bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Completion Clean-Up Design and Execution for Shah Deniz Stage 2 Development Project
Authors: Mollayev E. , Javaid M. , Gill G. , Johnston M. , Schwarz F. , Dobrynin Y. , Erkan T. , Elghamry M. , Huseynov R. , Runchey M. , Gros T. 
Published: October 2017

Abstract
This paper describes the design and operational performance of the 15 kpsi Shah Deniz Stage 2 completion clean-up surface process equipment which has been designed to ensure solid/debris-free gas/condensate production at first gas in 2018. This project demonstrates a genuine step change in the design and operation of well testing and clean-up systems. It takes process safety to a new level whilst simultaneously reducing the overall equipment footprint, compared to traditional well test systems.
The design brief for this project included a requirement to safely process and correctly dispose of all fluids produced from completed SD II production wells. This included formation hydrocarbons at elevated flow rates, completion fluids and residual drilling fluids. The surface package also had to fit within the rig well test deck and individual skid weights kept within the rigs crane capacity. As a result, the decision was made to design, engineer and manufacture a customized set of equipment. Additionally, an upgraded data acquisition system was required to process the increased volume of data as well as provide the required level of system monitoring and control. An enhanced process shut down system was also needed in order to implement the shut down philosophy demanded by the projects process safety policies.
The SD II completion installation schedule, in which twelve wells were completed back to back, called for a semi permanent installation of the surface process package. This provided the opportunity to implement many of the design upgrades described in this paper. As a result of these upgrades operations have been carried out in a safer, more controlled and efficient manner, whilst simultaneously maintaining full compliance with all industry and company specific regulations. The two central elements to this operational efficiency was due to the surface equipment operating well within its design envelope, even at high flow rates, and the data acquisition system enabling the entire process system to be fully monitored and controlled. This enhanced process control enabled emerging risks to be rapidly detected and mitigated prior to any detrimental escalation.
This paper discusses the various challenges posed by the project and the ways in which these were mitigated and overcome. Many of these design solutions can be applied to future high flow rate surface systems.
Delivering Russia's Longest Offshore ERD Open-Hole Gravel Pack Well
Authors: Kumar Manish , Bouches Vincent , Shmakov Alexander , Plotnikov Alexey 
Published: October 2017

Abstract
Sakhanlin Energy Investment Company operates 3 offshore platforms in the Sea of Okhotsk east of Sakhalin Island in the Russian Ferderation. The Piltun Astokhskoye oil field is being developed by the PA-A and PA-B integrated drilling and production platforms. The Lunskoye gas field is being developed from the LUN-A integrated drilling and production platforms. The Lunskoye field is being developed using ERD technology and the sandface completions have transitioned from oriented perforations to open hole gravel packs. Executing these openhole gravel packs in these challenging extended-reach wells is quite challenging. And this is further complicated by the harsh climatic conditions around the island. Sakhalin Energy recently completed two of these wells successfully which are delivering over 400 MMscf/d of sand-free gas to the island's liquefied natural gas plant.
First Hybrid Bit Experience for Balaxany and Fasila Formations in Azerbaijan Region
Authors: Kravchenko Andrey , Mikhailov Vladimir , Sheraliyev Meiirzhan 
Published: October 2017

Abstract
The drilling activity challenges in Azerbaijan are usually associated with the Pereriv (also known as the Fasila) formation due to highly abrasive tight sandstones and high vibrations while drilling, especially in deeper zones. Optimizing the rate of penetration (ROP) while maintaining toolface control is a challenge in the region when trying to reduce cost and maximize margins for customers. One past solution included a choice of premium milled-tooth roller-cone bits with multiple trips due to the bearing and seal life of the cones. Polycrystalline diamond compact (PDC) bits were another solution that yielded marginal ROP improvement when not sliding and balling issues were not present. After a nearly year-long preplanning phase, the customer drilled these formations with a hybrid drill bit and tripled the previous ROP without any noticeable drop entering Fasila. Throughout the section the weight on bit (WOB) was limited due to very high cuttings volume from the increased ROP. Overall, the first hybrid bit run replaced two roller-cone bits, and the second deeper hybrid bit run replaced 2-½ roller-cone bits. Sliding was deployed during drilling with no issues, maintaining toolface control. Hole quality improvements were noted during successful wiper trips and casing.
Even though hybrid bits were previously used in the Caspian Sea region (Kazakhstan side), the two included case studies represent the first experience of hybrid bit technology used in Azerbaijan accounting for multiple achievements and potential break-through performance for future projects.
Impact of Thin Oil-Rim to the Development of Gas-Condensate Fields in the South Caspian Basin
Authors: Mammadov Tahir , Javadzade Rovshan , Abdullayev Vugar 
Published: October 2017

Abstract
It is common to observe thin oil zones with limited thickness between the gas cap and the bottom water in gas-condensate reservoirs. The existence of thin oil zone must be taken into account in the development plan of the gas-condensate reservoirs, as this nuance has a significant influence on the recovery factor of reservoirs.
The objective of this paper is to understand the influence of thin oil zone to the development of the gas-condensate reservoirs in the South Caspian Basin. A numerical 3D hydrodynamic reservoir model has been built and sensitivity analysis has been performed for different reservoir properties. The results of the cumulative gas and condensate production were studied in terms of the reservoir total recovery factor to show the impact of different reservoir properties.
According to the results, it is crucial to study and understand the thin oil zone in gas-condensate reservoirs, as the presence of thin oil zone increases the reservoir recovery. Even not produced separately, the thin oil zone has positive influence on the development of gas-condensate reservoirs.
Additionally, the sensitivity study shows that the properties such as the reservoir absolute permeability, the thickness of the oil zone, the aquifer strength, the critical gas saturation, the critical water saturation and the residual condensate saturation have an essential influence on the final results even if the thin oil zone exist in the gas-condensate reservoirs. From the reults, it can be inferred that, although the thin oil zone has a positive impact on the gas-condensate reservoir recovery, the above mentioned properties also must be investigated and taken into account.
Investigation of an Analytical Solution for Spontaneous Imbibition to Effectively Estimate Special Core Analysis SCAL Properties
Authors: Khan Abdul Saboor , Alyafei Nayef 
Published: October 2017

Abstract
A newly derived solution for capillary dominated flow is investigated by comparing it to experimental and numerical simulation data of spontaneous imbibition in water-wet rocks. The analytical solution allows for the estimation of relative permeability and capillary pressure data for rocks.
To validate the analytical solution, it is evaluated for published data for co-current and counter-current spontaneous imbibition on four water wet rock samples. The published experimental saturation data for these rocks is scaled by the square root of time, and the result is compared with the corresponding analytical solution. To further investigate the validity of the analytical solution, a 1-D numerical simulation model is created for the spontaneous imbibition experimental setup and run with identical conditions.
Experimental data for spontaneous imbibition, when scaled by the square root of time, converges approximately to a single curve. It is therefore evident that the analytical solution is valid for water-wet rocks. Saturation function curves that are obtained from the analytical solution are then used as inputs to 1-D numerical models of cores with properties and dimensions that are identical to the experiments. The saturation profiles obtained from numerical modelling results, when scaled by the square root of time, display good quantitative agreement with the analytical solution, with deviations between the two sets of results varying in the range of 1 – 6% for the four data sets.
The analytical solution is very promising in that it can be used as a basis to extract otherwise time consuming Special Core Analysis (SCAL) properties by carrying out relatively fast and simple spontaneous imbibition experiments. The procedure introduced can also be adopted as a complement to the existing SCAL experiments to verify results.
Comprehensive Study of the Charlson Oil Field, Williston Basin, ND
Authors: Anderson Jordan , Rice Joseph , Said Abdulkadir , Mehrer Cody , Ostadhassan Mehdi , Alexeyev Alan 
Published: October 2017

Abstract
The objective of this study is to perform geological, petrophysical, geomechanical, decline curve, and economic analyses; a numerical reservoir simulation; and lastly a well and facility design for the Mission Canyon Formation of the Charlson Field of North Dakota. Essentially, the goal is to perform a broad start-to-finish analysis of the Charlson Field, while also determining the feasibility of a different development plan than what was used. It is important to note that the study is on a look-back basis as the field is mature and depleted.
Geological and petrophysical analyses were performed using available well log and core data. A complete geomechanical and wellbore stability study was done as well. The well and facility design consists of casing, cementing, and separator design. These designs were established using historical designs, literature, and calculations. Numerical reservoir simulation was performed using simulation software and data obtained from the geological and petrophysical analysis. Decline curve analysis was performed using field production data. Lastly, economic analysis used historical oil prices, well cost data, and reservoir simulation production data.
The results of the geological and petrophysical analyses helped to better understand the lithology, geology, and petrology of the Charlson Field. These results refined the area of study to areas of high production capability and obtained characteristics to use later in the study. The geomechanical analysis provided a Mechanical Earth Model, and a mud weight window that could be used to create drilling mud, and casing designs. The well design portion delivered casing and cement designs, that along with drilling mud designs created using the mud weight window, could have possibly helped alleviate casing failures seen in the field. The separator design provided an optimized separator system and operational conditions. The numerical reservoir simulation and decline curve analysis both provided production estimates for a development plan. The economic analysis was performed to determine the economic feasibility of the proposed development plan. The study determined that drilling another well in 1984 during the infill drilling of a separate well could have generated ~$18 Million net present value, with a rate of return of 18%. In addition, the well design could have helped alleviate casing failures in the Charlson Field. With the above conclusions, it is easy to see that even with the limited data used in this project, it is imperative to manage data for optimal results in any development.
Improving TCO Well Integrity Process through Successful Deployment of Well Integrity Portal
Authors: Tursinbayeva Damira , Kuznetsov llya , Sadyrbakiyev Renat , Yeskayir Batima , Barragan Daniel 
Published: October 2017

Abstract
Historical events and recognition of the potential hazards caused by the adverse production environment (such as high pressure and high H2S) of existing wells in Tengiz and Korolev fields has led Tengizchevroil (TCO) to always be focused on risk mitigation and safety procedure and fully aware of the criticality of well integrity. Thus, appropriate and robust processes were developed early in the field development as a precationary step to mitigate the risk of potential well failure events. These processes later evolutioned into fully documented, automated, robust TCO Well Integrity process, which meets both industry API RP standards, Chevron Process Safety guidance and Kazakhstan’s Industrial Safety Laws.
However, increasing number of TCO wells increases the possibility of potential risks considering that Well Integrity Process (WIP) requires a lot of manual work and data review by engineers. In order to improve reliability of the process, the team has developed and successfully launched the Well Integrity Portal (WIP) dashboard to automate routine duties. As a result, fully deployed WIP has provided engineers with full set of interactive dashboard functionality, which includes, but not limited to: live data/metrics visualization, automated workflows for alert/notification, non-conformance report generation, etc. This paper will provide overview of TCO’s Well Integrity program and details on how Well Integrity Portal has been developed and deployed to ensure continuous benefit to the company and incident-free operation.
Building a Trend for Chemical Remediation Jobs in ACG
Authors: Allahverdiyev Parviz , Anguiano Juan , Gathman Brad , Agayev Farid 
Published: October 2017

Abstract
High gas and sand production along with productivity decline are amongst some common well management challenges in oil producers of Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan sector of the Caspian Sea. This paper will focus on trials in the region in deploying chemical treatments to tackle excessive gas and sand production in unconsolidated reservoirs.
Sand production can disrupt normal operations at topside facilities, cause well management challenges and well productivity impairment. Successful sand shut-off (SSO) also means reduction of some financial and safety impacts for the business.
Reservoir pressure support through secondary recovery mechanisms is an important component for delivering production targets of ACG field. With continuation of gas injection for reservoir pressure support, the Gas Oil Contact (GOC) can move closer to the producers at times resulting in well management challenges due to rising well Gas Oil Ratios (GORs). Upon free gas breakthrough (GBT), well drawdowns are actively restricted to prevent further growth in gas rate and subsequent acceleration of oil rate decline. For some wells, an effective Gas Shut-Off (GSO) would mean immediate production impact associated with increased drawdown available potential. In others, the driver for GSO is the need to minimize total facility gas production volumes to avoid immediate or future production deferrals due to gas facility constraints. In sand producing wells, successful GSO interventions provide the secondary benefit of reducing risk of flow-line and choke erosion that arise during well life.
Various mechanical and chemical techniques have been assessed and deployed in trials to mitigate high gas and sand production in ACG over the last four years. The objective of this paper is to share the candidate selection methodology and results of the chemical GSO and SSO trials implemented to date. In addition to this overview, the surveillance data supporting the candidate selection process will be presented with pre and post intervention well parameters to demonstrate the impact of the shut-off techniques along with longevity.
Experience of Acidizing Injection Wells for Enhanced Oil Recovery at the Zhetybai Field Kazakhstan
Authors: Suleimanov Baghir A. , Guseynova Naida I. , Rzayeva Sabina C. , Tulesheva Gulnar D. 
Published: October 2017

Abstract
The article discusses the results of local acid treatment of key wells situated in the selected area of the deposit. This technique allows not only to recover well injection capacity, but also to increase the area sweep efficiency both according to the formation thickness and its strike, which helps to increase oil recovery.The method for effectiveness evaluation of the deposit stimulation technique has been proposed. It is based on calculation of formation system hydrodynamic characteristics with the account of well interference. Based on the geophysical well logging data (GWL), the area sweep efficiency is determined in accordance with the formation area and thickness.The proposed method has been implemented on the basis of the data of the Zhetybai (Kazakhstan) deposit.
Using DTS on Gas Injectors to Monitor Flow Distribution
Authors: Seyidov Murad , Nurmammadov Emil , Mammadli Ilkin 
Published: October 2017

Abstract
Understanding flow distribution across the well is significant piece of surveillance and important input for decisions related to well and reservoir management. Companies face significant challenges to monitor it. DTS is one of the technologies to mitigate challenges and minimize surveillance costs. As part of surveillance plan of ACG Res02 pilot program, DTS has been installed on a newly drilled gas injector (GI1). Significant learnings have been acquired from this trial.
GI1 was drilled as part of a pilot program on Res02 reservoir, which is currently at early stages of development. It has been equipped with number of surveillance tools as well as DTS across the whole sand interval. DTS profile on injector was generated based on difference in temperature of injected fluid and reservoir. Specifically in ACG environment injected gas temperature is higher than that of reservoir. Hence, warming effect was expected on the zones taking injected gas where due to heterogeneous nature of the reservoir, uneven injection into sublayers can occur.
DTS enabled real-time monitoring of how temperature profiles change across the sands and revealed uneven distribution of injected gas across the reservoir. When gas injection rate was increased, clear change in temperature profiles was observed – injection was getting into the lower sands as well. Moreover, shut-in DTS traces helped more accurately identify gas taking sands based on coolback effect. As injected gas temperature is higher than the reservoir temperature, temperature profile will be cooling back towards the geothermal gradient once the well is shut-in. This can be considered as warmback analogue that can be seen in water injector temperature logs.
Introducing DTS on gas injectors is both cost efficient and provides continuous flow monitoring, which enables real time decision making. Since it is dealing with only one fluid phase (gas) it provides more certainty. Information gathered from DTS will have a strong impact on field development planning, pressure maintenance, as well as smart completion designs.
Water Breakthrough Effect on Well Productivity and Skin Factor Change
Authors: Huseynov Rufat , Babayev Javid , Sadikoglu Kasim , Azizov Ehtiram , Ismayilova Farida 
Published: October 2017

Abstract
Azeri-Chirag-Gunashli (ACG) is the world class, giant offshore oil field located in Azerbaijan sector of Caspian Sea with secondary drive mechanism as water and gas injection. The productivity index of comingled wells is high and average initial rate reaches 20mbd. As soon as water breaks through at producer from one of sand units, skin factor increases which leads to oil productivity reduction. Several causes of skin factor increase were investigated such as; scaling, fines migration, other mechanical damages, emulsion, relative permeability change etc. The impact of each mechanism should be well understood for better business decisions.
Impact of relative permeability change due to water breakthrough (WBT)was investigated in this paper via analytical and numerical well test methods. Impact of fluid migration from higher pressuresed sand into lower one through wellbore was also investigated. The results are aligned with the actual field observations.
Diagnosing Multiphase Flow Regime in Multilayered Reservoir by Distributed Temperature Sensor Data
Authors: Mammadli Nijat , Malikov Haji , Suleymanov Arif 
Published: October 2017

Abstract
The article discusses the possibility of diagnosing the multiphase flow regime in the multilayered reservoir by using DTS (distributed temperature sensing) data.
The analysis of the theoretical and actual curves of temperature build up and drawdown, corresponding to the main modes of multiphase flow of formation fluids are given in this article.
The possibility of diagnosis of the multiphase flow regime is found based on analysis and interpretation of the characteristics of temperature build-up and drawdown in different intervals of the reservoir at the start of the well or shut in, or by changing opening degree of the choke.
The possibility of diagnosing water breakthrough (WBT) intervals, based on the analysis of the changes in temperature curves according to the DTS is shown.
For a more detailed analysis and interpretation of temperature change curves in the wells more frequent DTS measurements are required. It is necessary to conduct a comparative analysis of the dynamics of the temperature and pressure redistribution in the productive zone of the well, with the results of geophysical logging, production logging, taking samples of reservoir fluids from different zones of productive layers in the multilayered reservoir, moisture metering, hydrometry and others.