bluuebunny/crossref_metadata_2025_split huggingface dataset:
Leadership and Safe, Productive Culture and Workplace—A Case Study in Improving Safety Through Leadership Development in Drilling and Completions Operations
Authors: Karish J. , Siokos G. 
Published: December 2007

Abstract
Many oil and gas organizations have grappled with the best way to show visible leadership necessary for sustained safety performance.
Over the past 3 years, EDN has worked with a number of Operators and Contractors to develop and implement an HSE Leadership Development Program designed to develop leaders’ skills to integrate safety into their work and build confidence and competence to lead their people in improving safety outcomes. In effect, become visible leaders for safety.
The HSE Leadership Development Program begins by developing a greater understanding of the organization's safety vision and values and then exploring and experiencing leadership, team behaviors and skills necessary to achieve safe work outcomes. It ends with participants developing action plans that are revisited shortly after the Program ends with coaching to extend learning and assist in the plan's implementation.
The Program provides feedback for each participant that is prepared as a result of behavioral observations made during the Program by trained observers. The feedback is focused on specific HSE Leadership Competencies, including: ➭An ability to describe the organization's business context and how HSE features in business success.➭An ability to integrate safety systems with all other business systems to ensure their seamless application in the workplace.➭An ability to create a work environment and culture where people freely and willingly participate in planning and implementing plans for improved productive and safe work outcomes.
This paper will expand on the structure of this Program and results achieved thus far.
The paper and presentation will cover the development of the HSE Leadership Development Program since its inception in BP to its various forms in other organizations.
Breaking the Safety Plateau: A Successful Implementation of Behaviour-Based Safety Across a Range of Cultures, Facilities and Functions
Authors: Younes N. 
Published: December 2007

Abstract
BG Group, a leading oil and gas company operating in over 20 countries, enjoyed a long period of consistent safety performance improvement through the development of robust safety management systems and processes and a strong top- down drive from the company's Management team. However, the rate of improvement, as measured by the lost time injury frequency (LTIF), reached a plateau with a risk of deterioration. A step change in HSE management was required to avoid complacency and further improve the safety performance past the identified plateau.
To measure the company's safety performance, a range of proactive and lagging indicators is used. The results from these lagging indicators are aligned with a body of published studies demonstrating that as many as 95% of all workplace incidents are triggered by unsafe behaviours. It is therefore by focusing on safety-critical behaviours, as proactive indicators of performance, that the company management intended to reduce incidents and bring about continuous improvement.
The implementation strategy was developed centrally in consultation with all stakeholders within the business units. Support was then requested from the Corporate HSSE Committee to introduce a Behaviour-Based Safety (BBS) process based on the ABC model (Antecedent, Behaviour, and Consequence). A target was set to start implementation in 10 facilities within the first year.
This target was achieved with behaviour-based safety processes developed for oil and gas exploration, production, transmission or distribution facilities in places as diverse as North Africa,Kazakhstan,India,South America or the North Sea.
This technical presentation describes the process of choosing adequate BBS implementation strategy to ensure management buy-in, workforce ownership and a strong focus from all on delivering continuous improvement.
The 14-Point HSSE Assurance Tool
Authors: Younes N. 
Published: December 2007

Abstract
The 14-Point HSSE Assurance Tool is an innovative, electronic tool developed internally within the BG Group to support the company's drive for continuous HSSE improvement. It: Embeds a risk-based approach to HSSE management through a novel risk screening process;Defines the fit for purpose HSSE management system specific to the lifecycle stage of every Business Unit or project;Provides three meaningful scores of Business Unit HSSE performance consisting of: Management System Gap Analysis (MS Gap Analysis) Score which measures the extent to which the required H SSE management system controls have been created and documented;HSSE Perception Survey Score which measures the workforces' perception (from management through to the shop-floor) of the way HSSE is managed in the company;Behavioural Survey Score which measures the effectiveness of application of the HSSE Management System controls;Provides support and promotes knowledge sharing via an integrated HSSE Toolbox, which gives guidance and good practice for each proposed control;Allows for benchmarking of performance both within and external to BG Group;Is designed for use by non-HSSE professionals.
The name of the tool is derived from the 14 elements of the HSSE management system illustrated in Figure 1.
Pore-Scale Modeling of Three-Phase WAG Injection: Prediction of Relative Permeabilities and Trapping for Different Displacement Cycles
Authors: Suicmez V. S. , Piri M. , Blunt M. J. 
Published: December 2007

Abstract
We use a three-dimensional mixed-wet random network model representing Berea sandstone to compute displacement paths and relative permeabilities for water alternating gas (WAG) flooding. First we reproduce cycles of water and gas injection observed in previously published experimental studies. We predict the measured oil, water and gas relative permeabilities accurately. We discuss the hysteresis trends in the water and gas relative permeabilities and compare the behavior of water-wet and oil-wet media. We interpret the results in terms of pore-scale displacements. In water-wet media the water relative permeability is lower in the presence of gas during waterflooding due to an increase in oil/water capillary pressure that causes a decrease in wetting layer conductance. The gas relative permeability is higher for displacement cycles after first gas injection at high gas saturation due to cooperative pore filling, but lower at low saturation due to trapping. In oil-wet media, the water relative permeability remains low until water-filled elements span the system at which point the relative permeability increases rapidly. The gas relative permeability is lower in the presence of water than oil because it is no longer the most non-wetting phase.
We show how to use network modeling to develop a physically-based empirical model for three-phase relative permeability. We demonstrate that the relative permeabilities are approximately independent of saturation path when plotted as a function of flowing saturation. The flowing saturation is the saturation minus the amount that is trapped. The amount of oil and gas that is trapped shows a surprising trend with wettability - weakly water-wet media show more trapping of oil and gas than a water-wet system due to the complex competition of different three-phase displacement processes. Further work is needed to explore the full range of behavior as a function of wettability and displacement path.
Geomechanics Considerations for Through- and Near-Salt Well Design
Authors: Willson S. M. , Fredrich J. T. 
Published: December 2007

Abstract
Over the next decade a significant amount of exploration and new field developments will take place in salt provinces around the world - in the deepwater Gulf of Mexico, and offshore Angola, Brazil, and North and West Africa. Salt formations provide both opportunities and challenges to the design and construction of the often complex wells to be drilled in these locations. An overview of the many geomechanical considerations necessary to ensure successful well construction when drilling in through-, sub- and near-salt environments is presented. The structural styles of deformed sediments adjacent to salt, combined with stress perturbations caused by the presence of salt, are used to assess the risk of encountering zones that might cause wellbore instability or lost-circulation problems. Well design examples are provided that show how near- and through-salt uncertainties may be included within a geomechanical well design for required mud weights while drilling.
Assessing the Impact of Oil Viscosity Mixing Rules in Cyclic Steam Stimulation of Extra-Heavy Oils
Authors: Mago A. L. , Barrufet M. A. , Nogueira M. C. 
Published: December 2007

Abstract
A global steady increase of energy consumption coupled with the decline of conventional oil resources points to a more aggressive exploitation of heavy oil. Heavy oil is a major source of energy in this century with a worldwide base reserve exceeding 2.5 trillion barrels. Management decisions and production strategies from thermal oil recovery processes are frequently based on reservoir simulation. A proper description of the physical properties, particularly oil viscosity, is essential in performing reliable modeling studies of fluid flow in the reservoir. We simulated cyclic steam injections on the highly viscous Hamaca oil, with a viscosity of over 10,000 cp at ambient temperature, and the production was drastically impacted by up to an order of magnitude when using improper mixing rules to describe the oil viscosity. This paper demonstrates the importance of these mixing rules and alerts reservoir engineers the significance of using different options simulators have built in their platforms to describe the viscosity of heavy oils. Log linear and power mixing rules do not provide enough flexibility to describe the viscosity of extra heavy oil with temperature. A recently implemented mixing rule in a commercial simulator has been studied providing satisfactory results. We also suggest more flexible mixing rules that could easily be implemented in commercial simulators.
Petrophysical Model of Split Shear Waves in Anisotropic Media
Authors: Fanchi J. R. 
Published: December 2007

Abstract
We present a geophysical model of seismic anisotropy that has three velocity solutions: P-wave velocity, and fast and slow shear wave velocities. The geophysical model is used to justify the extension of a petrophysical algorithm in an integrated flow model to a form that is suitable for modeling reservoirs that exhibit seismic anisotropy. The model is illustrated by applying it to data representing limestone and tight sands.
A Model to Predict Liquid Holdup and Pressure Gradient of Near-Horizontal Wet-Gas Pipelines
Authors: Fan Y. , Wang Q. , Zhang H. , Sarica C. , Danielson T. J. 
Published: December 2007

Abstract
A mechanistic two-fluid model with new closure relationships is proposed to predict liquid holdup and pressure gradient of stratified flow. The proposed closure relationships include correlations of wetted wall fraction, liquid-wall friction factor, and interfacial friction factor. An iterative calculation procedure is implemented to solve for liquid holdup and pressure gradient for a given set of operation conditions, pipe geometry, and fluid properties.
Two sets of facilities, a small-scale with 51-mm ID and a large-scale facility with 150-mm ID test sections, were used to tune the model. Superficial gas and liquid velocities were varied from from 5 to 25 m/s, and 0.00025 to 0.03 m/s, respectively in the small-scale facility while they were varied from 7.5 to 21 m/s, and 0.005 to 0.05 m/s, respectively in the large-scale facility. The pipe inclination angle varied from -2° to 2°. The liquid holdup was ranged between 0.003 and 0.12 emphasizing the low-liquid loading two-phase flow.
The tuned model performance was then benchmarked against the high-pressure (up to 90 bar) SINTEF stratified flow data. The model predictions agreed well with measured values of liquid holdup and pressure gradient. The comparison between the present model and OLGA performance was also presented.
Coiled-Tubing Gas Lift Reclaims 2000 BOPD of Lost Crude
Authors: Tischler A. , Woodard T. A. , Becker B. G. 
Published: December 2007

Abstract
The paper describes a successful implementation of coiled-tubing gas lift (CTGL) in the diatomite formation of the Belridge field in Kern County, Calif.
The paper shows how the use of CTGL reclaimed 2000 BOPD that would have been otherwise lost due to irreparable casing damage. As soon as casing damage is detected, the future economic life expectancy of a well decreases to approximately 2 years. Wells with confirmed casing failure must generally be abandoned and redrilled, increasing costs significantly.
The paper will detail candidate well selection, equipment design and specifications. During the program, numerous design challenges had to be overcome. Special wellhead configurations were designed in order to ensure a safe and environmentally friendly operation. Coiled tubing (CT) selection was critical – both to optimize lift volume with minimized injection gas and to insure proper functionality and longevity in a high CO2 corrosive environment. The implementation of the project as well as associated risks and final production results will be mentioned as well.
Collapse Resistance of Tubular Strings Under Geotectonic Load
Authors: Morita N. , Kasahara Y. , Hikida H. , Ito Y. 
Published: December 2007

Abstract
The tubular string collapsing process is significantly different when an external load is applied through a solid formation or a fluid. A series of experiments were conducted to analyze the differences in tubular string stability with a fluid force and geotectonic loads. The laboratory tests showed that tubular strings started yielding significantly earlier if the load was applied through a formation rather than through a confining liquid. However, during additional loading after tubular string yielding, the deformation of the tubular string installed in a formation remained small since most of the external load was supported by the surrounding formation. Analytical solutions were developed to calculate the stress state and deformation before yielding and after yielding for gravel packed or cemented tubular strings under directional in-situ stresses.The API tubular string failure criteria were also modified so that they could be applied to more general stress state around a tubular string.Using the tubular string stress state and the generalized API pipe failure equations, a guideline was given for field design of tubular strings under geotectonic load based on the experimental observations.
Correcting Supercharging in Formation-Pressure Measurements Made While Drilling
Authors: Hammond P. S. , Pop J. J. 
Published: December 2007

Abstract
This paper describes a method to correct formation pressures measured while drilling for the effects of supercharging (increased sandface pressure caused by drilling fluid filtrate leakoff).The method consists of deliberately varying the wellbore pressure, measuring that and the sandface pressure response, and then using a mathematical model, taking account of fluid flows within filtercake and formation to quantify the amount of sandface pressure elevation.The true formation pressure then follows by subtracting this estimate of the supercharging from the actual measurement.The method is explained and demonstrated using synthetic data, and then application to data taken in a real well is shown.
Diluting Acid Gases With Sweet Gases in Gas Lift Systems: Assessment, Challenges, and Recommendations
Authors: Barsoum B. N. , Faramoy S. , Zekry M. M. 
Published: December 2007

Abstract
The offshore oil fields located in the Gulf of Suez (GOS) are sweet oil reservoirs. Edfu field, discovered in November 2001 with total proven reserves between 25 million-30 million barrels, contains sour gas. H2S is extremely toxic; the combination of H2S and CO2 (Acid Gas) can be highly corrosive. Edfu field produces up to 6 MMSCF/day with 800 ppmv H2S and 8 % CO2 in the associated gas phase.
Since 1980&s gas associated with the GOS production is being fully utilized for production of Natural Gas Liquids (NGL) at the fractionation facilities in Gas Plant (GOS G/P U-104) based on some pollution prevention mechanisms. Sales gas is being used as a clean fuel for gas-lifting-oil projects.
During the period of Edfu production it was noted that there is dramatic increase in the acid gases concentration in the gas lift system in addition to recently occurring under-deposit corrosion failure.
This paper describes a case history about de-souring of the Edfu acid gases on the offshore production facilities by diluting (mixing) with other sweet gases produced from GOS area. The work demonstrates the influence of such application on corrosion rates of both gas pipelines and offshore production facilities. Also the feasibility of sweating process considering the incremental recovery of natural gas liquids is included.
This paper shows in a systematic way how to separate H2S and CO2 out at G/P U-104.However, these components must be managed in a cost-effect way and according to regulatory requirements to maximize recovery of hydrocarbons and minimize acid gases safety and environmental impacts.Also we review comparative economic and risk analyses of various H2S management options available to developing low volume of acid gases reserves, considering the impact on G/P U-104 production facilities (including rate, ultimate total volume, engineering capacity), the health and safety risks, impact on environment, and regulatory Issues according to current EGPC standards.
Subsea Smart Multilateral Wells Increase Reserves at Gullfaks South Statfjord
Authors: Haugen V. , Fagerbakke A. -K. , Samsonsen B. , Krogh P. K. 
Published: December 2007

Abstract
The Statfjord Formation in Gullfaks South was discovered in 1978, and came on production in 1999 as part of the Gullfaks Satellite Development.
In the Plan for Development and Operations (PDO) The STOOIP was estimated at 35 million Sm3, with estimated recoverable reserves of 12.6 million Sm3. Start up of the first two wells in 1999 showed that the production rate was lower than expected, most likely as a result of poor reservoir communication. A third well was drilled in 2001 and experienced gas breakthrough shortly after startup. Based on these observations booked reserves were reduced to 2.4 million Sm3 in the reservoir management plan for 2002.
Production has been limited by low connectivity, reservoir heterogeneity and gas breakthrough. Surface operated downhole inflow control and multilateral wells have been identified as solutions to these limitations, which has lead to an increase in expected oil recovery.
This paper describes the process of implementing Downhole Instrumentation and Control System (DIACS) and Multilateral Technology (MLT) in three horizontal subsea wells drilled in 2003 and 2004. This has led to a twofold increase in the reserve estimate to 5.4 million Sm3 in the reservoir management plan for 2005.
Geosteering Using New Directional Electromagnetic Measurements and a 3D Rotary Steerable System on the Veslefrikk Field, North Sea
Authors: Wiig M. , Berg E. , Kjærefjord J. M. , Saltnes M. , Stordal E. A. , Sygnabere T. O. , Laastad H. , Raeper G. , Gustavsson E. , Denichou J. -M. , Darquin A. , Omeragic D. 
Published: December 2007

Abstract
Veslefrikk is a North Sea oil field in its tail-end production period where optimal well placement is critical for the drainage of the remaining reserves. This paper presents two case studies representing different challenges with respect to geosteering. In both cases a newly developed Directional Electromagnetic logging while drilling tool (D-EM) was used together with a fully rotated point-the-bit 3D rotary steerable system (RSS) to achieve proactive geosteering. The LWD tool was able to detect resistivity contrasts in any direction up to 5 m from the wellbore. In the first case the objective was to position a 570 m long horizontal well section 1-3 m below the top of the reservoir sand, thereby attaining maximum distance from the water level and ensuring that no attic oil was left behind. In the second case the challenge was to optimize the amount of oil filled sand along the 1100 m horizontal trajectory, while drilling perpendicular to the depositional direction in a fluvial channel system.
The early detection of the sand to shale boundaries resulted in an increase of 10-15 % in the recoverable reserves for each well compared with conventional geosteering.
The workflow setup for both cases included the use of a Web-based system for communication and data transfer. This ensured efficient decision-making involving geosteering specialists, wellsite geologists, and onshore company personnel.
Modeling Water-Injection Induced Fractures in Reservoir Simulation
Authors: Hustedt B. , Qiu Y. , Zwarts D. , van den Hoek P. J. 
Published: December 2007

Abstract
We couple a fracture growth simulator to a standard reservoir simulator using a two-way communication approach. The new approach allows interaction of two stand-alone software packages in order to capture the impact of both, varying reservoir pressure- and stress fields as well as dynamically growing or shrinking fracture shapes.
At a given time step during the simulation, the pressure field is calculated by the reservoir simulator. We determine the stress field on the reservoir grid. Both, the pressure- and the stress field are needed to evaluate a fracture propagation criterion that is based on a stress intensity formulation. The fracture shape is determined in balance with the fracture fluid pressure and the in-situ reservoir stress field using an iterative procedure.
Currently, the coupled simulator handles fracture growth/shrinkage for horizontally, symmetric fractures with fixed height in a single layer reservoir model. The stress calculations require the reservoir grid blocks to be sufficiently rectangular in shape.
We benchmark the new simulator for a number of different test simulations by comparison. The overall comparison with analytical solutions and/or analytical simulations shows a very good fit.
Assessing the Uncertainty in Reservoir Description and Performance Predictions with the Ensemble Kalman Filter
Authors: Zafari M. , Reynolds A. C. 
Published: December 2007

Abstract
Recently, the ensemble Kalman filter (EnKF) has gained popularity in atmospheric science for the assimilation of data and the assessment of uncertainty in forecasts for complex, large-scale problems. A handful of papers have discussed reservoir characterization applications of the EnKF, which can easily and quickly be coupled with any reservoir simulator. Neither adjoint code nor specific knowledge of simulator numerics is required for implementation of the EnKF. Moreover, data are assimilated (matched) as they become available; a suite of plausible reservoir models (the set of ensembles) is continuously updated to honor data without rematching data assimilated previously. Because of these features, the method is far more efficient for history matching dynamic data than automatic history matching algorithms based on optimization algorithms. Moreover, the suite of ensembles provides a way to evaluate the uncertainty in reservoir description and performance predictions.
Here we establish a firm theoretical relation between randomized maximum likelihood and the ensemble Kalman filter. We also consider examples where the performance of the EnKF does not provide a reliable characterization of uncertainty in the model or performance predictions. Although we have previously generated reservoir characterization examples where the method worked well, here we also provide examples where the performance of EnKF does not provide a reliable characterization of uncertainty.