bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Implementation of High-Rate Pinpoint Technology in an Extremely Challenging Multilateral Well: Successful Lessons Learned From Tight Carbonate - Minagish Field, West Kuwait
Authors: Mofti Mohamed , Sierra Leopoldo , Alboueshi Alaeldin Saad , Patra Milan , Ali Sulaiman , Abu-Eida Abdullah , Matar Saad , Al-Shemali Nasser , Al-Azmi Nasser 
Published: October 2019

Abstract
A significant challenge in the tight Mishrif oil reservoir of the Minagish field is ensuring hydrocarbon flow through the complex and highly damage-susceptible carbonate intervals. In recent years, field development strategies have begun to prioritize multilateral well technology over vertical and deviated wells because of the advantages of maximized reservoir contact, higher production rates, and improved access to reserves (hydrocarbon in place). The downside of most unconventional multilateral wells is that laterals are open hole, completed with much complexity, and pose challenges for effective acid stimulation because of poor acid distribution over the long interval.
The Mishrif formation in the Minagish field in west Kuwait is a challenging tight carbonate with poor reservoir quality, relatively low pressure, and no external pressure support. The stimulation methodology was highly modified as fit-for-purpose to address the unique challenges of multilateral well operations, formation technical difficulties, high-stakes economics, and untapped potential from these formations. Furthermore, to enhance production, the lateral lengths of the well were designed as an optimum solution. To maximize and sustain hydrocarbon flow and production, a multiple stage acid pinpoint treatment was performed by dividing the wellbore into small intervals, based on petrophysical and reservoir properties evaluations; a high-rate pinpoint technique was used for both laterals individually. The selected sections were individually acid stimulated, and the inflow contribution from the entire productive sections of both laterals was maximized with a highly reliable and effective multistage continuous operation.
The post-operation well test and production data show a significant production increase; long-term production data show a sustained production increase, stable pump intake pressure, and low water cut, demonstrating the success of the pinpoint technique as an optimized solution for the first multilateral well. The success of this well stimulation method has enabled the use of this pinpoint-squeeze as the best technique for all horizontal wells in this field.
This paper summarizes the design processes, challenges encountered, production response, and lessons learned from applying this pinpoint acidizing technique. It can be considered as a potential approach for addressing stimulation challenges in similar tight carbonate reservoir conditions in other fields.
Well Cementing with Elastic Properties Cement Stone and Liner Rotation is the Key to the Successful Development of Hard-to-Recover or Tight Oil Reserves from Bazhenov Formation
Authors: Susliakov Ivan , Shevchuk Taras , Alekseev Alexey , Dryaba Alexey , Alyakin Andrey , Sekachev Oleg 
Published: October 2019

Abstract
Significant progress in technologies development of well completion and stimulation allowed to involve in the development of reserves which 10 years ago were considered unpromising due to the too low reservoir permeability. Particularly significant influence of modern achievements on shale beds, which were previously not seriously considered as possible objects for hydrocarbon production. The success of shale oil production in the United States inspires oil companies around the world to study the possibility for the development of such objects.
On the territory of the Russian Federation is perhaps the largest area of shale formation of the world – Bazhenov formation. In 2016, PJSC Gazprom Neft for the first time for the Bazhenov formation implemented a full cycle of construction of a horizontal well with a Multi-Stage Fracturing, which on the level of the applied technological solutions is not inferior to the American analogues used in the United States for shale oil production. The length of the horizontal section of the well was more than 1000 m; the 114 mm liner OD was run in and cemented. The cementing operation was carried out with liner rotation, and the cement blend itself contained specially selected additives which were designed to ensure high resistance of the cement stone to the damaging effects from multi-stage fracturing.
The experience in drilling and cementing, completion and production operation of the well turned out to be positive, and in 2018, a pilot project started drilling a whole series of horizontal wells with multi-stage fracturing at two well sites. During the implementation of the project was found a stable relationship between the well production and the efficiency of fracturing, which is significantly affected by the isolation the anulus.
Formation Pressure While Drilling Technology: Game Changer in Drilling Overpressured Reservoirs
Authors: Ramatullayev Samat , Makhmotov Akikat , Zhabagenov Muratbek , Cesari Michele , Torrisi Salvatore , Capone Graziano , Ferrari Federica 
Published: October 2019

Abstract
The Formation Pressure While Drilling (FPWD) has been widely used in the industry in different downhole environments for formation evaluation purposes – pressure gradients, fluid identification and contacts, and reservoir pressure management. However, there is a niche application of this tool that no wireline formation tester could provide – real-time drilling optimization.
Drilling reservoirs with abnormal high pressure is a complex process. The overpressure can cause a well to blowout or become uncontrollable during drilling leading to catastrophic outcome if too low mud weight is selected. On the other hand, too high mud weight can lead to lost circulation, decrease in rate of penetration, stuck pipe and most importantly it can damage the formation hindering productivity of the well. The monitoring of actual pore pressures in real-time with FPWD tool is critical to make proper mud weight adjustments, rather than relying on inferred pore pressure from either predictive models or offset wells.
The paper discusses a case study of application of FPWD in a well drilled in a fault block never drilled before, where pore pressure data from wells located in nearby blocks indicated that there may be abnormal high-pressure zones. Pressure measurements were performed while drilling after every 100 m upon reaching a certain depth. Since downhole BHA included gamma ray and resistivity tools along with FPWD tool, the combination of this data was used to select the intervals to be tested.
The study shows how real-time pore pressure measurements helped to adjust mud weight from 1.45 to 1.80 sg to avoid the risk of formation fluid influx into the well, optimize drilling operations and, based on the acquired results, an operator decided on the total depth (TD) of the well. Since pretests were performed at targeted layers, formation pressure and mobility data also aided in reservoir characterization.
The paper presents the first successful application of FPWD technology in Russia and Caspian region for drilling optimization purposes in overpressured reservoirs. Real-time data availability allowed making quick operational decisions to safely drill the well until planned TD.
Reservoir Value-Engineering for West Siberian Oil Fields
Authors: Naugolnov Mikhail , Murtazin Rustam 
Published: October 2019

Abstract
A new reservoir engineering analytic tool is presented that provides express oil residual reserves estimation, classification and following express waterflooding optimization for large West Siberian brownfields. Results are compared with full field 3d simulation models, and field pilot approbations.
The approach is based on residual reserves estimation and classification. Reserves classification is done with author's approach for reservoir complexity index (RCI) evaluation. The complexity of reservoir depends on three main parameters: permeability (1), fluid and rock properties: wettability, relative permeability, saturation and viscosity (2), and reservoir heterogeneity, calculated as a function of sweep efficiency and pumped pore volumes (3). All reserves are divided by RCI into several classes with the most economical way of development: sidetracks, re' hydraulic fracturing, treatments and flooding optimization. Waterflooding optimization using capacitance and resistivity model (CRM) considered more carefully as the main way to involve the largest scope of remaining reserves.
The implementation of the new approach based on reserves estimation and classification helps to identify the most attractive zones and to select the most suitable way for development. It also shows values of profitable and unprofitable current remaining reserves. Based on simple capacitance resistive analogue and economic models instrument for waterflooding optimization solves the problems of OPEX reduction, NPV or production maximization in express way. Combined capacitance and OPEX optimization models demonstrate good results on some West Siberian fields and find wells with unproductive injection, unprofitable oil production (due to high watercut and low liquid rate), show zones with high production potential, help to reallocate injection volumes and to involve into development additional amount of oil coupled with economic profit. The injection wells work regime optimization is solved using genetic algorithms based on differential evolution. Results of instrument implementation correspond with 3d simulation model and show nice additional oil production on real field. To summarize, the described approach gives an opportunity to minimize operational expenditures and to improve project economic performance without additional capital expenditures or investments in the terms of low oil prices.
The novelty of the work is in the using of new approach of reservoir complexity index estimation for STOIIP classification and best development methods selection. The novelty is also in integration of RCI, semi analytical physical based waterflooding management methods with hybrid data engineering methods and optimization algorithms. Using of new methods together with economic model provides a responsible tool for solving reservoir cost-engineering problems and increasing of project's value.
The Fracture Characterization and Assessment of Gas Potential with Advanced Formation Tester in Low Permeability Fractured Carbonate Reservoir
Authors: Ramatullayev Samat , Blinov Vlad , Tukhtaev Rustam , Filimonov Anton , Mendybaev Nurhat , Zeybek Murat , Tillyabaev Muzafar , Abidov Khurshid , Gavrilov Alexey , Frik Vladimir 
Published: October 2019

Abstract
Carbonate reservoirs can exhibit heterogeneity in terms of porosity, permeability, fractures, vugs and wettability. This heterogeneity affects well performance, completion and reservoir management development decisions. Although extensive logs are run for the petrophysical evaluations in these formations, the use of advanced wireline formation testers (WFTs) can greatly aid in reservoir description. WFT not only can identify hydrocarbon bearing formations but also plays a vital role in fracture characterization and calibration of fracture models.
Advanced petrophysical logs were used to identify potential pay intervals, while high resolution image logs to delineate fractured zones and static fracture parameters, such as dip, azimuth and aperture. It has been shown that fracture dynamic properties, such as conductivity, can be quantified via pressure transient analysis using wireline formation tester in addition to fluid analysis. In this paper, WFT data was used to understand the pressure behavior of naturally fractured reservoir containing a network of discrete finite-conductivity fractures.
The study presents results obtained from advanced logging suite that was run to characterize complex low porosity and low permeability carbonate reservoir where natural fractures provide primary pathways of fluid flow. Advanced wireline formation tester with straddle packer and fluid analyzer were used to test potential intervals. Two out of several intervals were enabled to flow, identifying mobile gas. The pressure transient response confirmed the complexity of reservoir and dominant contribution to flow regimes from fractures in these two intervals. Dynamic fracture properties were characterized through pressure transient analysis and were integrated into fracture model. On the other hand, flow could not be established in number of other intervals indicating tight matrix and no flow contribution from fractures, leading to calibration of geological models.
The novelty of approach is the use of wireline formation tester not only to measure formation pressure and acquire downhole samples but to characterize dynamic fracture properties to calibrate fracture model.
The Results of the Pilot Works on Well Completion Technologies and Continuous Monitoring on the Example of Extremely Long Horizontal Wells of the Yu. Korchagin Field in the Caspian Sea
Authors: Shtun Segey , Senkov Alexander , Abramenko Oleg , Nukhaev Marat , Mukhametshin Ilkam , Naydenskiy Konstantin , Galimzyanov Artem , Popova Ekaterina 
Published: October 2019

Abstract
This paper presents the experience of LUKOIL-Nizhnevolzhskneft of implementation of various completion designs and continuous monitoring systems for extended-reach horizontal wells. The article describes the evolution from stand alone sand control screens and passive inflow control devices to the introduction of multi-zone advanced smart wells with inductive coupling. In addition, the work presents experience with fiber-optic distributed temperature measuring systems and chemical tracers.
Since 2010, There are a lot of advanced technologies for well completion and continuous monitoring has been introduced at the field named after Yu. Korchagin, including nozzle-based inflow control device (ICD), autonomous ICD, ICD with check valve, sliding couplings, multiposition couplings, interconnected sand screens, fiber optic systems, chemical tracers, hydraulic and electric smart wells. The application of some technologies turned out to be limited in the conditions of the field named after Yu. Korchagin, part of the technologies had limited implementation due to the long length of horizontal wells, and some technologies showed unique benefits and were recommended for further wide implementation.
Pilot projects of some technologies, as well as the use of various completion systems and continuous monitoring systems at the wells of the Yu. Korchagin field, allowed LUKOIL-Nizhnevolzhskneft not only to solve current operation problems, but also to select optimum technologies for usage in the following fields of Caspian shelf.
Optimization of New Well Flowback Process
Authors: Sadyrbakiyev Renat , Neubauer Edward , Skopich Anton , Suleimenov Olzhas , Aitzhanov Abzal 
Published: October 2019

Abstract
New wells were initially cleaned-up directly to the Plant Facilities in Tengiz. The existing facilities were not designed to process well flowback fluids which can contain contaminants, emulsions and solids from drilling and completion fluids. Well flowback operations directly to the process facilities were causing plant upsets and a backlog of wells to be placed on production.
An MRM (Management of Residual Materials) spread was introduced in TCO (Tengizchevroil) in 2016 to clean-up new wells prior to performing a Plant flowback. The MRM unit utilizes an EverGreen Burner that performs fallout free and smokeless combustion of liquid hydrocarbons and residual well materials during well clean-ups.
Cleaning-up new wells using the MRM spread has significantly improved the number of successful Plant flowbacks per year, lessons learned in all phases have been captured and will be shared. However, MRM clean-ups did not always guarantee a problem-free Plant flowback since only qualitative methods were being used to determine when a well had been cleaned-up sufficiently to be routed to the Plant.
To improve the ability to determine a well's readiness for a Plant flowback, new quantitative methods were developed which include continuous sampling and gas-chromatography analysis along with compatibility tests.
This paper will share the best practices and challenges during MRM operations, research details, field trial and results that were achieved after optimization of the flowback process.
APC for Wellhead Chokes to Optimize Plant Performance in Tengiz Field
Authors: Tanzharikov Arman , Cernik Randy , Shantayev Arman 
Published: October 2019

Abstract
Tengizchevroil (TCO) has implemented Advanced Process Control (APC) to automatically control the feed into the plant by adjusting the chokes of selected wells in the field. The automated choke operations are closely monitored and thoroughly discussed during daily Field-Plant interface meetings to confirm overall stability of the plant performance and improvement in plant efficiency. With the use of a dynamic multivariable model-based controller we are now able to predict the demands from the production facility and automatically deliver the exact amount of field production to meet plant's ever-changing production capabilities while minimizing the pressure losses between the field and the operating plant.
The early APC deployments demonstrated the opportunity in delivering highly significant value to TCO. TCO had implemented numerous APC throughout the plants to optimize complicated processes and developed the necessary organizational capability (OC) to implement the Field APC. The Field APC project was the first joint project involving both the field and the plant assets. This APC project demonstrated the "One TCO" approach, with support and buy in from a cross functional team of Automation, Reservoir Management, Process Engineering and Plant Operations personnel.
TCO is now able to automatically react to changes in both the field and plant to deliver the maximum plant capacity at any given moment. Since plant throughput limitations are constantly changing due to changes in ambient temperature, H2S content or gas-oil ratio (GOR) of the inlet feed, etc.; the APC is automatically adjusting the output from the wells to match the inlet requirements of the plants. The solution uses dynamic models to predict constraints and drive operations to an economic optimum while honoring an everchanging set of constraints. The APC allows the plant and field operators to spend more time addressing non-routine problems by automating one of the operator's routine duties.
Workflow of Oil Spill Estimation
Authors: Motaei Eghbal , Yeap May Chen Dharshini , Tewari Raj Deo , Mammadov Elnur , Ruvalcaba Jazael Ballina 
Published: October 2019

Abstract
Blowouts have catastrophic consequences and can potentially occur during any exploration or development projects. The situations that could lead to a blowout are underestimated pore pressure, rapid change in pressure, abnormal pressure or operation complexities such as complete fluid loss and thief zones. Blowouts are the most destructive and dangerous disaster in the oil and gas operations. Apart from causing fatalities and injuries, a blowout also causes ecological and environmental damages. While there is remedial work that can be done to manage the side effect of a blowout, an analysis has to be done to evaluate the extent of the damage. The oil spill analysis has to include all parameters and take into consideration all scenarios which would cater for the remedial work needed to address the aftermath of the blowout.
In this paper, the entire spill process beginning from the reservoir up to the surface is reviewed. The review covers the phenomenon involved in a spill process, the related HSE concerns, remedial work and spill modelling. The initial conditions, boundary conditions, and media transfer functions such as porous media properties, sand face and wellbore geometry are fully captured in the study and is reflected in the workflow. These parameters would affect the plume shape, size and geometry, blowout duration and oil spill volume estimation. The workflow presented in this paper is an effective technique for efficient decision making and remedial work in case of an oil spill resulting from an uncontrolled blowout.
The Results Implementation of a Set of Measures to Enhance the Production Efficiency of High-Viscosity Oil
Authors: Isaev Anatoliy Andreevich , Aliev Mekhrali Mirzali , Takhautdinov Rustem Shafagatovich , Malykhin Vladimir Ivanovich , Sharifullin Almaz Amirzyanovich 
Published: October 2019

Abstract
It was shown in [1] that the directional structure of the wellbore profile is one of the factors complicating the operation of the wells with the PCP units.
It was found that the maximum inclination angle of the well in a certain way reduces the MTBF of the rods. The maximum inclination angles of the wells with the known operating time in millions of cycles (revolutions) that had experienced rod failures have been calculated with the help of dipmeter logs of the group of directional wells.
The analyzed group includes PCP units with the number of pump shaft revolutions: Up to 100 min-1; 100…200 min-1; 200…300 min-1; 300…400 min-1.
Therapeutic drug monitoring of infliximab compared to standard clinical treatment with infliximab: study protocol for a randomised, controlled, open, parallel-group, phase IV study (The NOR-DRUM study)
Authors: Syversen Silje Watterdal , Goll Guro Løvik , Jørgensen Kristin Kaasen , Olsen Inge Christoffer , Sandanger Øystein , Gehin Johanna Elin , Warren David John , Sexton Joseph , Mørk Cato , Jahnsen Jørgen , Kvien Tore Kristian , Bolstad Nils , Haavardsholm Espen A. 
Published: October 2019

Abstract
Background:

Infliximab (INX) and other TNF-inhibitors (TNFi) have revolutionised the treatment of several immune mediated inflammatory diseases. Still, many patients do not respond sufficiently to therapy or loose efficacy over time. The large individual variation in serum drug concentrations on standard doses and the development of anti-drug antibodies are thought to be major reasons for treatment failures. Therapeutic drug monitoring (TDM), an individualised treatment strategy based on systematic assessments of serum drug concentrations, has been proposed as a clinical tool to optimise efficacy of INX treatment. TDM seems reasonable both from a clinical and an economical point of view, but the effectiveness of this treatment strategy has not yet been demonstrated in randomised clinical trials. The NORwegian DRUg Monitoring study (NOR-DRUM) aims to assess the effectiveness of TDM, both with regard to the achievement of remission in patients starting INX treatment (part A) as well as to maintain disease control in patients on INX treatment (part B).

Methods:

The NOR-DRUM study is a randomised, open, controlled, parallel-group, comparative, multi-centre, national, superiority, phase IV study with two separate parts, NOR-DRUM A and NOR-DRUM B. Patients with rheumatoid arthritis, psoriatic arthritis, spondyloarthritis, ulcerative colitis, Crohn’s disease and psoriasis are included. In both study parts participants are randomised 1:1 to either TDM of infliximab (intervention group) or to standard treatment with infliximab without knowledge of drug levels or ADAb status (control group). NOR-DRUM A will include 400 patients starting INX therapy. The primary outcome is remission at 30 weeks. In NOR-DRUM B, 450 patients on maintenance treatment with INX will be included. The primary endpoint is occurrence of disease worsening during the 52 weeks study period.

Discussion:

As the first trial to assess the effectiveness, safety and cost-effectiveness of TDM in patients receiving TNFi for a range of immune mediated inflammatory diseases, we hope that the NOR-DRUM study will contribute to the advancement of evidence based personalised treatment with biological medicines.