. The analysis consists of literature review, modeling of actual treatments in advanced fracturing simulation and matrix treatment simulation, and modeling of alternative schedules and fluids. The quick semiquantitative laboratory method of scales analysis is suggested as part of the study. As a result of the study, the key factors in the production decrease after propped fracturing are revealed; the reasons for the inefficiency of some matrix treatments are explained; and the mechanism of acid fracturing in the given layers is explained and suggestions are provided. In addition, some rare production enhancement-related methods (ultrasound and thermobarochemical treatments) are discussed. An overall table of production stimulation methods is provided, and it can be applied for any fields with similar characteristics.
Oil and Gas Production Management: New Challenges and Solutions
Authors: Polyanskiy Sergey , Yudin Evgeny , Slabetsky Andrey , Smirnov Nikita , Andrianova Alla 
Published: November 2022

Abstract
The organization of the management of an oil and gas producing enterprise has not experienced major changes over the past few decades. At the same time, extractive enterprises face numerous problems and challenges:
- Deteriorating stock quality, oil price volatility and volatility of market in general,
These problems are accompanied by a decrease in the efficiency of production: an increase in the water content of the stock, an increase in the number of downtime and complications on the stock, the appearance of unproductive lifting-costs
All this leads to a drop in the economic efficiency of asset development.
Current challenges, such as flexible production management, its economic efficiency, deterioration of the structure and quality of the resource base, the need for system-based linking of a large amount of additional information about the field on the one hand and a huge variety of calculation and digital tools on the other, dictate the need for an integrated transformation of the principles of production management of an oil and gas producing enterprise.
We offer you to familiarize yourself with the approach to the organization of oil and gas production management based on an effective process model and integrated digital solutions, the purpose of which is to optimize the operation of the field and ensure the growth of free cash flow from production. (Figure 1)
Modeling Sand Transportation in Wells Under Different Multiphase Flow Conditions
Authors: Bakyt Nursultan , Zhang Hong-Quan , Zhu Haiwen 
Published: November 2022

Abstract
Sand particles can be produced from reservoirs along with oil, water, and gas in the petroleum industry. Particles can cause serious flow assurance issues, blocking a fluid path and causing fluctuations in oil and gas production and transportation system. Studies have been conducted to identify critical particle transport velocity in horizontal stratified flow. However, very little has been done to identify critical particle transport velocity for different inclination angles and flow patterns in the oil and gas production system. In this paper, two mechanistic and three empirical models are selected, modified, developed, and presented for stratified, slug, bubbly, dispersed bubble, and annular flow patterns. A model for particle transport in gas production well is also presented. Zhang et al. (2003) unified gas-liquid pipe flow model is applied to cover all inclination angles to determine flow pattern, liquid holdup, and other flow conditions.
Particle transport in a production system is controlled by many parameters like fluid properties (liquid and gas densities, liquid and gas viscosities), sand particle properties (density, size, concentration, angle of repose, sphericity), well geometry (pipe diameter, roughness and inclination angle), and fluid flow (flow pattern, superficial liquid and gas velocities, liquid holdup, water cut). The effect of each parameter on the critical particle transport velocity is analyzed to find the most important ones. The evaluations are validated by comparing with the previous work and experiments. However, this model validation part is not covered in this paper.
Gas-Steam Composite Stimulation: A Strategy for a Heavy Oil Reservoir with High Water Cut in Kazakhstan
Authors: Yi Leihao , Guo Erpeng , Hua Xin , Zhu Aijun , Wang Chunxi , Guan Wenlong , Wang Yuexi , Zheng Xiantao , Zhao Yu 
Published: November 2022

Abstract
North Buzachi field is structurally located in the western part of Ustyurt Basin on the edge of Caspian Sea in Kazakhstan. It's a heavy oil reservoir with viscosity nearly 400 mPa·s at 33°C. After nearly 20 years of cold-water flooding, the oil production has fallen sharply. Low sweep efficiency and high water cut come to be the main severe challenges at this stage. Ways to improve efficiency and productivity need to be tried and evaluated.
Water shut off tests, polymer flooding and adjusting perforations have been tried, but with little success. Thermal enhanced oil recovery (EOR) methods generally are effective options and cyclic steam stimulation (CSS) was considered. But the high-water saturation and water cut make CSS get rapid economic decline after 1 or 2 cycle. Therefore, the feasibility of Gas-Steam Composite Stimulation (GSCS) on this field is studied and evaluated. This paper shows the prospect of GSCS in this reservoir by studying flow mechanisms and numerical simulation analysis.
Gas-Steam Composite is a mixture of steam, carbon dioxide and nitrogen, which is produced based on a high-pressure jet combustion mechanism. The mixed components are simultaneously injected into the formation at the same pressure and temperature. GSCS has been tried in other similar oil fields (Mortuk oil field in Kazakhstan) before, and the actual production results are better than predicted. The application prediction of North Buzachi field was based on the previous theory and experience. During the GSCS progress, gas overlap occurs underground, resulting in secondary gas cap drive and higher reservoir pressure. Along with other synergistic effects, the oil rate can theoretically increase to 4-5 times of water flooding in North Buzachi field. By the results of numerical simulation, the upper residual oil was swept and the sweep efficiency increase from 14% to 40%. The daily oil production per well grows from the initial 3.5 t/d to 15 t/d. Compared with the final recovery of 12% by water flooding, the recovery may reach 33.4% after 7 cycles of GSCS. Meanwhile, the water cut declines from 97% to 50% and the average cyclic oil-steam ratio reaches 4.24.
Economical evaluation shows that cost per ton of oil can be reduced by 24%. With the remarkable increase in production, more economic benefits can be achieved with GSCS technology. This study not only lays the groundwork for future pilot of GSCS in this field, but also provides a significant reference for the development of similar heavy oil reservoirs.
Auto-Adaptation of a Pilot Well with the Use of Special Options for Hydrodynamic Modeling and the Results of Stationary and Non-Stationary Modeling of Gas-Liquid Flow inside the Well During PLT on COI
Authors: Varavva Artem , Yamaletdinov Ayrat , Apasov Renat , Badgutdinov Ruslan , Samolovov Dmitriy 
Published: November 2022

Abstract
Fields X and Y are large gas condensate fields located on the Yamal Peninsula. The fields have a multi-layer structure, at field X, it is planned to bring into development 15 formations combined into 5 development targets, at field B – 18 formations combined into 10 development targets. Separate development targets include up to 6 formations penetrated with horizontal wells. In 2021, 4 horizontal and multilateral pilot commercial development wells were drilled at the fields previously studied only with exploratory wells in 1970-1990, which helped specify the petrophysical, conceptual, geological, fluid, and reservoir simulation model of the field. The new data helped make important investment decisions and switch the project to the Implement stage. During the creation and history matching of the reservoir simulation models of these fields, the small amount of actual data and the existing significant uncertainties in the initial data required to perform multivariant calculations and integrate all field studies (results of flow testing, gas condensate studies, downhole pressure and temperature readings, as well as sludge-and-water monitor readings obtained during downhole logging with coiled tubing) to determine the unknown parameters of the penetrated formations, the share of inflow from them and to narrow down the existing ranges of uncertainties. This work helped specify the RSM – the core of forecast production profiles that formed the basis of decisions on the construction of infrastructure facilities and drilling of additional wells to meet gas production obligations in 2025-2028.
Challenges in Original Oil-In-Place Estimation: Selection of the Best Method for a Field with Non-Uniform Geological Parameters
Authors: Magomadov Ismail , Balhasan Saad , Khalifa Shakier , Awad Mohammed , Yaqoob Saad 
Published: November 2022

Abstract
Accurate original oil in place (OOIP) estimation is a serious industry concern, not only due to the economic issues but also the further field life and success of the development. The uncertainty surrounding the EE-Pool resource size is due to the unique values of the reservoir areas and net pay. This uncertainty in the reservoir area and net pay has also affected the estimated reserves, resulting in wrongly predicted reservoir potential. In order to reduce technical and economic risks associated with the uncertainty of EE-Pool, a data analytics approach applying different methods of OOIP determination techniques was used. EE-Pool contains a heavy amount of data: production data, PVT data, pressure data, well testing data, rock properties data, and geological data. The value of OOIP from the Material Balance Equation (Straight-Line method) was estimated at 100-million stock tank barrels of oil (MMSTB) for both areas and has been determined as a reference value. Compared with the reference value of OOIP, the volumetric method demonstrated the worst result with 63-% error and 63 MMSTB. While the Monte Carlo Simulation combined with Crystal Ball provided the most optimistic results with 9.1-% error and 9.1 MMSTB of oil.
Defining the Fracturing of Carbonate Reservoirs After Multistage Hydraulic Fracturing
Authors: Isaev Anatoliy Andreevich , Takhautdinov Rustem Shafagatovich , Yunusov Irek Miyassarovich , Novikov Maxim Gennadievich , Malykhin Vladimir Ivanovich 
Published: November 2022

Abstract
Hydraulic fracturing is fundamental to optimizing the development of carbonate reservoirs at fields on the western slope of the South Tatar arch in the Republic of Tatarstan. The importance of hydraulic fracturing is becoming increasingly decisive for the exploration of oil fields as the total scope of hydraulic fracturing is increasing and, consequently, the share of man-made fracturing is also increasing. The paper proposes a solution to the problem of obtaining reliable data on the nature of newly formed conducting structures and the seepage flows of formation fluids during the development of producing formations, faced by oil and gas field operators. The article also provides the analysis results of the properties of a man-made fracturing and their spatial propagation, triggered by multistage fracturing (MSHF) in horizontal well ends. The studies revealed that increased volume of proppant injection leads to an expansion of fracture's dimensions, the length being more and the height much less, while the intensity of microseismic emission is correlated with the proppant flow rate. In the process of hydraulic fracture formation, concurrent activation of the existing natural fractures occurs. Increasing the injection volume leads to greater spatial coverage of the reactivation area of existing fractures. Based on the concept of critically stressed state of the rock massif, the obtained network of natural fracturing has been schematized. The identified fractures can be grouped into fracture systems with conditional kinematics according to the Coulomb-Anderson model as reverse faults of northwest extension with the azimuth of 146.79° (326.79°), as normal faults based on azimuth of HF fractures, as strike-slip faults of northeast and west-northwest extension with azimuths of 24° (204°) and 95 (275°), respectively. The obtained results mostly confirm the common nature of the spatial variation, the causes of its occurrence, and progression of a field of fractures Besides, to increase the efficiency of well operation the technology of gas evacuation from annular space of the well and its partial utilization by means of KOGS compressor unit was applied at the wells under examination (3292 and 3294).