bluuebunny/crossref_metadata_2025_split huggingface dataset:
No Lost Time Injury: A Success Story of a Multi-Disciplinary Approach in Amenam Kpono Field
Authors: Bada A. J. , Abia D. , Igwe A. , Ugbebor J. 
Published: February 2011

Abstract
Amenam Kpono offshore platform is operated by Total E&P Nigeria Limited, (operator of the NNPC/TEPNG joint venture). Amenam Kpono is ISO 14001:2004 certified and has been consistent in high ratings in Internal and External Safety Audits. Oil and gas operations are associated with inherent risks. The hazards and associated risks become high when there are varied critical and simultaneous activities such as Coiled tubing operations, Separator sand jetting, Turn around maintenance, painting campaign, opportunity jobs and oil / gas production. The scope of the paper did not cover the technicalities of these high potential operations but emphasises on the safety approach during the planning, execution and the handing-over/demobilization phases of these operations. Hazards eliminations and risk control /reductions from the various safety elements: Organizations, Personnel, Equipment and Environment are in the effectiveness of multi-disciplinary approach using appropriate Safety barriers. Ensuring a ‘No Lost Time Injury" considering these critical operations is a continuous improvement on the Health, Safety and Environment management systems and the enhancement of the Safety culture in the field. The paper also focuses on various pro-active measures employed in achieving the No lost time injury and the impact/benefits to the company in terms of Legal, Image, Moral and Economics. Safety Culture development and the human factor were also analysed in relations to Injury prevention. In Amenam Kpono Field, various measures (Pro-active / Reactive) such as Safety Inspections, Safety Audits, Safety training, Safety observations, Accident investigations and sharing lessons, Job Safety Analysis, Safety meetings, Emergency Response and plans, Contractor Management, Personnel on board management all combined with the different roles played by all personnel culminate in the success story of No lost time injury. The Safety Statistics of Amenam Kpono Field were presented comparatively focussing on LTI and target settings for the various datas. Ensuring a multi-disciplinary approach to the functionality of the Company's Health, Safety and Environment management system has caused personnel to take ownership of safety and shares the responsibility of operational safety objectives follow-up/close-out.
Early Kick Detection Using Real Time Data Analysis with Dynamic Neural Network: A Case Study in Iranian Oil Fields
Authors: Kamyab Mohammadreza , Shadizadeh Seyed Reza , Jazayeri-rad Houshang , Dinarvand Navid 
Published: February 2011

Abstract
One of the important challenges in drilling a well is kick detection. In fact, ignoring the signs of a kick lead us to complicated problems in killing the well and consequently, if the kick could not be controlled a blowout may occur. Therefore, considering the early detective parameters seems crucial.
Kick happens because some parameters like tank volumes are changed when the time passes, so static neural network cannot predict this occurrence; therefore, using dynamic neural network, which incorporate the previous data could predict the system manner better than the static one.
In this paper, a dynamic neural network model is presented and good results with acceptable accuracy are shown. The model was trained with some Iranian onshore oil wells that kick was encountered in them. The kicks were predicted longer before it could have been detected by the drilling crew.
Optimization of Waterflooding Using Smart Well Technology
Authors: Meshioye Oluwafisayo , Mackay Eric , Ekeoma E. , Chukuwezi Martinez 
Published: February 2011

Abstract
The incorporation of the smart technologies in injection wells has not been widely considered before this work, hence the originality. The world's demand for oil product is increasing gradually and lack of new significant discoveries has made it imperative to look for secondary processes and better technology that will help increase oil production. One of the secondary recovery mechanism used all over the world is waterflooding. Waterflooding is used in nearly all the fields in the world, it is used after natural depletion, and it's used for pressure maintenance and volumetric sweep of the reservoir. Smart well technology is another technology that is assisting in increasing oil production, it's a non-convectional well with downhole instrumentation (sensors, valves and inflow control devices) installed on the production or injection tubing. This work presents a methodology where waterflooding is been controlled by smart injector well technology to help optimize or increase the net present value of the Field.
The optimization procedure was done on three different case studies of commingled reservoir having different layer characteristics; it involves vertical smart injector well and production well penetrating fully through the commingled reservoir. A set-up optimization procedure was applied, were rate allocation method was used at each zone of the smart injector well. In this research, the right rate allocation to each zone that gives the maximum Oil recovery or highest Net Present Value gives the answer to the Waterflood Optimization setback. The smart injector well use in this research has Inflow control Valves which can automatically open and close in order to meet certain reservoir or production requirements.
Installing Smart Completion on the injector well gives an opportunity to control all cases of early water breakthrough and reduce water recycling in some reservoir layers; which will ultimately lead to an increase of 2% − 8% in the Net Present Value and 6% − 9% Cumulative Production of from the field.
This Technology is highly recommended for Niger Delta fields to improve recovery and delay water breakthrough.
Determination of Water Salinities in Hydrocarbon Bearing Reservoirs of Some Niger Delta Fields - Nigeria
Authors: Oruwori A. E. , Ikiensikimama S. S. 
Published: February 2011

Abstract
The purpose of this study basically is to determine water salinity of some fields to be used for screening of candidates for reservoir performance monitoring jobs, and to make such data available for use in the future field development studies. In this work the methods used to determine the water salinity are: the use of log interpretation chart, interpretation of basic common open-hole logs and the use of log interpretation software. The water salinities obtained from these methods were compared with the produced water analysis salinity values from the laboratory. From the results obtained, there is a trend in salinity, and the trend in the hydrocarbon bearing reservoirs varies with the different reservoirs or fields of study and is greatly affected by the lithology of the formation (i.e. sand or shale) where resistivity reading was obtained from, and resistivity tool used for logging the various reservoirs.
A Systematic Workflow Process for Heavy Oil Characterization: Experimental Techniques and Challenges
Authors: Memon A. I. , Gao J. , Taylor S. D. , Davies T. L. , Jia N. 
Published: February 2011

Abstract
Heavy crude oil reserves are steadily gaining attention as the world's energy demand increases. The fluid characterization of heavy oil and bitumen is critical in deciding best extraction, production, and processing methods of a heavy oil asset. High viscosity, low API, low saturation pressure, and low GOR impose challenges in measuring fluid properties of heavy oil. Such challenges include fluid sampling, sample handling, cleaning and de-emulsification of heavy samples and slow evolution of gas from oil phase during pressure-volume-temperature (PVT) testing— e.g., constant composition expansion (CCE) experiment. Due to these challenges, the accurate and reliable fluid characterization of heavy oil becomes more difficult. Currently, no industry standards exist for heavy oil property measurements. More often, heavy oil property measurements are performed in the same way as black oil fluid property measurements. This poses a big risk in obtaining erroneous fluid properties measurement for heavy oils.
This paper summarizes the heavy oil fluid characterization technique that includes fluid sample handling, PVT analysis, fluid viscosity, emulsion and rheology, slow kinetics of gas evolution during CCE experiment, solvent solubility study, steam stripping study, and high temperature vapor-liquid equilibrium of oil-solvent-steam systems. The experimental methodologies, including the merits and experimental limitations for these measurements are discussed in detail. Example results of heavy oil property measurements for each technique are presented. Finally, a systematic heavy oil characterization workflow is proposed for various types of production processes such as cold depletion, steam flood and heavy oil flow assurance characterization.
Local Dissociation Experiments of Methane-Hydrate-Bearing Soil
Authors: Falser S. , Palmer A. C. , Tan T. S. , Ja M K. 
Published: February 2011

Abstract
Large amounts of gas hydrates are deposited in marine sediments and permafrost regions in many parts of the world. Their potential as a future energy source, but also as a geohazard and contributor to global warming has raised people's interest. The paper reviews the major methane hydrate test facilities and summarises their capabilities. It is reckoned that none of them can dissociate hydrates locally by a combination of heating and depressurizing while measuring their composition changes in it situ. These features are later revealed as the core elements of the new hydrate test facility at the National University of Singapore (NUS), which can simulate hydrates in up to 1500 m below sea water level and 350 m below sea bed or surface, dissociating them along a centred line source while measuring local pore pressure-, temperature- and density-changes. Its single components are described in detail.
Montney Fracturing-Fluid Considerations: Case History
Authors: Romanson R. , Riviere N. , Taylor R. , McIntosh G. , Wilson M. , Loran C. , Cockbill J. R. 
Published: February 2011

Abstract
The Montney gas reservoir presents exciting potential and is likely to become a critically important component of future gas supply. However, the Montney often presents variable and unique stimulation challenges. Unlike reservoirs like the US Barnett shale but possibly like the Muskwa in the northeast B.C. Horn River basin, recovery of water-based fluids can be a key issue to achieving economic production rates in the Montney.
Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production response. One must always keep in mind that key reservoir properties can vary dramatically in the Montney, both as a function of geographic location and depth.
A presentation entitled "Montney Fracturing Fluid Considerations" was given at the 2009 CSUG conference, which summarized results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions. Water-, foamed water-, and hydrocarbon-based fracturing-fluid systems were studied. Implications of the results as to choice of optimum fluid were discussed.
This paper presents field-production results of the trials conducted with fluid systems resulting in conjunction with the above study. The concepts and reasoning used to arrive at final fluid choices for field trials are discussed, as well as a theoretical interpretation of the field-production results.
Behavior of Depressurization in Type III Hydrate Reservoirs
Authors: Shahbazi A. , Pooladi-Darvish M. 
Published: February 2011

Abstract
Hydrate reservoirs have been categorized as Type I, II, and III; Type I with underlying free-gas, Type II with underlying freewater, and Type III that is sandwiched by impermeable formations. The most common type of hydrate reservoirs are probably Type III reservoirs, where there is no underlying mobile phase beneath the hydrate layer. Depressurization in Type III reservoirs is characterized by difficulty in reducing pressure over a large region because of limited available surface area for decomposition and low permeability in the hydrate. This is unlike to be the case in Type I and II reservoirs, where pressure could be reduced across a large surface area between the hydrate and the underlying free phase.
A 3D numerical model incorporating heat and fluid flow, along with kinetics of decomposition and (re)formation of hydrate and ice, is developed in this paper. Next, the solution behaviour of Type III hydrate reservoirs in response to application of the depressurization technique is studied, with the goal of understanding the interactions between fluid and heat flow and their effects on the decomposition region. This is achieved by exploring for similarity solutions in Type III reservoirs.
The results of this study indicate that the behaviour of Type III reservoirs is sometimes close to that of diffusion problems, suggesting that a similarity solution exists. This has also been shown to be the case in the literature. However, under some other conditions, it is shown that the solution to this problem is also identical to a travelling wave solution, which is another type of similarity solution often observed in diffusive-reactive problems that exhibit frontal behaviour and sharp gradients. Conditions leading to development of these two types of similarity solutions are identified.
The contribution of this work is in identifying the different solution regimes in Type III hydrate reservoirs. This could help to understand and simplify the modeling of governing mechanisms involved in the process of gas production from the most common type of hydrates.
Real – Time Geomechanics: Applications to Deepwater Drilling
Authors: Bagala S.. , McWilliam I.. , O’Rourke T.. , Liu C.. 
Published: February 2011

Abstract
Lithologies under deepwater conditions usually show relatively reduced effective stress, due to the reduced lithostatic column. This translates into relatively narrow mud weight windows, driven mainly by shear failure or pore pressure in overpressured conditions, and by minimum horizontal stress gradients. Drilling operations should consider wellbore collapse, kick and losses as the primary geomechanics-related drilling hazards. These should be investigated and predicted during well planning, and should also be appropriately monitored during drilling, especially when an appraisal campaign will require highly deviated wells.
Real-time geomechanics is defined as a workflow that takes into consideration mud weight window planning, identification of geomechanics-related drilling hazards and possible mitigation actions, and, while drilling, operations monitoring by real-time data acquisition and interpretation, drilling occurrences detection, drilling practices revision, and the real-time update of mud weight window for further drilling. The authors present the case study of a drilling campaign in Chevron operated Rosebank Lochnagar Discovery, deepwater West Shetland, in almost 3,700-ft water depth. This campaign had the goal of proving the development concept of drilling horizontally in a field where the previous maximum inclination was only 35 degrees.
The planning phase consisted of mud window modeling using a mechanical earth model from offset wells. Potential drilling hazards were then identified and synthesised using a Drilling Roadmap as a drillling planning and management tool. The monitoring phase consisted of real-time detection, from analysis of logging-while-drilling and wireline data, of drilling hazards typical in the area, such as cavings, losses, and packoffs. Data interpretation required a multidisciplinary team of geologists, petrophysicists, geomechanics engineers, and drilling engineers.
The application of real-time geomechanics allowed an improvement in operations, safe drilling practices, and refined calibration of the 1D geomechanical model for further drilling campaigns.
The Science Behind Erosion Qualification Testing of Frac Pack Tools
Authors: Clem Nicholas J. , Hammer Aaron C. , O’Connell Maria M. , Amaral Anderson da 
Published: February 2011

Abstract
Frac packing tool erosion is a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbm. As zone lengths are increased and multizone operations are performed, jobs requiring 60 bbl/min pump rates with proppant loads reaching 1,500,000 lbm are becoming more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells.
Extensive research and development, including computational fluid dynamics analysis and scale-model erosion testing, have led to the development of a new series of sand control tools that have been optimized for ultra-high-rate frac packing applications. Analyzing various patterns such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization.
Results from full-scale erosion qualification testing of this new series of sand control tools are discussed. The qualification tests are designed to simulate extreme applications for tools in terms of pump rate, treatment volumes, and proppant properties, while testing conditions remain consistent with actual job specifications. The qualification test parameters were chosen to emulate and, in some cases, exceed the parameters of frac pack treatments currently being planned for the deepwater Gulf of Mexico. Erosion properties of the crossover, extension, and casing will be discussed, and depicted.
Co-Injection of Noncondensable Gas Improves ES-SAGD Performance in Shallow Oil Sands Reservoirs With a Small Top Water Zone
Authors: Alturki A. A. , Gates I. D. , Maini B. B. 
Published: February 2011

Abstract
The majority of oil sands are too deep for surface mining extraction; hence, in-situ techniques such as Steam-Assisted Gravity Drainage (SAGD) must be used. However, SAGD in low-pressure, top water, reservoirs shows relatively poor performance. To improve SAGD, solvent can be co-injected with steam, as in Expanding Solvent SAGD (ES-SAGD) leading to enhanced recovery, rates, and efficiency. Like most pressurized processes, a competent caprock is needed to prevent steam losses to maintain good efficiency and rates. There exist significant oil sand resources that are considered inaccessible because they are shallow (low-pressure) with little or no caprock with top water zones. Solvent addition allows reduced operating pressure, which makes it amenable for low pressure, shallow reservoirs. This research examines ES-SAGD, with non-condensable gas co-injection, in reservoirs with top water that has the potential to quench the chamber and stagnate oil drainage. The results reveal complex dynamics between the depletion chamber and overlying water zone and operating strategies that extend the life of the chamber thus raising the recovery factor. Low-pressure ES-SAGD operating strategies can be used to efficiently recover bitumen from shallow reservoirs with top water. A key finding from this study is that addition of non-condensable gas to ES-SAGD can significantly improve recovery, rate, and efficiency. Given the volume of shallow oil sands reservoirs with top water, development of processes to unlock this type of resource is important and critical to further growth of in situ oil sands recovery in Alberta. The results provide a technical basis to construct feasible low-pressure ES-SAGD processes for this type of reservoir.
Monitoring Flow and Completion Integrity of a North Sea Subsea HPHT Appraisal Well During an Extended Well Test Using Permanently Installed Fiber-OpticTemperature Sensors
Authors: Wood P.. , Simpson A.. , Holland B.. , Brown G.. , Rogers G.. , Anderson S.. , Balster E.. , Figueroa M.. 
Published: February 2011

Abstract
Since the mid-1970s technology has enabled extraction of the UK’s oil and gas reserves in a cost-effective manner using subsea wells rather than individual platforms. In 2008, 43% of the UK’s oil and gas production was by subsea wells (The United Kingdom Offshore Oil and Gas Industry Association, 2010).
Centrica Energy performed an extended well test on a subsea high-pressure, high-temperature (HPHT) appraisal well in the North Sea and monitored the test using a permanently installed optical distributed temperature sensor (DTS) system. The high temperatures and pressures, together with a subsea installation, created specific challenges for monitoring the completion integrity and flow from the multizone reservoir during the well test.
In this paper the authors outline the deployment of the DTS system and present an interpretation of the acquired data. The completion was installed in one trip, with tubing-conveyed perforating (TCP) guns run at the bottom of the string. The firing of the guns, the completion integrity, and the fluid flow were monitored using a DTS optical fiber connected through the wellhead via an optical wet-connector and extending past the packer to the bottom of the guns. The same cable was used to operate a downhole electrical pressure gauge above the packer. Interpretation of the continuous temperature data enabled Centrica Energy to:
identify leaks at gas lift mandrels while pressure testing the production tubing during commissioning, allowing time saving decisions to be made on how to proceed with the installation. check that all the perforating guns fired correctly to confirm that the whole reservoir was open to flow. monitor the flow from different reservoir intervals over the 2-week well test to compare the flow profile from the reservoir to model predictions. minimize QHSE risks associated with a well intervention.
An Integrated Single-Well Approach to Evaluating Completion Effectiveness and Reservoir Properties in the Wind Dancer Field
Authors: Cherian B. V. , Claugus A. O. , Dilli M. , Mata D. , Sitchler J. C. , Alatrach S. , Neumiller J. L. , Panjaitan M. L. 
Published: February 2011

Abstract
Accelerating the learning curve in a fluvial tight-gas development program can be achieved by understanding the impact of reservoir quality and completion properties on well productivity. Too often completion changes are made over a small sample (statistical) wherein numerous parameters (proppant volumes/type, gel-loading, etc) are changed without clear accountability of the variation in local geology and reservoir quality. This complicates basic production analysis techniques and can be a costly practice to determine the direction in which optimization should proceed.
Various proppants, fluid types and design schedules were analyzed to quantify the impact of these designs on productive fracture half-lengths and conductivity. Calibrated fracture propagation models were also utilized to relate these productive properties (fracture length, conductivity and permeability) to stress profile, gel-loading and proppant types via fracture propagation models. The development of calibrated mechanical properties, petrophysical models and understanding of current hydraulic fracture and reservoir properties thus enabled redesigning of future completions and the analysis of these completions. This paper demonstrates the application of appropriate fracture propagation models, rate-transient analysis and production history matching techniques to understand the direction in which completion design changes must move to increase productivity.