bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permanent Downhole Gauge: A Need or A Luxury?
Authors: Chris Chen Jiun Horng @ , Nordin Norbashinatun Salmi , Nuriyadi M Azrul , Samsudin Noren , Kasim Abdullah , Hoe Chum Wai , Rahman Roziman Abdul 
Published: December 2009

Abstract
Moving into electronic age, completion tool and accessories are getting advanced. For the past 10 years, permanent downhole gauge (PDG) technology has been supported with tremendous investment in its research and development. This pacing technology is no longer new to the industry oil and gas operators. Some operators have made it as standard practice but however, some operators are still performing financial model analysis to justify for PDG installation. Is it a real need to install PDG or it is just another fancy luxury that give limited financial returns to the project? How much data is required by petroleum and reservoir engineer to understand the reservoir? This paper presents in detailed about the financial model analysis and demonstrates the tangible and intangible benefit of the PDG and the added value to full field life cycle.
Hearing Conservation Program in Oil and Gas Company
Authors: Hadad Ashif , Cahyono Dwi , Putra I. B. Ardhana , Susanto J. , Rianto Bambang Udji Djoko , Tjahjono E. W 
Published: December 2009

Abstract
Noise is one of hazards in Oil and Gas Company. It is managed thru Hearing Conservation Program (HCP) which mainly consists of workplace noise measurement, noise dose calculation for HCP member (personnel intentionally exposed to noise hazard) or noise exposure, Noise control (Engineering Control, Administrative Control, and Hearing Protection Device), Training and socialization, Audiometric testing and evaluation program. Letter assigning HCP Committee and issuance of procedure for HCP have been issued as a proove of support from Management.
It is recently developed INASyst® software (Integrated Noise Assessment System) to support the program which provides some essential noise features such as, Noise Mapping, Noise Source measurement analysis, Noise Dose Calculation, HPD (Hearing Protection Device) Selection, Noise Criteria Calculation. The noise simulation program, on the other hand, will also allow prior analysis to the planned alteration on noise source hence noise levels at the working places. Therefore early precaution and action plan concerning the HCP can be appropriately prepared
In health surveillance aspect, Audiometric test is performed regularly refers to the procedure and evaluated together with ENT (Ear, Nose & Throat) specialist for early detection of the Noise Induced Hearing Loss. All Audiometric test result is entried into database. For improving employees awareness related to Noise, Similar Exposure Group health talk is performed using variety tools (Playing games/animation) by Medical Staff and regularly by ENT Specialist with the topic Noise effect, Noise control and the appropriateness useful of ear protector. The program evaluation was performed by elements program inspection and also presented to the management for continuous improvement
Hearing Conservation Program in Oil and Gas Company.
Managed Pressure Drilling Proves its Value in Offshore East Java Field Development
Authors: Lang Clifford , Attema Huib , Toralde Julmar Shaun , Nas Steve , Fisher Kevin 
Published: December 2009

Abstract
The development drilling campaign for the Ujung Pangkah field in offshore East Java, Indonesia, began in the first quarter of 2007. To prepare for circulation losses, the field operator tendered for managed pressure drilling (MPD) services as a contingency. The first gas well was successfully drilled by relying on conventional lost circulation material (LCM) to minimize the losses encountered. However, after drilling a pilot hole, plugging back and sidetracking the second gas well, total losses were encountered, followed by the persistent migration of gas up the annulus despite seawater bullheading. After stabilizing the well, MPD equipment and personnel were then mobilized and the system was rigged up to allow for clean-out and completion operations. Total losses were again experienced, but MPD made washing and reaming down to the previous depth possible. MPD techniques also kept gas migration in check, allowing for safer tripping operations in and out of the hole. An additional 55 ft of new formation was drilled and completion was run using MPD methods. This gas well has proved to be the most productive well drilled in the field to date.
In subsequent wells, MPD equipment was rigged up before drilling the hole sections where severe circulation losses are anticipated. This practice paid dividends when severe losses were again experienced while drilling the first oil well. With the MPD system already installed, drilling was able to resume immediately in MPD mode up to the target depth for the section, despite total losses. Liner running and cementing was then successfully done in MPD mode, allowing for the successful isolation of the zone where the losses were and for drilling operations for the next hole section to proceed immediately.
The MPD system in the Ujung Pangkah field has proven its value as a contingency measure by allowing drilling operations to continue despite total loss of circulation and by minimizing the non-performance time involved when the eventuality occurs.
Challenges for Coiled Tubing in Slim Hole Horizontal Well Intervention
Authors: Al-Sharji Hamed , Kumar Santhana , Ferdiansyah Erik , Neyaei Fardin Ali 
Published: December 2009

Abstract
This paper addresses challenges faced in Coiled Tubing (CT) intervention in slimhole horizontal wells in one of the most mature fields in Oman. An intensive production optimization program has been set by the reservoir management team. The optimization activity consisted of clean-out, saturation logging, perforation and stimulation. CT units utilization played the main role in this program. Large number of these wells were completed with 2 7/8" cemented horizontal liner and 4½" tubing equipped with gas lift system. These wells were sidetracked using CT drilling. The length of the horizontal 2 7/8" section ranges between 1000 m and 1600 m, having the kick-off depth at about 1300 m.
CT intervention was very challenging in these well, as CT reach was limited in most of the cases. This is mainly due to the following factors: Complex well trajectory path or "snake-like" wells.Limited tools and CT pipe size due to small cross sectional area.Scale build up on completion.High production rate resulting in resisting CT passage.Corroded liner and poor cement bond resulting in preventing scale cleanout with reactive fluids.Bad liner and/or tubing conditions resulting in mechanically obstructing CT passage.
Therefore some unsuccessful cleanouts or dummy runs were held. Hence, no logging and or optimization activities could be done.
A total of 22 wells were intervened in this project. At project midway success rate was 40% and at the end success rate was increased to 60%.This paper addresses the lesson learnt throughout this project and techniques used to enhance CT reach. The technique involved the use of CT force models and reach simulator to sensitize different factors. As more jobs were performed, models were compared with actual data and some learning could be gained. The main learning was that well flow rate was the highest contributor preventing a deep reach. Hence, the improvement techniques involved manipulating gas lifting flow rate to reduce well flow rate while CT runs in hole.
Silicon Containing Scale Forming Characteristics and How Scaling Impacts Sucker Rod Pump in ASP Flooding
Authors: Jinling Li , Tiande Li , Jidong Yan , Xiwen Zuo , Yan Zheng , Feng Yang 
Published: December 2009

Abstract
ASP (alkali-surfactant-polymer) flooding improves recovery rate dramatically. However, scaling problem happens in artificial lift systems and causes pump sticking in sucker rod pumps and the average pump running time decrease from 500 days to 37 days. By analyzing the constituents and characteristics of scales from ASP production wells and experimenting with simulating produced liquid, characteristics and mechanism of silicon containing scale forming are researched. The results show that Ca2+, Mg2+, Al3+, polyacrylamide, surfactant and silicon influence the ASP scales structures and forming processes. The ASP scales have the characteristics of absorbing and sticking. Basing on describing of scaling characteristics, mechanisms and the pump structures, the reasons for pump sticking are analyzed. Pump sticking which caused by scaling between the plunger and barrel occurs when the sucker rod pump is sucking, hot water is circulating or the pump is stopping. When the well is shut down, one major reason of pump sticking is scale particles set down, stick and pack in the anti-sand groove. When a great deal of hot water is circulating in the well bore, liquid viscosity lowers and scale particles set down speed increases also. The slow-dissolved solid scale-inhibitor SY-2 and anti-scale pump with long plunger-short barrel are developed and applied in field. Through these methods applications, the pump running time have been prolonged and good results have been achieved.
Novel Injecting Concentration Design Method for Polymer Flooding in Heterogeneous Reservoirs
Authors: Zhang Xiaoqin , Guan Wenting , Li Xia , Liu Zhen , Meng Jing , Jiang Dongyang 
Published: December 2009

Abstract
Daqing oilfield is a multilayer heterogeneous oilfield. Recently, as the development target is more complex and reservoir heterogeneity is more serious, simple injection concentration can not meet the requirement of polymer flooding in Daqing oilfield. Therefore, based on different reservoir geologic characteristics, individualized design of injection concentration for single well is needed to relieve the areal contradictory. Numerical simulation study shows that under the same pressure difference, reservoirs with different permeability are compatible with polymer solutions of diverse concentrations. In the field site, individualized design for single well is based on actual permeability and injection pressure scope, injection concentration ranges from 400mg/L to 2500mg/L. After implement, breakthrough rate of polymer along high permeability zone is effectively controlled; meanwhile, development degree of low permeability reservoir is increased, areal contradictory is relieved as well as polymer flooding effect is improved.
Safety Cultures – Pushing the Boundaries of Risk Assessment
Authors: Lee Nai Ming 
Published: December 2009

Abstract
With an ever growing interest in the safety, health and environmental performances of organisations across the industries, today's responsible businesses are committed to the conservation of workplace safety and health, as well as the environment.
In Oil Spill Response, risk assessment (RA) is an integral part of the Safety Management System and pivotal to operational safety. RA is used to address hazards and risks to our staff, contractors, and the large number of industry delegates subscribing to our training courses annually.
Over the years, the approach to RA has constantly evolved. While the concept is not foreign, a lack of common understanding on how risk assessment should be applied has limited the purpose for which it is meant. Following a recent in-depth review of the existing process, the methodology for risk assessment underwent a major revamp. Central to this review is the need for a coherent approach to the conduct of RA across all levels of the organisation.
The outcome of the study signifies a step change in the approach to risk assessment, with an ensuing framework that is more rigorous and comprehensive. Aligned to approach taken by leading organisations in the Oil and Gas industry, hazards and risks to people, environment, assets and reputation are addressed using defined sets of criteria.
This paper will outline key challenges in the conduct of RA, and the different considerations when reviewing the approach to managing operational hazards and risks. The corresponding build-up of a framework to administer the process, and to support the communication of risks, coupled with the implementation of risk control measures and post-activity review, will also be discussed, with an intention to highlight how management commitment and visibility is demonstrated through its application.
Lastly, the paper will explain the practical application of the revised methodology, taking in view the diverse environments that spill responders would be required to work in.
Bringing the 1st BP Operated Subsea to Shore Gas Field into Production: Flow Assurance Lessons Learned
Authors: Harun A. F. , Watt N. 
Published: December 2009

Abstract
Taurt field located in the Mediterranean Sea in 108 m water depth is the 1st BP operated subsea to shore gas development. Phase 1 of the project consists of two subsea wells producing directly from the subsea manifold to the onshore gas processing plant via a 68 km, 20-in pipeline. The field has been brought into production and ramped up to 230 MMscfd successfully despite facilities constraints during initial start-up. The main flow assurance issues experienced during the initial start-up are hydrate risks due to J-T cooling and liquid production handling onshore particularly due to potential completion brine return.
The experience during initial start-up highlights the importance of collecting good fluid samples during exploration and appraisal, and also the down hole and wellhead pressures and temperatures during flow back. Confirming the condensate yield helps prediction of liquid holdup in the pipeline which in turn will affect the prediction of liquid production coming to onshore during ramp-up. More accurate prediction of the wellhead temperature affects the requirement for hydrate inhibitor which in turn also affects the liquid holdup in the pipeline and liquid production coming onshore.
Transient simulations help in selecting the dewatering strategy to be either pigged or pig less operation by predicting the amount of remaining water and how it impacts the production ramp up. Simulations also help prediction of the liquid production for setting up temporary liquid handling facilities to prevent the possibility of completion brine return upsetting the processing plant.
Comparison with the actual liquid production data suggests that simulations should have been performed with less conservative condensate yield, although predicting the completion brine return onshore is still difficult. After obtaining the latest fluid composition and the actual operating conditions, the hydrate management strategy has been re-visited and resulted in operations cost saving and simpler operating procedures.
Reusing Recovered Base Oil from OBM Cuttings
Authors: Kleppe Stein 
Published: December 2009

Abstract
Millions of tones of oil contaminated drill cuttings are produced every year. By nature the cuttings are contaminated by drilling mud. The level of contamination depends on the efficiency of the mud return system carried out by means of shell shakers. The cuttings may origin from drilling with water based mud (WBM) or oil based mud (OBM). Many different composition of mud and many different properties in the well result in a vast variety of cuttings properties. Defining caracteristics of the cuttings is difficult and it is often not made easier by the drillers and mud suppliers who tend to protect details about their mud.
Drill cuttings have different destinys in different areas. Some is dumped, some is reinjected, sometimes the material is cleaned and parts of the waste are reused in new mud. It appears as if the destiny of drilling wastes often is decided based upon limited input and without overall conciderations. In some cases the decision seems based on unproportional focus in only a few areas like ease of operation, emissions to sea/air, cost, storage, etc. Often the value of oil in the cuttings is not given appropriate attention.
The purpose of this document is to touch upon the different routes OBM cuttings may take and treatment methods in general, then to discuss available thermal separation techniques and finally to describe studies made of oil quality from thermal separation by means of friction based hammermill driers.
Often the oil recovery acceptance criteria are based on a maximum flash point reduction caused by the thermal process, but comparison is made to virgin base oil which not necessarily represents the actual oil in the feed. Tests have shown a measurable shift in distillation curve and flash point from virgin base oil to oil in drill cuttings. This study does not include identification of the scources of degradation of oil before separation, but it is likely that aging and pollution from mud additives or from well formation are factors of significance.
The findings are that the hammermill works for recovery of high quality oil from OBM drill cuttings without degrading oil qualit ard. In fact the thermal separation process can be used to raise the quality of oil compared to the actual feed to the unit by removing oil fractions outside of the virgin base oil specification. Recovery and reconditioning of the valuable base oil justifies the cost of the cleaning process, providing a win/win situation for the drillers, mud companies and for the environment.
Verification of Microbial Activities for Microbial Restoration of Methane Deposit With Subsurface CO2 Sequestration into the Depleted Oil Fields
Authors: Otagaki H. , Fujiwara K. , Hattori Y. , Sugai Y. , Okatsu K. 
Published: December 2009

Abstract
The objective of this research is to estimate the possibility of microbial restoration of methane deposits using subsurface sequestered CO2 and indigenous anaerobes in depleted oil fields. The most important factors are the efficiency and velocity of methane conversion by indigenous anaerobes inhabiting a reservoir. Field samples (producing oil and water) from oil field in Japan were collected and analyzed in order to clarify the existence and survivability of indigenous methane-producing anaerobes under reservoir conditions. The hydrogenotrophic methanogen consortium MYH-4 consortium was separated from the enrichment culture added oil reservoir water. By using MYH-4 consortium, two experiments were conducted. ( i )Direct calculation of the CO2 to methane conversion rate for economic assessment. ( ii )As the main objective of the field operation test, it is necessary to identify the state of the subsurface injection environment and the limitations that it poses to methane production. To clarify this, the experiment was carried out by using stable isotope probing. At the result of these studies, it has been understood that the methane conversion efficiency from CO2 was approximately 50%.
Re-Evaluation of a Complex Mature Field (Dunbar, UKCS): A Geosciences Integrated Work
Authors: Ben Brahim L. , Coombes T. , Cooper R. , Fredonnet J. , Taylor D. , Varley S. 
Published: December 2009

Abstract
Dunbar Field (3/14 block) is operated by Total E&P UK. Situated on an intermediate terrace between the East Shetland Platform and the Viking Graben, the field is characterised by a series of pre-Cretaceous and structurally aligned tilted fault blocks. The principal hydrocarbon accumulations are contained in the Middle Jurassic Brent Group and younger Upper Jurassic Heather Sands with additional volumes in the Lower Jurassic Statfjord and Triassic.
Internally, the field is compartmentalised by a number of N-S faults and a secondary alignment of NE-SW faults which cross cut and often offset the main N-S faults. The larger scale faults down throw to the east and subdivide the field into four main areas; the West Flank, Central Panel and Frontal Panel with an uplifted Horst (Triassic) Panel in the south. Each of these panels has specific reservoir and fluid characteristics.
Discovered in 1973 the field did not start production until 1994 owing to the high levels of complexity and geophysical uncertainty. Compartmentalisation, with limited or no interaction between panels, was a major obstacle in assessing the potential of the field. (Coombes et al, 1996)
The field has so far produced more than 280 MMBoe.
Better understanding of the reservoir behaviour relies on our ability to better define the size of the connected volumes through a combination of seismic horizon and fault picking followed by refined geological and reservoir models. A full re-evaluation of the field was launched in 2007. It includes a PSDM3D reprocessing of the third 3D seismic survey on the field, shot in 2001. Use of the latest time processing and depth imaging techniques has enabled us to better understand the results of Phase III drilling (2005 – 2007) and improve our understanding of compartmentalisation to better define new targets, including the undeveloped volumes in the Triassic southern horst.
An Integrated Computer Based Method to Maximize Infill Drilling, Sidetracking, and Workover Potential in Multiple Stacked Hydrocarbon Reservoirs
Authors: Friedel Torsten , Trebolle Ramiro , Flew Stephen , Belfield William , Meyer Juergen , Curteis Charles , Syaifullah Nalom , Caretta Fausto 
Published: December 2009

Abstract
A novel workflow methodology that covers the entire cycle of field development maximizes the production potential and can increase reserves in stacked reservoirs. The approach will potentially reduce associated costs, risks, and uncertainties, in spite of complex geological structures and drainage patterns.
The new workflow encompasses planning from concept selection to preparation of well proposals during the implementation work. Scalable to any given size of hydrocarbon prospect and number of infill wells, the computational method incorporates cross-disciplinary software (geomodeling and seismic packages) as well as reservoir, production, completion, and drilling software. Linkage between the disciplines is close and conducted iteratively, operating in parallel instead of the common sequential and decoupled approach.
The method has been successfully tested in a brown field with 165 stacked reservoirs. Reserves increased significantly compared to the offset field development plan (FDP), while water production was significantly reduced. The optimized drainage pattern for the whole field also revealed significant future workover potential in shallower reservoirs, maximizing contingency and lifetime value of infill wells.