bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation-Optimization Model for Dokan Reservoir System Operation
Authors: Othman Luqman , Ibrahim Dr. Hekmat 
Published: October 2017

Reservoir operation system is the essential part of water resources management, and each reservoir has a special policy for operation. Simulation and optimization are two different techniques for the operating process of any reservoir. Combined simulation-optimization (S-O) model as a new technique in recent years to minimize the deficit in hydropower generation and irrigation demand has been developed for Dokan reservoir system in Kurdistan Region, Iraq. The model combines the Simulink and genetic algorithm (GA) as techniques for simulation and optimization respectively. For comparison, one traditional simulation model based on the standard operating policy (SOP) and two optimization models using nonlinear programming (NLP) and discrete differential dynamic programming (DDDP) optimization methods was developed. In the present study, three performance evaluation criteria, namely; reliability, resiliency and vulnerability have been used for comparing and evaluating the developed models.
The proposed models were run over a period of 54 years using monthly time step interval, i.e. 648 months starting from Jan-1958 to Dec-2011. The results reveal that the SOP model (Model-I) has serious deficit events in minimum downstream demands, although, it has a higher reliability in the irrigation demand (0.94). In addition, the other models; NLP, DDDP and S-O by considering weight factors and almost have the same reliability, 0.90, 0.90 and 0.91 respectively. Furthermore, the results show a low resilience for NLP model and a high vulnerability for S-O modelwhich causes higher severity of failure events. Moreover, for the operation period from 1995 to 2011, the annual productions of hydropower are 1280, 1339, 1344and 1296 MW by increasing of 24.9, 30.64, 31.16 and 26.46 % more than the actual hydropower production (1025 MW) for SOP, NLP, DDDP and S-O models respectively.
Finally, the conclusions present that the DDDP optimization model provides high reliability as well as more power generation at the same time. The model can be more easily applied to solve the nonlinear and multi objective problems with less computational time.
Correlation of Consistency and Compressibility Properties of Soils in Sulaimani City
Authors: Rashed Dr. Kamal , Salih Dr. Nihad , Abdalla Tavga 
Published: October 2017

Compressibility properties of soils are one of the most important properties in geotechnical engineering because of the needs for a safe and economic design for structures foundations. Compressibility parameters are used in the settlement calculations. Direct determination of both compression index (C c ) and recompression index (C r ) are costly, cumbersome and consuming time. These indices require undisturbed soil samples depending on a lot of experiences in the field works. Due to those factors, useful correlations were developed previously to predict compressibility properties. In the current study, the correlations conducted by using consistency properties, which are easy measurable variables. In this study, single (nonlinear equation) and multiple empirical equations were proposed to predict compressibility indices (C c and C r ) as a function of index properties (LL, PL, PI and SL). The equations were predicted using sixty undisturbed fine-grained soil samples collected from twelve different locations at Sulaimani City in Kurdistan Region of Iraq. Statistical analysis has been carried out by using SPSS software (Version 24). Coefficient of determination (R 2 ) and root minimum square error were used as an evaluation criterion in order to check the calculated empirical correlations equations. The statistical analysis showed that there is a direct and positive correlation among the selected parameters. In addition, accurate correlations were obtained in comparison to the existing relationships.
Restoring Production Naturally in a Challenging Well - Using ACTive-Q DTS, DFLO Technology & Stimulation, SA Field - North Kuwait Case
Authors: Elaila Shamseldin Z. , Al-Dousari Mohamad A. , Barki Jassim , Chetri Hom B. , Slama Hedi 
Published: October 2017

Abstract
Inflow control devices techniques started to be widely used in North Kuwait filed (NK) where it delivers a valuable mean of managing production and simultaneously control the water cut and gas breakthrough. Drawbacks, such as port plugging and limited intervention options to the reservoir are also dealt with as a risk factor. In North Kuwait, some wells started to show production decline. Finding the root cause and identifying that it is related to formation damage or ICD-completion issue is necessary to define and plan for proper intervention in order to restore the productivity.
One of the key and initial confirmations required is the ICD completion’s integrity, the assurance of the ICD ports to be open and contributing to production. This can be identified by either PLT or ILT, needing multiple activities and interventions to decide for remedial actions and to design a proper well intervention. Real-time coiled tubing profiling tool is a coiled tubing conveyed tool that enables real time injection profiling that helps in real time in confirming the port status if open or plugged. Meanwhile the CT itself during the same run can be utilized for the planned treatment to stimulate or remove any asphaltene/scale deposit.
In Sabriya Field, Well-0X, a real-time coiled tubing profiling tool was utilized in ICD completion to deliver ILT profile in real time mode. Coiled tubing profiling is a powerful tool that can be run easily with CTU. It reduces the risks of using H-PLT/H-ILT in HZ wells. The tool shows a good match during the injection profile with DTS profile. The identification of the cease to flow root cause was easily identified (the quantitative injection profile across ICD compartments shows the compartments of low injection and the compartments of high injection rate). It was planned to perforate the ICD completion based on the initial findings from the previous intervention that will be resulted in losing ICD integrity and main function.
Thereafter, based on the finding, a trial of wax and asphalting treatment was pumped to enhance the well productivity before moving forward for ICD perf option. Hence, in single run, an injection profile to identify the plan and injection of treatment followed by a second injection profile to confirm status of the ports were conducted which helped to restore the well productivity thereby multiple interventions and deferred production.
Based on the results, the right corrective action was selected avoiding ICD perforation thus selecting the right decision that helped in restoring the well productivity and saving costs while maintaining ICD integrity and main function. The well was successively put back onto production with a normal flowing rate. The planned and executed job has helped to restore production with best practice. This practice and work flow have been accepted to be implemented in similar wells in future.
Spectral Noise Logging SNL as a Key Tool to Identify Water Source in a Deviated Production Well on ESP
Authors: Ali Ahmed Al-Rujaibah , Bhagavatula Ramkamal , Prosvirkin Sergey 
Published: October 2017

Abstract
Well RAx1 is a 55-deg deviated oil well completed as ESP producer in the sandstone formation. Current production was 1,300 BLPD with 95% water cut. Open-hole logs indicated a clear oil zone whereas well performance was contrary to the log response. The challenge was to identify the water source and subsequently plan for remedial well workover.
As part of the investigative process, it was necessary to flow the well and make logging runs to measure both temperature and pressure, as well as zonal production criteria to gain a full understanding of the production issues. Conventional production logging tools cannot determine flow behind pipe. There was a need for specialised and sophisticated technology to identify flow behind pipe and to accurately determine the true source of water in this well. A combination of spectral noise logging (SNL) and high precision thermometer (HPT) tool was deployed as a solution to this challenge.
After logging data analysis, clear evidence of communication was seen with water zones above and below the pay zones. This communication was observed only in flowing conditions with noise range in the spectrum of 0.1 – 30 kHz. The shut-in survey did not show any noise response from above or below the pay zones. Shut-in SNL captured noises caused by the fluid moving within the pay zone with a frequency 6.5-16 kHz. Static and flowing pressures of 3710.8 psi and 2,880.6 psi were recorded at the top of pay zone. The gas-oil contact depth was determined at 1,900 ft from static temperature gradient. The production profile was analysed in detail by modelling the temperature profile. This method is based on construction of the actual temperature profile for the entire well to detect convective temperature perturbations due to wellbore heat transfer by flow. From the temperature modelling results, 41% of the fluid contribution was from the pay zone, 5% from above and the rest from below.
The application of SNL tool was successful in providing qualitative assessment of flow behind pipe. Its use could be extended to identifying fluid encroachment from below oil-water contact or lateral breakthroughs in nearby wells. It aids in better understanding of fluid movement near the wellbore enabling better well diagnosis, including leak detection behind multiple barriers and checking for swell packers integrity in ICD completions etc., which cannot be decisively determined by conventional production logging tools.
Significant Reduction in OPEX by Improving Efficiency of GC Test Facility
Authors: Al-Shammari B.. 
Published: October 2017

Abstract
Kuwait Oil Company is currently producing around 3.2 MMBOPD out of which the major share of 1.7MMBOPD is produced by South East Kuwait asset (SEK). SEK has 14 Gathering centers (GC) with an average of 100 flowing completion per GC. It has always been a challenge to test individual completion to get correct rate and other well test parameters not only to calculate the exact production potential of the GC but also to back allocate the rates to the reserves produced. Since long time the prevailing practice in SEK was to test individual wells in the GC using GC test separator and as well as testing wells by portable test units. The rates obtained from above two methods were used to be compared with the expected calculated rates based on PI calculations and other reservoir properties. The GC test is done by diverting the well manually to GC test separator which does not incur any additional cost to the company compared to portable test which done by service company hired by KOC well surveillance department with associated operational cost.
The need of portable test were justified because the old GC test facilities occasionally were giving inaccurate results and the results were used to be rejected by Field development engineers resulting in a repeat test request of portable test. This was not only taking long time to get the correct data but also add extra operational cost component to the company.
In 2014-15 it was proposed to upgrade the GC well test facilities with state of the art technology. The upgrade was completed in November15 and the GC test facilities became operationally available in Dec 15. In spite of initial difficulties and inaccuracies in the tests results the GC test units were finally accepted in Jan16 to be accurate for all the GC’s after satisfactory comparison between the portable and GC tests results.
There has been a great cost saving by the above in operating expenditure (OPEX) of SEK well surveillance. The number of portable tests has been reduced to 200 from the earlier average number of 1400 plus per year resulting a direct saving of around USD 3.6 million
How Private Cloud Solution Go Beyond the Conventional Infrastructure Solution for Jurassic Kuwait Digital Integrated Field
Authors: Al-Mai N.. , Najem N.. , Al-Shammari R.. , Leeri A.. , Robert H.. , Divakaran D.. , Farid A.. , Johnston B.. , Arzhilovskiy S.. 
Published: October 2017

Abstract
Kuwait Digital Integrated Field (KwIDF Jurassic) is a complex field located in the North Kuwait. As with many other Digital oil field projects the IT challenges are numerous. The current infrastructure is based on physical servers and resource handling is challenging. Require integrated infrastructure solution to build new workflow demands and to cater large amounts of real-time data being retrieved wells and facility sources.
Adoption of Cloud computing for oil and gas is increasing over the last few years, this document primarily focus on Private Cloud strategy for KwIDF Jurassic. A comprehensive assessment was done with the KOC IT Stakeholders, during the in assessment phase captured all the challenges and we ensure the Security is prime requirement accessing the KwIDF applications, One of the prominent challenges was to have offered in cloud computing is the centralized data-handling requirements, the solution creates such a change in technological as well as new workflows Validation tests on the KOC recommended hardware was successfully completed. This delivers the learning and experiences for cloud road map and strategy creation for KOC IT,
Based on the validation proof of concept results, the solution private cloud implementation framework was designed primarily on Virtual Desktop Infrastructure (VDI). Includes Kernel-Based Virtual Machine (KVM) virtualization technologies, the VDI Solution will integrate with KOC Application cluster, the VDI Solution provides anytime, anywhere access to KwIDF applications with improved security. The Cloud and Virtualization solution will improve the application delivery system with high performance for the provide solution and enhance operational and business outcomes. Adding private cloud platform can take the project to a new level of business improvement and enhance operational performance.
The potential benefit of implementing secure cloud includes benefits like high-resource utilization and IT resource management for operations team in Datacenter.. Providing high availability and disaster recovery, also allow user self-service provisioning templates with rapid delivery of virtual machines, the whole solution is aligned with KOC CITG business strategy.
Utilizing Entire LWD Dataset from Horizontal Wells in Thin Bed Siltyshale Layers of BGSU to Extract Maximum Value
Authors: Kotecha R. K. , Al-Zaabi R. Z. , Al-Sabea S , Ali F.. , Al-Rabah A. A. , Bu-Qurais A. F , Haryono R.. , Haider E.. , Altemeemi B.. , Alharbi A.. 
Published: October 2017

AbstractDrilling in thin reservoirs is challenging task. But with easy pockets gone the reservoirs left are less than 5 to 10 feet and it becomes difficult to steer well exclusively in the sweet spot or sand in thin payzone. It is this reservoir which offer task to drill horizontal well and produce maximum where otherwise it would be difficult to produce even 200-300bopd from this thin layer of silty shales. Moreover the thin beds are like appearing or vanishing as we drill ahead due to facies change. This needs complete attention till the well reaches Target Depth (TD). Even a small fault of sub-seismic nature of 2 feet throw can offset the well from the sweet zone. But with advanced logging tools used in two wells helps to understand the nature of lithology and its productivity. Best application of this tools are in silty shales in Burgan Sands Upper (BGSU) which generally show high GR and often this leads to misjudgment of well not being in sweet spot.Logging While Drilling (LWD) logs and inversion was used whether the well is in productive zone or not. The LWD tools now have Azimuthal GR, density and resistivity. This gives a holistic picture of the lithology in the roof side or the bottom side of the lateral section. The wells under discussion were drilled with such advanced version of distance to boundary tool.After well was steered till TD, the data was processed by Petro-physicist to indicate possible payzone to decide completion. But due to high GR which is often prevalent in Burgan Sand Upper (BGSU) the entire well bore was not getting classified as potential payzone. But after looking the inversion and all LWD data sets it was conveyed that the Inflow Control Device (ICD) can be lowered for entire well bore length. As an outcome advanced ICD was lowered also against high GR zones which otherwise were not getting classified as potential payzone, and well were completed. The well was put on production starting with 1300 BOPD on 32″ choke and still after 18 months continues to produce. PLT results show that the zones indicating high GR and with poor log properties were also contributing oil. The paper discusses these wells and utilization of complete data set acquired at time of drilling and taking completion decision accordingly. The output of data of LWD has been fully utilized to complete the well successfully and given the confidence of doing so in other wells. In fact this experience was used in another similar looking well with unfavorable parameters and successfully completed.
Sour Gas Occurrences in Kuwait and the Mitigation Challenge
Authors: Hofmann A.. , Al-Khamiss A.. , Andriyany R.. , Taqi H.. , Malekzadeh R.. , Strien W. van 
Published: October 2017

AbstractNumerous oil and gas reservoirs in Kuwait are suffering from H2S contaminations. The H2S concentrations in the affected reservoirs vary significantly from low ppm ranges up to 40%. The H2S concentration levels are related to the generation processes. The high H2S concentrations observed in the Lower Jurassic reservoirs can be related to the TSR process. The dominant H2S generation process in the Upper Jurassic and Lower Cretaceous reservoirs is the thermal cracking of the organic sulphur compounds (OSC) occurring in the Najmah and Sargjelu source rocks. The H2S contaminations observed in the Cretaceous reservoirs show indications of multiple H2S sources. The bulk of the H2S in these reservoirs is generated in situ by the BSR process. In some fields clear indications for H2S migrated from deeper horizons e.g. via faults are observed.H2S contaminations are also observed at the top site facilities at various stages of the production process. The source for those contaminations is only partly in the subsurface. In several cases a distinct increase of the H2S contaminations of the fluids on its way from the reservoir well to the processesing facilities is observed.New sampling and analytical technologies tailored to the H2S problematic have been developed, which support the selection of the appropriate mitigation or remediation strategy. The utilization of modern low cost DNA sequencing technologies for the analysis of the bacteria and archea species provide essential information for the design of appropriate chemical cocktails for the mitigation.Reservoir modeling and forecast technologies have been developed to predict the development of the H2S concentrations in a reservoir. However, for a reliable forecast - irrespective which modeling system or tool is applied - the understanding of the H2S generation process is essential. Furthermore good quality and reliable H2S measurements are mandatory for the history match.The mitigation and remediation of H2S is a major cost factor in the field development and operations. Field souring i.e. the increase of the H2S concentration during field life is the worst case scenario, which could cause major investments to assure field production. Not only the costs for the H2S treatment materials (e.g. biocides, nitrate) but also the investments in corrosion inhibitors, H2S resistant pipes, valves, filters, and the upgrade of the processing facilities have a large financial impact. Furthermore HSE related measures and required safety and monitoring systems are increasing substantially the operation costs.In view of KOC's ambitions to increase the oil production by 20% by 2020 and the subsequently expected increase of H2S production, a contry-wide coordination of the treatment concepts for the H2S could improve the efficiency of the mitigation operations and could potentially reduce the investments and operation costs related to the sour gas issue.
Advances in Spacer Technologies for Improved Zonal Isolation Results in Challenging Deep Deviated HPHT Wells Containing Heavy Oil Based Muds
Authors: Brandl Andreas , Doan Angela Anh , Alegria Adriana Estela 
Published: October 2017

Abstract
Insufficient wellbore cleaning prior the cementing job is considered to be the biggest single factor leading to poor zonal isolation results. A mud-spacer-cement program with suitable fluid needs to be carefully engineered for the given wellbore conditions to improve cementing quality. We discuss optimum spacer design features which are critical for the successful cementation of deep deviated HPHT wells containing heavy oil based muds and review a simulated scenario. Advanced lab test methodologies beyond industry standards are utilized to model more accurately the given complex downhole conditions.
A simulated &gt;20,000 ft highly deviated wellbore was characterized by HPHT bottomhole conditions and the rheological performance of the cement spacer was critical to job success. The well needed a stable cement spacer that would not settle-out on the low side of the &gt;14,000 ft horizontal section, which would potentially put the well at risk. The 16.17 ppg mud required an even higher-density spacer system to clean it effectively. But conventional high-density spacer systems only compound the settling challenge and the well's anticipated bottomhole temperature of 350°F was expected to compromise any additives that might stabilize the fluid systems. Therefore a lab study about spacer stability was performed using a HPHT rheometer and the dynamic settling test – an industry standard which was actually established for cement slurries but not for spacer fluids. We found that a conventional spacer failed at 350°F by showing a rapid decline in rheology to almost zero viscosity and severe settling. To overcome the settling issue, provide stability, and maintain a sufficiently high rheology profile at given 350°F, we re-designed the spacer by using a modified biopolymer which shows a delayed hydration and viscosification over time successfully counteracting the destructive thermal effects.
The mud-spacer-cement fluid train was eventually optimized showing good fluid compatibility and maintaining within the narrow, 1.6 ppg margin that separated the pore pressure from the fracture gradient. The cementing job was designed using an advanced fluid displacement software, which predicted high mud removal efficiency under these challenging conditions. In order to enable proper mud displacement, the Friction Hierarchy—a key design factor that is often difficult to achieve under the extreme HPHT well conditions—was achieved with the new spacer concept.