bluuebunny/crossref_metadata_2025_split huggingface dataset:
Significant Initiatives for Managing Emergency Response at Drilling Rigs in Remote Areas - Smart Alert System (SAS)
Authors: Al-Shatti Ahmad , Al-Rakdan Abdulwahab , Al-Khaldy Ali 
Published: October 2015

Abstract
Kuwait Oil Company is the premier Oil & Gas Company in the Gulf region involved in exploration and production of oil & gas reserves. The Company is one of the subsidiaries of Kuwait Petroleum Corporation, State of Kuwait. In line with the Company strategy to improve its production capacity from current 3.0 Million BPD to 4.0 Million BPD, the company deployed many on-shore drilling rigs on a fast track basis during past two years. Present Rig Fleet includes 25 deep drilling rigs and 60 development drilling & work over Rigs. The Company has established the HSE Management System and procedures based on the international standards to focus on the health, safety of workers and environmental protection.
Since majority of Rig fleet is deployed in desert remote areas, where there is a challenge in response time during any emergency situation. Various Initiatives and improvements programs were implemented to avoid such emergency at first place, which resulted in enhanced HSE performance especially the LTIFR as well, and in addition, Company has adopted the latest technology called Smart Alert System (SAS) for emergency response especially for drilling rigs working in remote desert areas. This system is based on GPRS, SMS, GPS protocol using GIS map enabled Tablet PCs.
The presentation discusses the experience of Kuwait Oil Company in enhancing the performance overcoming all HSE challenges by implementing various intitative and sharing the best practices adopted for emergency response for Drilling Rigs operated in remote desert areas.
Application of Optimized Particle-Sized Lightweight Cement Technology to Improve Integrity on Surface Casings in Myanmar
Authors: Olutimehin Kunle , Jia Zhang Xua , Voon Eric 
Published: October 2015

Abstract
One of the main challenges of drilling in the Central Andaman Sea offshore Myanmar is the mitigation of overall well integrity risk arising from weak top-hole formations. On a well drilled by one operator, conductor integrity was lost due to cratering and loss circulation while cementing which eventually led to having to re-spud the well. Almost all the offset wells drilled by the operator in the same field experienced losses in the top section interval.
To meet integrity objectives for both exploration and development wells, the cementing strategy in certain cases must consider alternative solutions in addition to conventional Class G cement. In a recent project executed for one operator the cementing philosophy for the entire surface sections therefore had to be fine-tuned to incorporate the proven Optimized particle-sized distribution methodology.
A proprietary coarse material made from glass beads was introduced as part of the slurry design, being used for the first time in Myanmar to further improve cement properties. On the development wells the optimized design called for pumping 10.5ppg High-performance Light-weight cement (HPLWC) lead slurry, together with a standard Class G tail.
To meet operational integrity objectives, planning and risk assessments were put in place by the service company and the cementing programmes were developed to incorporate necessary mitigations against the identified risks. Plans were put in place to handle the implicit logistics requirements. Careful attention was paid to the execution given the downhole pressure sensitivities, all slurries were mixed and pumped with a degree of relative precision.
This paper summarizes the design and implementation of the cementing operation which contributed positively to meeting well integrity objectives. Apart from operational success, expectations which hitherto factored in possibility of top-up jobs were exceeded; for the exploration well the critical zones were covered with good returns to seabed observed on all the cement jobs as monitored by ROV. Hard cement were tagged and drilled out from the shoe track in each case and well operations progressed without any loss of integrity issue.
The paper aims to demonstrate that incorporating technology can help to improve well delivery and reduced lost time. Approximately, 18 cement jobs have been executed on the project - all successfully done. Out of these 4 top-hole cement jobs involved the use of the High-performance Light-weight (HPLWC) technology described in this paper.
A Comprehensive Downhole Capillary Surfactant Injection Screening & Optimisation for Liquid Loaded Gas Wells
Authors: Andrianata Satria , Susanto Agung 
Published: October 2015

Abstract
Depletion of the reservoirs leads to a decrease in field production rate. Wells production rate continue to drop below the minimum critical velocity, at which point the liquid that was previously carried upward by the gas begins to fall back. The produced liquid accumulates in the well creating a static column of liquid, therefore creating a backpressure against formation pressure and reducing production until the well ceases production. Down hole Capillary Surfactant Injection (DCSI) is installed on the wells to overcome the liquid loading symptom by generating foam, thereby reducing the surface tension, lowering the fluid density, and lowering critical rate. This paper discusses the improvement to obtain higher success ratio of DCSI installation project on the observed field. Analysis and improvement is done to improve the success of DCSI installation through a comprehensive wells screening, continuity laboratory test, and field optimisation. The screening including the selection of liquid loaded wells & laboratory test (foam test, pH, and salinity test) were corrected with the actual temperature to obtain an accurate foam performance. Correlation is generated to correct the effect of foam build rate and decay rate against critical parameters. Validating well performances with the results of laboratory tests is conducted by continuously field optimisation. The laboratory test is significantly important to screen DCSI well candidate. Surfactant concentration, temperature, & condensate content are critical variables for foam build up and decay performances. Uncertainty variable and un-matching well performance previously not assessed can be reduced by these improvement steps, thus increasing the success ratio DCSI project. The improvement DCSI screening proposed is used as a reference to start the DCSI project to obtain higher success ratio.
Drill Site Surface Facilities Readiness: Systems Improvement through Use of IT (An Upstream Oil & Gas Company's Approach)
Authors: Nath U. , Phookan J. 
Published: October 2015

Abstract
Getting a drill site ready on time for drilling with the least idle time to its resources (drilling rigs and rig related manpower) was becoming a major constraint to the Company's achieving its annual operational targets. On an average the Company has to drill at least 50 locations in a year. Multiple departments are involved in the entire process of getting a drill site ready for drilling with multiple activities, some independent and some dependant, having to be carried out by the concerned departments before the final objective can be achieved.
It was seen that the existing system of monitoring and reporting of the pre-drilling status of sites was not effective and hence there was an urgent requirement for an IT based on-line monitoring system to be implemented for ease of monitoring, transparency, better review and decision making.
Treating each of the drill sites as a project by itself, which needed to be monitored closely by the use of a system with multiple data input and reporting channels and having the ability to generate various reporting formats meant that there would be multiple projects required to be monitored at any given time.
By implementing an integrated enterprise project management solution having multiple users the Company was able to meet its requirements.
Integrated Static and Dynamic Modelling Workflow for Improved History Matching and Uncertainty Modelling
Authors: Chong E. E. , Wan Mohamad W. N. , Rae S. F. , Lim L. , Flew S. 
Published: October 2015

Abstract
Traditionally, the history matching process is done only on the dynamic model, without any direct update to the geological (or static) model. As a result, geological uncertainties are not fully evaluated in the dynamic model. Non-integration of static and dynamic modelling results in either too much time being spent modelling detailed geological phenomena that have little impact on the dynamic behaviour of the reservoir, or, conversely, important geological and petrophysical parameters being misrepresented or missed out which may have significant impacts on the overall field development strategy.
Ideally, if any updates to static parameters are required as result of history matching in the dynamic model, these changes should be reflected directly in the static reservoir model, thereby ensuring consistency between the static and dynamic models.
In this paper, a workflow is presented where both the static and dynamic modelling software packages are integrated as part of the history matching process. This workflow involves input parameters being adjusted in the geological model directly. Uncertainty analysis tools are used to obtain multiple history-matched models, which results in an order of magnitude increase in speed compared to traditional history-matching processes.
Not only will this methodology result in improved history-matched models with a wider range of production forecasts being captured, but more importantly, it will result in better understanding of the static and dynamic uncertainties and their interdependencies, leading to a more informed decision-making process with regards to overall field development. In addition, this methodology offers a platform where the subsurface professionals involved in reservoir model construction and simulation processes can focus their efforts on improving reservoir characterization and identify areas that require further data acquisition or improvement.
This paper also describes how the workflow was successfully applied to a recently developed, producing and waterflooded oil field in South East Asia, and eventually delivering an optimized reservoir model for reservoir management and a probabilistic approach to production forecasting.
Carbonate Geostopping to Refine Depth Uncertainty Using Borehole Seismic - A Case Study in Vietnam
Authors: Dac T. Nguyen , Sanders M. , Millot P. , Pham The P. , Tomohisa N. , Ryosuke K. 
Published: October 2015

Abstract
Drilling exploration wells always carry increased risk given the lack of offset wells. Once of the main uncertainties usually is the depth prognosis derived from surface seismic depth converted data. The accurate prediction of the depth of top carbonate while drilling carbonate reservoirs is important to avoid losses and well control problems. This can have a significant financial impact. This paper demonstrates the use of innovative look-ahead VSP technology in Vietnam to refine depth prediction of the top of carbonate ahead of the bit for accurate geo-stopping.
An offshore exploration well was being drilled in an area with drilling challenges. This was the first well in the field and lacked offset well velocity information, so there was a high degree of depth uncertainty to the top of the carbonate target from surface seismic interpretations, making drilling operations risky. An intermediate VSP was requested to look for reflections ahead of the intermediate TD using Schlumberger VSI1 tool. The VSP data was acquired in open and cased hole using an air gun cluster as the seismic source.
The drilling program required the casing to be set immediately above the top of the carbonate. By acquiring an intermediate VSP, the depth uncertainty was reduced and the target depth prediction was refined. This was achieved using the look-ahead VSP technique, from which the acoustic impedance and velocity ahead of the bit was estimated. This was combined with time-depth from the VSP data over the logged interval to help refine the predicted depth to the top of the carbonate. This was used to optimize the depth at which the casing was set. The depth uncertainty of the key formation top (top of carbonate reservoir) from the surface seismic interpretation was over 180m prior to drilling. The final prediction depth from the VSP interpretation is 7m shallower than the actual carbonate reservoir.
Guided by the inverted acoustic impedance log and velocity ahead of the bit from look-ahead VSP, a further 150m was safely drilled before setting the casing. The casing point was set successfully without penetrating the carbonate. The intermediate VSP results helped to decide drilling ahead in a safe manner with confidence, after setting the casing before penetrating the carbonate target.
Using High-Expansion Gauge Hangers to Collect Reservoir Performance Data for Improved Oil Recovery
Authors: Babin Jacques , Mlcak Matthew , Denmon Michael 
Published: October 2015

Abstract
This paper illustrates varying situations where the high-expansion hanger has proven to be a viable and valuable solution for reservoir analysis and optimization. Difficulties associated with acquiring accurate data using modern completion designs or new exploratory methods to optimize producing resources are also discussed in addition to solutions provided using the high-expansion hanger.
A new high-expansion gauge hanger is deployed on slickline or coiled tubing using a non-explosive setting tool, for completion and reservoir analysis during well testing. It can be positioned anywhere in the casing for through tubing and/or rigless operations. The high-expansion design provides a generous bypass flow area to increase accuracy of data recorded. A unique slip design enables reliable set in highly scaled or corroded pipe. Precise placement of downhole gauges on slickline reduces cost and improves accuracy of reservoir and production analysis for improved recovery and efficient well placement.
It is becoming more important to ensure the accuracy of reservoir performance data acquisition to maximize asset production and extend the life of the well. By using strategically placed sensors to accurately record critical information from multiple forms of testing and reservoir enhancement techniques, accurate data gained during testing phases ultimately leads to the best flow regime design and successful reservoir optimization. Modern completion design or reservoir stimulation techniques are effectively evaluated using data acquisition, aiding the development, refinement, and implementation of such techniques.
Anchoring sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications; these flow-rate conditions can prevent the determination of production at the time and rate that could maximize production and revenue of the asset.
This paper examines difficulties associated with accurately acquiring downhole pressure and temperature data in complex well completions as a means to analyze reservoir properties and ultimately optimize the asset recovery. The high-expansion hanger provides a means for precise placement of downhole sensors in more challenging completions during well testing.
Being able to precisely position pressure gauges, sampling tools, or other memory-based logging mechanisms is of great value. By using the slow consistent power of the downhole electrical power generator tool as a setting tool, the gauge hanger provides increased reliability and creates a secure anchor point, regardless of scale buildup or location. It can be run on slickline, electric line, or coiled tubing (CT), providing multiple solutions.
3D Reservoir Mapping While Drilling
Authors: Viandante Mauro , Pontarelli Laura , Fernandes Fred , MacDonald Shona 
Published: October 2015

Abstract
A development campaign offshore Australia, with a total of 15 laterals in a challenging geological environment, has been successfully completed by Quadrant Energy. The main objectives were to geosteer and place the well path at an optimum standoff from the oil/water contact (OWC), while drilling at the interface of the gas/oil contact (GOC), when present, and at 1-1.5m TVD from the reservoir top when not.
The field is characterized by a series of transverse and longitudinal seismic and sub-seismic faults that bisect hydrocarbon-bearing sands which represent the greatest challenges in this development campaign. Evidence from exploration wells showed a thin column of heavy oil and a gas cap in the fault-bonded reservoir. A new multi-disciplinary methodology not only enabled Quadrant Energy to achieve its development objectives, but to develop a full subsurface picture of the Coniston field reservoir.
The use of the Reservoir Mapping-While-Drilling (RMWD) combined with Bed Boundary Mapping Tool (BBMT) and Multi-Function LWD services enabled the laterals to be placed at 1-2m TVD below the reservoir top or gas cap, when present, even in highly faulted sections. In addition to this precise placement the extreme depth of investigation of the RMWD service, in conjunction with the real-time multilayer inversion capability, constantly mapped the OWC at a distance up to 19m TVD below the wellbore. While drilling, different qualities of reservoir sands were identified and enabled the extensions of the wells’ TDs based on reservoir properties. The distance to boundary information, provided in real-time by the RMWD service, was used in real-time by the Quadrant Energy geology and geophysics team to update and validate the seismic model that provided increased confidence in the reservoir model and a more precise planning for future development wells.
This paper will illustrate the use of the latest LWD RMWD technology in a challenging geological environment. The paper will explore the close collaboration, teamwork, and integration necessary to drive innovation and demonstrate the outcomes of this successful campaign which have not only exceeded the development goals, but have also generated a full 3D view of the reservoir.
Conceptual Design for Offshore Pipeline Replacement in Mature Field by Flexible Pipe for Capex and Opex Optimization
Authors: Yananto H. , Girindra Y. 
Published: October 2015

Abstract
A study was initiated to evaluate the benefit of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields to keep them running profitably and with an attractive return on investment (and with no sacrifice to safety and environmental risks). The challenge is to have a new technology with lower "Total" cost from design, procurement, installation, operation and maintenance during its life time.
In the appraise stage, several technology options were considered to select the best option to maintain the pipeline; API 17J Flexible Pipe with specific design for shallow water is the alternative option compared to traditional rigid carbon steel pipeline. The assessment process started with pipeline technology update, followed by technical compatibility/ acceptance, commercially available pipe sizing, installation total cost comparison, installation schedule, and operation-maintenance. The decision will be taken by decision tree using Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk.
From the assessment it was conluded that flexibles pipe has more advantages compare to rigid pipes in term of CAPEX, OPEX, resistance to corrosive fluid, ease of installation, ease of repair and maintenance, and ease of decommissioning. The capital cost for 6" F2-FP Flexible pipe is US$ 8.5 million with NPV US$ 37.4 million and IRR 31.7%. The expected monetary value of 6" flexible pipe in decision tree analysis is US$ 27.5 million, the highest among other two options. The flexible pipe is feasible to be applied in F2-FP pipeline replacement project.
Success Story: A New Development Concept Utilising New Advanced Technology in A Very Old Complex Mature Field
Authors: Ng K. F. , Afandi T. , Sa'adon D. , Ja'afar J. , Omar M. A. , Latiff N. A. , Santoso G. I. , Alang K. , Roberts I. D. , Murad N. , Permanasari D. , Kutty F. 
Published: October 2015

Abstract
T-Field, located offshore East Malaysia, is a matured oil field that beganits development in the 1970s. Conceptual geological model generally illustrated this field as retro-gradational turbidite setting. The major reserves are contained in the stage IVD sequence, which is of late Miocene in age. The gross oil-bearing interval is about 300 m thick, divided into three(3) groups of sands (U -Upper, M-Middle and L-Lower stage IVD). As the "low hanging fruits" exist but are limited within this 40 years old matured field, drilling along the reservoir bedding plane was introduced as the best way to optimise the oil recovery in this field, where maximum reservoir-wellbore contacts and lower drawdown are expected to be achieved.
It is commonly known that the turbidite channel has enormous geological complexity and therefore presents great challenges for successful horizontal well placement. The discontinuity of sand packages, highly anisotropic environment with the presence of thinly laminated sand and the lateral heterogeneities in horizontal zone are the biggest challenges in the implementation of this new drilling approach. Therefore, good well planning and right geosteering decision during drilling are crucial to achieve the well objectives. A reservoir mapping-while-drilling technology with capability to map the multiple sand layers in larger scale (up to 30m Depth of Investigation) was utilised to provide a clear picture of the reservoir structure during well landing and after entering the reservoir to stay inside the reservoir sweet spot for optimum production.
This paper captured the first job in South East Asia in developing horizontal well placement in turbidities environment. It elaborates the highlights, success story and lessons learnt in using the latest technology which was proven as the most advanced geosteering and reservoir-scale mapping tool. This technology has not only enabled the drilling of 600 m-MD oil column, doubled net-to-gross ratio of sand penetrated and doubled the oil production of target reservoir but it has also helped the asset team in proper reservoir characterization and redevelopment planning.
A Strengthening, Modification & Repair (SMR) Decisionmaking Toolkit for Structural Integrity Management (SIM) of Ageing Offshore Structures.
Authors: Nichols N. W. , Khan R. , Ng S. M. , Lee L. A. 
Published: October 2015

Abstract
The Strengthening, Modification & Repair (SMR) toolkit is currently integrated into PETRONAS Carigali Sdn Bhd (PCSB) Structural Integrity Compliance System (SICS) which is a web-based application for the Structural Integrity Management (SIM) of fixed offshore structures. The objective of the SMR toolkit is to allow a user (engineer/manager) to quickly and efficiently determine all available SMR options for both jacket and topsides. The toolkit aids in the selection of suitable SMR technologies for a range of applications based on several key information as entered by the user. The Toolkit provides a variety of SMR options from key case studies from global and local databases and provides the most appropriate solutions for the SMR on both jacket and topsides structures of fixed offshore structures. The toolkit also has the ability to make use of other resources such as availability of particular vessels in specific operating regions, financials, logistics, technical expertise and other decision-making criteria prior to the engagement of implementation of any costly SMR scheme. The SMR decision-making toolkit is ideal for practising structural integrity engineers in operations to perform high level feasibility studies in determining preferred SMR options. The database is continuously updated to provide new options on case studies, availability of other resources and expertise, including availability of vessel and technical resources including the pricing, to ensure operators have the best information at hand prior to making decisions on SMR.