bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Field Subsurface Integrity: Performance Analysis of Glass Reinforced Epoxy Tubing Completion at High H2S Wells at Offshore Caspian Sea
Authors: Fablillah Wan Mohd 
Published: October 2017

Abstract
As the BHQ-field matures, sustaining well productivity throughout its lifespan requires an essential need to focus on the field's well subsurface integrity. Wells in BHQ that were completed with Glass Reinforced Epoxy (GRE) tubing have been undergoing a unique and targeted monitoring program for the past few years, parallel to the objective to understand the performance of well integrity of the BHQ-field wells as a whole, and GRE tubing at high H2S wells in particular.
The main challenge is related to H2S production as the field is producing around 100 - 500 ppm of H2S. During the well design stage where reference was made to the reservoir data obtained from a series of appraisal wells, the field development plan has concluded that the wells’ tubing is to be coated with GRE. The trim and sealing elements of the wellhead and Christmas tree were also made compatible to H2S. However, irregularities can still be observed at the surface apparatus during the production phase. In order to avoid more serious integrity issues, diagnostic surveys and logging were performed.
The result from the field monitoring activities together with existing reservoir data were then combined and analyzed. The result from the analysis has significantly contributed towards an understanding of GRE tubing performance and behavior at high H2S wells. Logging data of a calliper log ran at few wells with a one-year gap indicated that the corrosion did not appear to be present. However, it could be observed that the wellhead and Christmas tree sealing element made from a certain type of component is not compatible. The result from the analysis also has become important data for investment comparison for well development and production teams, between GRE and other types of completion tubing, such as 13-chrome and Super 13- chrome, for future project's reference. On top of this, the effectiveness of the well integrity program at BHQ-field, such as 6- monthly wellhead preventive maintenance, actuators and choke maintenance and annulus pressure diagnostic in relation to production sustainability and overall assurance of health and safety aspects of the field operation, can be concluded as meeting the standard with minor improvement.
This paper will provide the analysis on GRE tubing performance at gas wells with high H2S production. The analysis will present the data on GRE tubing compatibility with a harsh environment. It also allows the investment comparison to be made with other types of completion tubing. This paper also will provide the process flow in determining the effectiveness of the well integrity program and process safety program at gas wells with H2S production in the Caspian region.
Maximum Production and Safe Injection Through Cruise Control of Producers and Injectors
Authors: Aasheim Robert , Kittilsen Pål , Fjalestad Kjetil , Idsø Einar Skavland , Løvik Ingvild , Fredriksen Morten 
Published: October 2017

Abstract
Process disturbances may cause reduction in production as the necessary margins to process constraints need to take peak values into account. If the process disturbances can be suppressed, it is possible to operate closer to constraints resulting in higher production.
For both injection and production wells, process disturbance rejection is typically achieved with automatic choke control, which is also beneficial for efficiently achieving changing target values. Good control requires accurate and up-to-date measurements. For cases where no reliable physical sensor is available, robust soft sensor design is a key element in the well control solution.
The process disturbances caused by natural fluctuations of the underlying process require frequent adjustments of the well chokes to maintain key parameters at their desired values. If wells are choked to ensure operation within given constraints, it is normally beneficial to implement automatic choke control since this enables operation closer to these constraints. The control target may also be to track a calculated downhole pressure trajectory during well restart. A smooth restart is important for some wells to avoid excessive sand production. In addition, automatic actions can be taken to reduce the risk of safety issues.
This paper presents field experience as perceived by a control engineer from applying automatic choke control to a large number of water injectors to stabilize the downhole injection pressure or injection rate and application of automatic control for production chokes to control downhole pressure. During restarts of production wells, the downhole pressure follows a pressure trajectory set point to minimize pressure fluctuations to avoid excessive sand production. Exchanging manual infrequent choke manipulations with automatic control to keep the process close to the true, physical constraints, enables safe and optimal production.
Influence of Auto-Fracturing Phenomenon on Injection Well Work Regulation
Authors: Ostapchuk D. , Sintsov I. , Balin V. 
Published: October 2017

Abstract
Currently, a significant quantity of oil fields all over the world are developed with reservoir pressure maintanance mechanisms.
It is worth noting that sometimes water is injected into a reservoir with pressure, which is higher than the rock pressure. Such condition causes technogenic autofracture opening in productive layer. The autofracture is not strengthened with a proppant, so its geometrical size changes with the change of bottomhole pressure. And this feature leads to some difficulties with injection well work regulation.
An attempt to explain the reasons of ineffective well operations (bottomhole treatment and outflow profile alignment) on several fields of West Siberia was an occation for these studies. We found a considerable number of examples on these fields, where well operations had opposite results than were expected. So, we have hypothesized the causal link existence between holding ineffective well operation and the presence of autofracture in this injection well. For this aim, first of all, we describe the algorithm for autufracture detection in injection wells with the help of Bourdet diagnostic plots (which are used in well test interpretation) in conjunction with field data. Then, we checked our hypothesis by studying a statistic correlation between well operations with opposite result and autofracture presence. Finally, we show an explanation how opposite results of well operations in injectors with autofracture can be easily explained. The reason is rather obvious, but this phenomenon have never been described before: all the matter is in ratio between bottomhole pressure and pressure of autofracturing before and after well operation.
Based on these results, we made a clear conclusion about the necessity of considering possibility of autofracture appearance in injection wells. Also we will give some recommendations about work regulation for injection well with such feature.
Nuclear Attributes Selection and Utilization to Address ACG Late Field Development Challenges
Authors: Alkhasov Emin , Han Xiaogang , Zett Adrian 
Published: October 2017

Abstract
The late stage development of ACG field poses new challenges that can be addressed through completion technologies associated with new or improved methods of surveillance using Multidetector Pulsed Neutron (MDPN) instrumentation.
In this paper we will describe the techniques developed and deployed to address specific well and reservoir challenges. The topics will include: –Evaluate the quality of the initial fill and subsequent changes to various types of proppant with stand-alone and time lapse logging for Open Hole Gravel Pack completions–Identification of scale depositing behind the screens–Monitoring the gas cap movement and sweep efficiency in difficult environments (large casing in holes enlarged by reamer, heavy mud in borehole,)
The nuclear modelling has a key role in the early planning stage, enabling the selection of appropriate instruments and acquisition modes. This will reduce the interpretation uncertainty, and minimise the rig time and production deferment. Coupling MDPN measurements with innovative non-radioactive tracer doped gravel, enable a more efficient and accurate reservoir and well surveillance in Open Hole Gravel Pack Completions. The interpretational techniques combine the measured data with specific models of nuclear attributes benchmarked in yard tests that replicate some of ACG completions. Close quality control of the data during acquisition and proper communication with logging vendor is the key in to proper answers.
Using multiple nuclear attributes leads towards a more unique solution in such complex environments. The approach taken along with the results from seven wells will be presented and discussed in detail.
Application of Distributed Acoustic Sensing DAS Technology in Identification and Remediation of Sand Producing Zones in OHGP Completion
Authors: Sadigov T. , Thiruvenkatanathan P. , Sheydayev A. 
Published: October 2017

Abstract
Sand production remains a key technical challenge in the ACG (Azeri-Chirag-Gunashli) field as the target formation is comprised of weakly consolidated sandstone. Although sand control completions (such as open hole gravel pack) are used to limit sand entry into the well, water breakthrough, increased fines production, high flux across completed intervals amongst other factors may negatively impact on their effectiveness as well as stability of reservoir rocks, resulting in high sand production, consequently requiring choking back of wells. This, at times, leads to significant production deferrals, which are attributed to the impact on entire production system: completion, wellbore, chokes, flow lines and production vessels. Therefore, improving techniques and developing technologies for downhole diagnostic and remediation to restore production will be of value throughout the ACG field life. An effective remediation requires an understanding of the sand entry points. Over the last 24 months, BP has developed a new real-time technology solution that employs novel signal processing techniques using Distributed Acoustic Sensing (DAS) systems to detect sand entry points along the wellbore during production. The technology solution has been employed to the interpretation of over 30 conducted surveys to identify sand entry zones in real time. In some instances, the results have also been used to inform targeted remediation using expandable patches.
This paper summarizes the results from some of the DAS sand detection surveillance data acquired (in integration with other relevant dataset) and its use in remediation of compromised completion intervals. The authors will also share examples of drawdown optimization and risk management of wells with sand production based on acquired DAS data. This paper will cover a few examples of DAS survey data acquired both for wells with pre-installed fibre (25 wells) and those without it where the technology was deployed via wireline intervention (5 wells). The application of DAS technology in ACG has provided substantial value to date (both in terms of production and safety) and has much more value to be realized as the technology continues to mature.
Optimization of Recovery Using Intelligent Completions in Intelligent Fields
Authors: Abdullayev Azer , Kedia Rachit , Urakov Askar , Temizel Cenk 
Published: October 2017

Abstract
Throughout the previous few years, substantial attention has been paid to the usage of smart well technologies to help improve recovery, particularly with technological improvements and an increasing expanse of opportunities in more challenging and rewarding assets. The fundamental focus has been to propose and develop workflows that integrate several surface/subsurface subprocesses and automate the entire workflow. In cases where significant investment is made to complete smart wells with remotely controlled inflow control valves (ICV), reservoir sweep becomes decisive when evaluating the efficient recovery.
Application of this technology has been challenging because it is a modern concept. This study showcases the effective application of ICVs within intelligently completed fields to satisfy the objective function by augmenting reservoir sweep and oil recovery. In this study, a commercial full-physics numerical reservoir simulator has been used to evaluate a synthetic simulation model mimicking a realistic reservoir with waterflood. The wells are installed with smart well completions using ICVs that are controlled by conditional statements called procedures. The decision parameters varied to determine if the level of ICV opening within producer wells is water-cut and well-injection rates. Then, the cumulative oil recovery is used as an objective function to increase the maximum oil recovery.
The ultimate goal is to reach the highest net present value (NPV) through having higher cumulative oil production values with the lower water injection and water production rates. The relatively high expenditure linked with installing intelligent completions within wells drive further the importance to apply and study the advantages of this technology on multiple, diverse cases coupled with specifically planned workflows.
Recent studies have shown that a robust reservoir management plan along with an effective application of ICVs within intelligently completed fields can augment reservoir sweep and oil recovery. The results of the study demonstrated the positive impact when using ICVs on NPVs calculated compared to the base case where traditional completions have been used. It is also shown that, without a robust reservoir management plan, the use of intelligent completions might not always be successful. Augmenting the performance of the reservoirs, in addition to looking at the individual well performance, forms the crux of a sound reservoir management plan.
This study, therefore, examines the big picture by following a field-wide approach rather than focusing solely on individual or near-well performance. The core of this study is to provide a framework of effective integration of data from leading performance indicators attributing to intelligent well completions, with the ultimate goal of optimizing the reservoir recovery.
Best Practices in Calibration of Integrated Production Modeling for Tengiz Field
Authors: Onbergenov Ulan , Aitkazin Mirkhat , Tang Yula , Svyatov Aidar , Kairbekov Amirbek 
Published: October 2017

Abstract
Petroleum Experts Integrated Production Modeling (IPM) toolkit is widely used in Tengizchevroil (TCO) for short and long term production forecasting in the Tengiz field. The short and long term models each have their own strategic focus. The short term IPM model is used for day-to-day management of field activities to ensure business plan production volumes are delivered. The long term IPM model is used to manage base business and optimize scenarios for various future development projects. The short term IPM model is validated and history matched continuously and forms the basis of the long term model to meet business objectives.
Because of the complexity of the Tengiz gathering system, close collaboration among multiple teams, systematic updates and continuous improvement of the model is required. It is also important to have an accurate temperature prediction across the entire field network to conduct flow assurance studies, optimize plant inlet temperatures and maximize plant throughput.
As a result of the implemented calibration efforts, the model predicts field production rates within 1% of the actual field performance. The model provides more granularity and higher confidence in ensuring that the plant can produce at its maximum capacity when wells are shut-in for surveillance activities, pipeline repairs and meter station (MS) shutdowns for gathering line repairs. In a long term perspective, it's crucial to have an accurate model to plan MS shutdowns for upgrades and the successful startup of major capital projects.
This paper describes model improvement initiatives, the best practices and lessons learned during the calibration process of the complex IPM model. A structured workflow for the calibration of the IPM model is also provided. The calibration steps are described in detail with relevant examples throughout the paper. This workflow can be used by IPM practitioners in other fields to construct and maintain integrated production system models.
Unlocking the Development of Absheron Gas Condensate Field through an Integrated Asset Work and Modeling
Authors: Marmier R. , Decroux B. , Paran M.-A. , Raurich S. , Akhundov H. , Esor E. 
Published: October 2017

Abstract
Reservoir to surface Integrated Asset Modeling (IAM) is a cross-functional simulation, monitoring and decision tool. It captures the complex interactions all along the production / injection system of an oil or gas development. It is a powerful tool to maximize the value of an asset from the development phase to the end of the production period. This paper describes the successful work achieved for unlocking the challenging development of Absheron deep offshore gas condensate field through an integrated asset work and modeling.
The IAM has been the result of a multi-disciplinary and collaborative work where each disciplines, namely reservoir, well, network and surface process engineering, provided their inputs. A fully compositional fluid modeling was required to capture the challenges of such a long gas export production line with stringent thermal requirements due to the paraffinic content of the produced condensate, impacting at first order both plateau duration and economics. During all the pre-FEED engineering, attention was given to ensure consistency and synchronization between the IAM and the progress of the design work performed in parallel by each disciplines. Many sensitivity calculations on development parameters have been performed to quantify the impact of the geosciences uncertainties and other design parameters to define the optimum combination of production facility design, operating philosophy and monitoring strategy.
The first phase has been a screening with different production network design parameters associated to the base case reservoir model, namely the pipeline insulation and the arrival pressure.
The second phase has been to test the robustness of the proposed design towards reservoir base case uncertain parameters such as the well overall exchange coefficient, reservoir temperature, water break-through, fluid modeling and gas-water contact. The third phase has been to test the robustness of the proposed design towards low and high reservoir cases. All along these phases, many iterations and collaborative work between reservoir, well, network and process engineers occurred, all centered around the IAM offering the possibility to evaluate the production profiles associated to different designs assumptions while the different disciplines eventually performed more advanced "stand-alone" studies to further assess specific technical points.
The work performed for Absheron development highlights the benefits of integrated asset work and modeling to enable an economic development scheme robust towards uncertainties (petrophysical, structural modeling, water break-through…) and therefore not over designed
Improving Reservoir Conformance Control Through Next-Generation Supramolecular Gelators and Their Use in Hydraulic Fracturing
Authors: Yegin Cengiz , Temizel Cenk , Yegin Yagmur , Agharzayeva Zinyat , Sari Mufrettin Murat , Jia Bao , Urakov Askar 
Published: October 2017

Abstract
Recent developments in horizontal drilling and fracking technology have had a crucial role in increased shale gas and oil production in the U.S and the world. Natural resources kept in low permeability reservoirs, namely shale formations, can be recovered by a well-designed hydraulic fracturing process. Optimization of production and efficiency in hydraulic fracturing significantly depend on properties and efficiency of fracturing fluids. This work presents a pH-responsive supramolecular assembly solution system synthesized via complexation of maleic acid with an amino-amide in an aqueous media. Our previous studies on this system have verified its significant potential to be used as displacement fluids in EOR due to its highly adjustable and reversible viscosity behavior. Herein, we investigated its potential as fracturing fluids considering its mobility control, and proppant transfer and settling capacities.
The main protocol is: the viscosity of injected supramolecular solution is set to an optimum (moderate to high) value enabling both enhanced proppant transport and easy injection of the fluid, and then reduced with an external pH stimulus near fissures for proppant sedimentation and easy flowback. Flow-sweep experiments of the fracturing fluid using the supramolecular solution and proppants (silica sand) revealed that for only a 2wt.% concentration, viscosity could be varied nearly 1600 times by changing pH from ~4 to ~8, reversibly. Moreover, sedimentation studies showed that the settling rate of the silica proppants descended five orders of magnitude by increasing pH from 4 to 8 in a reversible fashion. On the other hand, our lab-scale preliminary experiments showed that these supramolecular assembly solutions both have reversible pH-responsive properties and high salinity and temperature tolerance. While degradation and breakage are observed in polymer viscosity modifiers used in hydraulic fracturing under high temperatures and sudden extreme shear stresses, supramolecular assembly solutions have ability to disassemble and re-assemble. Use of supramolecular solutions in fracturing fluids can also prevents reduction of permeability of reservoirs arising from polymer blockage during flowback period. Therefore, supramolecular solutions can be thought as self-healing polymer solutions.
Briefly, supramolecular assembly solution system described here has a potential to be a novel type fracturing fluid due to its pH-tunable and reversible viscosity and proppant transfer capacity, high salt tolerance, self-healing property, and sustainability and environmental friendliness.