bluuebunny/crossref_metadata_2025_split huggingface dataset:
In-Situ Residual Oil Saturation Determined at Angsi
Authors: Jakobsson Nils M. , Othman Mohamad , Mansur Hussen 
Published: December 2007

Abstract
This paper describes how an opportunity to determine residual oil saturation in-situ was captured in the Angsi field, a relatively new development in the South China Sea off the East coast of peninsular Malaysia. It describes the data required to determine fluid saturations in-situ in a well drilled through a reservoir which has been flooded by injection water, focusing on the importance of getting representative water salinity and reservoir temperature data. It also discusses how the residual oil saturation (Sor) determined in-situ compares with other Sor estimates.
Residual oil saturation is a critical parameter within reservoir engineering. Sor values are often based on laboratory tests performed on core plugs. Because laboratory Sor data is sensitive to plug heterogeneities and testing method, there is often a high degree of uncertainty associated with such data. More reliable, and more accurate, Sor information can be obtained in wells that have been drilled through flooded parts of the reservoir. Capturing such opportunities requires proper planning and preparation.
At Angsi, such an opportunity was captured during field development drilling. High quality in-situ Sor data was obtained in one of the major oil reservoirs. As a result, the residual oil saturation is now better defined, or less uncertain. This means there is a higher degree of confidence in the reservoir model and production forecasts generated from the model. The importance of reduced uncertainty and a higher degree of confidence in production predictions cannot be overemphasized. Such improvements are key to continued development optimization, and should ultimately lead to accelerated production and increased recovery.
Integrating Pressure Transient Test Data with Seismic Attribute Analysis to Characterize an Offshore Fluvial Reservoir
Authors: Sahni Akshay , Kelsch Ken 
Published: December 2007

Abstract
Interpreting pressure transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial depositional environments, where sand continuity is a significant uncertainty, pressure transient test interpretation can generate several non-unique solutions, all of which may match test data. Using seismic attribute analysis to constrain pressure transient test interpretation leads to better understanding of reservoir heterogeneities and boundaries, and is the central theme of this paper. Additionally, seismic data can guide the design of pressure transient tests, especially the test duration to evaluate key seismic anomalies. Other data such as production history, core data, formation evaluation from well logs, analog information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all relevant data, the focus of this paper is primarily on integrating seismic amplitude response with pressure transient test interpretation.
The interpretation of the pressure transient test is done numerically, guided by an initial interpretation of point bar and channel system geometry from seismic attribute analysis. The analysis of the build-up pressure derivative clearly shows the impact of point bar boundaries and connectivity across point bars. For the reservoir evaluated, there was fluid and pressure communication across the point bars, and this was reflected in the transient pressure analysis of the build-up and also from historical production data. The results presented in this paper illustrate the value of integrating geology, geophysics and production data with well test interpretation for a fluvial reservoir.
Production Optimization by Real-Time Modeling and Alarming: The Sendji Field Case
Authors: Danquigny Jacques , DaÏan Renaud , Tison Marc , Herrera Ronald , Ndombi Alain-Serge , Valette Pierre 
Published: December 2007

Abstract
Digital technologies can improve oil production and reduce operating costs. In this prospect, TOTAL launched a corporate program called "Field Monitoring" to capitalize affiliate previous experiences. For gas-lifted wells, it resulted in the development of the "Well Performance Monitoring" (WPM) tool which was implemented in December 2006 at the Sendji field located offshore Congo.
This paper presents the main workflows, functionalities and added value of WPM.
Besides multi-real-time data trends, the application offers colour-coded multi-alarm visualization versus time. These alarms are ranked in terms of "priority" and aggregated at each well, platform, field and asset level, allowing well engineers to track down under-performing wells.
Alarms priority can be linked either to well integrity issues or production losses. These real-time estimated losses are computed using network and well modeling softwares; they highlight deviation from optimum operating set points.
WPM makes easier the regular optimization of gas-lift optimization by feeding models inputs with user-validated real-time data.
A major challenge of right-time production optimization is to sustain updated models; two workflows address this issue: automatic modeling of production well tests and real-time modeling of the actual behavior of the production system. When a significant difference occurs between modeling and reality, a specific alarm is triggered.
The present paper shows various examples of enhanced well performance diagnosis and the corresponding production gains. Also, a good support from onsite teams was achieved thanks to key technical solutions such as user-friendly interface, possible individual tuning of each alarm, handling of unstable or unmatched wells. Finally, WPM enables to compute KPI's that allow the evaluation of potential well interventions.
This tool will be deployed at corporate level, and extended to ESP lifted wells, gas injectors or producers and to subsea wells in deep offshore environment. The general alarming, interface features and data architecture will be applied to surface equipment monitoring and optimization.
Reservoir Flow Simulation Using Combined Vorticity-Based Gridding and Multi-Scale Upscaling
Authors: Mahani H. , Ashjari M. A. , Firoozabadi B. 
Published: December 2007

Abstract
A novel technique for upscaling of detailed geological reservoir descriptions is presented. The technique aims at reducing both numerical dispersion and homogenization error, generated due to incorporating a coarse computational grid and assigning effective permeability to coarse grid blocks respectively. In particular we consider implicit-pressure explicit-saturation (IMPES) scheme where homogenization error impacts the accuracy of the coarse grid solution of the pressure equation. To reduce the homogenization error, we employ the new vorticity-based gridding that generates a nonuniform coarse grid with high resolution at high vorticity zones. In addition, to control numerical dispersion, we use Dual Mesh Method (DMM), which uses different grids to solve pressure and saturation equations. The coarse grid generated from vorticity is used for computation of pressure and the reference fine grid is used for updating saturation explicitly. The most strong point of the method is that dual mesh method has been incorporated onto non-uniform grid structure. This combination removes the need to solve the full fine grid for two-phase flow modeling, resulting in a less computationally demanding and more accurate upscaling technique. To evaluate the method, we run two-phase simulation using different 2D test cases. Our results indicate that the non-uniform DMM is more accurate than the uniform DMM due to using vorticity-based grids. The speed-up achieved in the computation is significant depending on the complexity of model and degree of upscaling.
Dry Gas Reinjection in a Strong Waterdrive Gas-Condensate Field Increases Condensate Recovery—Case Study: The Sleipner Ty Field, South Viking Graben, Norwegian North Sea
Authors: Eikeland Kjersti M. , Hansen Helga 
Published: December 2007

Abstract
The Sleipner Øst Ty Field is a strong waterdrive gas condensate field, with in place volumes of 59×109Sm3 gas and 52×106Sm3 unstabilized condensate. The reservoir consists of deep water turbidite sandstones and associated mudstones, which act as baffles to flow. The reservoir qualities are very good, with high porosity and with permeability in the range of 100 to 1000 mD.
The first production in the area started up from the Sleipner Øst Ty Field in 1993. The initial reservoir pressure of 244 bar was only one bar above the dew-point pressure. Massive dry gas reinjection started in 1996, and the reservoir pressure increased during the next two years causing an increase in the condensate to gas ratio. During the injection period, which lasted until 2005, 29×109Sm3 of dry gas was injected. The main focus during these years was to obtain good vertical and areal sweep of the dry gas in order to vaporize the dropped-out condensate. Chemical gas tracers were injected and analyzed for in the production wells to monitor the movement of the dry gas through the reservoir. This knowledge was used to identify unswept areas, and to change the drainage pattern by doing well interventions and drilling infill wells.
The injection was stopped primarily due to high probability of trapping gas. Compositional reservoir simulation showed that from 10 to 20% of the injected dry gas volume could be trapped in the northern region, which has no producers. The risk of not being able to back-produce the injected dry gas was considered high, since the saddle area separating the producers in the south from the injectors in the north was partly water flooded.
The gas cycling programme has increased the condensate recovery factor substantially; from the originally planned 50; by pressure depletion, to the current estimated ultimate recovery of 81;. At present, the condensate recovery factor is 76;.
Scale Milling and Nipple Profile Recovery with Electrical Wireline—Case Histories from Successful Operations in the North Sea
Authors: Mcinally Gerald , Osaland Espen , Iden Kjetil Systad , Halvorsen Knut Hille 
Published: December 2007

Abstract
During the last decade, wireline tractors have replaced coiled tubing or snubbing for the conveyance of wireline logging and intervention equipment into horizontal or highly deviated wells.
Based on this trend towards lighter and more mobile intervention methods, new techniques and equipment have now been developed to enable PowerTrac Advance (PTA*) wireline tractor technology to deploy rotating equipment such as milling, honing and brushing.
Wells suffering from scale buildup or seal bore damage have been successfully recovered, leading to considerable cost savings compared to conventional methods.
The wireline conveyed rotation technology can be used equally well in vertical pipe sections, as well as in horizontal or highly deviated well bores.
There are operational limitations as to what can be achieved and proper job planning is important to assure success.
Better Reservoir Management through Improved Water-Injection Methods with Data Analysis and Detailed Fracture/Reservoir Modeling
Authors: Jøranson Håvard , Klein Henry H. , Raaen Arne M. , Smith Michael B. 
Published: December 2007

Abstract
The search for practical engineering tools to better manage water injectors has been ongoing for many years. Simple analytical solutions have proven inadequate, and most reservoir simulators do not explicitly model water injectors. This paper proposes a methodology of using detailed and coupled fracture and reservoir modeling to ensure proper injection start-up procedures, and managing injection rates to avoid out-of-zone injection. This is combined with simple rate-pressure data to understand injection behavior, and from that control the process.
Flow through Inhomogeneous Fault Zones
Authors: Soleng Harald H. , Syversveen Anne Randi , Skorstad Arne , Røe Per , Tveranger Jan 
Published: December 2007

Abstract
Faults significantly influence fluid flow in reservoirs. In standard reservoir flow-simulator grids, faults are represented as surfaces or planes. However, outcrop studies show that faults often must be regarded as volumetric elements. Inside such fault zones, the facies characteristics differ significantly from those in the rest of the reservoir. In a fault facies reservoir model faults are represented as volumes populated with facies with properties derived from their origin and faulting history.
In this paper, we compare fluid flow performance of a fault facies model and a conventional fault model. The uncertainties attached to the fault zone properties and architecture included in the fault facies model produce a straightforward effect on the range of simulation outcomes and uncertainty of production parameters. In the conventional model, similar effects can only be reproduced ad hoc using poorly determined random fudge factors. We also look at the effect of upscaling the fault zone. Results show that the flow properties in the fault facies model differ from the conventional model with regard to both water cut and total oil production. As expected, upscaling may introduce a significant bias in the cumulative oil production.
Creating a Great Place To Work: The Result of Clear Strategy and Leadership Development
Authors: MacDonald Sue , Horgan Mike , Gomersall Sam , Brown Margaret 
Published: December 2007

Abstract
In August 2005, Marathon Europe set a clear forward vision and strategy, building upon a rich history and addressing long term direction for the Europe business unit (EBU). To support the implementation of this strategy and to ensure an appropriate focus on our people, five areas of focus, or Pillars, were created: Leadership, People, Values, Delivery & Growth.
These Pillars have provided focus and balance in all aspects of our business and served as a communication vehicle. Appropriate investment has been made in softer areas to develop leadership excellence and to support the development of people. A clear strategy has provided balance between short term delivery and long term growth. The management issues involved are not unique to the upstream oil & gas sector and by participating in surveys across industry sectors, we have identified and addressed areas of weakness and built upon areas of strength.
The results have been an increase in employee engagement and significant progress in achieving the long term vision for the EBU. The externally measurable results have included the achievement of 54th position in the cross sector UK Sunday Times top 100 best companies to work for 2007, the Ireland Top 50 best places to work and a staff turnover rate of only 2.6%.
We challenge others to participate in the Sunday Times top 100 and similar surveys, in order to enhance the reputation of the upstream oil & gas sector and to create more organisations which are great places to work.
Well Integrity Management System (WIMS)—A Systematic Way of Describing the Actual and Historic Integrity Status of Operational Wells
Authors: Corneliussen K. , Sørli F. , Brandanger Haga H. , Tenold E. , Menezes C. , Grimbert B. , Owren K. 
Published: December 2007

Abstract
It is important to be able to have an overview of the well integrity at all times. Statoil, Norsk Hydro and Total E&P UK Ltd. therefore joined forces in a JIP with ExproSoft to develop a software application for data collection, handling and reporting of well integrity. The resulting software is called WIMS, short for Well Integrity Management System. A pilot version was installed and tested by the operators’ spring 2007, prior to the release of the final version.
WIMS enables a uniform and structured approach for describing the status and handling of well integrity issues throughout the production phase of a well. This paper discusses the philosophy behind how WIMS handles well integrity information from when the well completion is installed until the well is permanent abandoned. The well integrity data follows the well from it is new, and is continuously updated when a well leak or other well integrity derogations occur. To assist in leak diagnosis, risk assessment and defining corrective measures; test results, continuous pressure and temperature data, annuli top-up and bleed-off data is presented in WIMS. The paper also describes how information is aggregated from well level and summarized to give an overview of the well integrity status for any defined cluster of wells.
WIMS is developed with the input and needs from three different operators, and the paper also includes a discussion of how WIMS will be used by the three operators.
Apart from the need of systemized and easily communicated well integrity data, the success of WIMS is dependant on the implementation process. Very often the implementation process is neglected, and there are numerous examples of failed attempts at introducing new software in the oil and gas industry. The paper shares the experience from the evaluation and implementation of WIMS.
Novel Service Approach Helps Operator Meet European Environmental Requirements, Reduce Waste Generation and Cut Costs
Authors: Marinescu Pavel , Buchner Alexander , Mertin Mario 
Published: December 2007

Abstract
Planning a well nowadays means not only addressing technical issues like trouble-free drilling and reducing formation damage but also seriously considering the amount and type of waste to be generated, local environmental regulations, possibilities and costs for waste disposal, and lastly, cost effectiveness. To achieve all these targets, a novel concept of integrated services program was initiated back in 2001. Since then more than 70 wells were drilled successfully, amounting to more than 500,000 ft and reducing overall drilling waste volumes by more than 35%.
Aligning all fluid-related services has been tried in the past; however, these efforts were mostly targeted at implementing a joint service project management package. Unfortunately, many of these arrangements proved to perform less than optimally. Main reasons were lack of cooperation and conflicting technological/financial interests.
The paper describes the environmental restrictions, their implications on well planning and waste management concepts and the field results of over 70 wells showing the successful implementation and continuous improvement of an integrated service program on a major drilling campaign in Austria from 2001 until 2006. Key Performance Indicators (KPIs) were defined at the beginning of the project, and incentive scenarios were developed. The Integrated Fluids Engineering (IFE) program was designed to include all aspects of drilling fluid management, from mud mixing, to solids control to controlling waste discharge. The project resulted in substantial and sustainable reductions in drilling waste generation while at the same time improving drilling performance through optimized drilling fluid systems, enhanced wellbore cleaning and consistent gauge-hole performance in soft to medium-hard sediments.
The paper also addresses the development of footage cost during the whole project period, supporting the fact that increased service cost does not necessarily result in increased well cost if the associated drilling performance increase can be realized.
Elastoplastic Fracture Model Improves Predictions in Deviated Wells
Authors: Aadnoy Bernt S. , Kaarstad Eirik , Belayneh Mesfin 
Published: December 2007

Abstract
A 10-years research program at the U. of Stavanger has shown why the commonly used Kirsch equation underpredicts the fracture pressure. The reason is that the plasticly behaving mudcake is not properly accounted for. A new elastoplastic model results from this work, and forms the basis for this paper. This model consists of an anisotropic part (the in-situ stresses) and a hydrostatic part (the plastic mud cake). The paper presents the complete models, which has application to all inclined wells.
"Wellbore strengthening" or "wellbore stress cage" are described by the new analytical model. Several cases demonstrate these concepts. Numerous tests in the fracture lab have led to mud design procedures to build a mechanically strong bridge across a fracture. A well was recently drilled using interactive mud design through the lab. The result was a trouble free well giving leak-off value exceeding any other wells in the area.
Several cases will be presented.Calibrating models to measured leak-off data, it is shown that the Kirsch equation severely underpredicts the fracture pressure.
Gas Well Liquid Loading from the Power Perspective
Authors: Dotson B. , Nuñez-Paclibons E. 
Published: December 2007

Abstract
A new perspective is introduced to the problem of liquid loading in gas wells. Gas wells cease producing as reservoir pressure depletes and gas velocity decreases. Below the critical rate, liquids cannot be lifted from the wellbore and instead, settle to the bottom. At this point, we apply artificial lift, which involves either the better use of the remaining reservoir energy, or the addition of external energy.
The objective of this study is to understand the appropriate application of external energy to maximize economic recovery. Our research was conducted in two stages. First, we modeled a simple synthetic gas well and simulated the liquid loading behavior. We observed the natural ability of the reservoir energy to carry the produced fluids to the surface, and then eventually, declining production with increasing liquid accumulation. Second, we performed a sensitivity analysis of the well's energy (i.e. siphon or velocity tubing strings) versus adding energy to the well (i.e. gas lift injection and downhole pumps) for production optimization at each point in the depletion of the well. We used the theoretical power as a proxy for well operating cost to calculate the economic limit.
As expected, ultimate recovery was improved by the addition of external energy. In particular, pumping was found to be favored over gas lift because it provided lower bottomhole pressures and required less power.
This new power perspective provides a systematic way to evaluate deliquification options through the depletion of a well.
In-Situ Density and Viscosity Measured by Wireline Formation Testers
Authors: O'Keefe Michael , Godefroy Sophie , Vasques Ricardo , Agenes Anne , Weinheber Peter , Jackson Richard , Ardila Mario , Wichers Wich , Daungkaew Saifon , De Santo Ilaria 
Published: December 2007

Abstract
A downhole density-viscosity (D-V) sensor is introduced that provides a real time direct measurement of in-situ density and viscosity at reservoir conditions using a wireline formation tester (WFT). The new fluid measurements are obtained during open-hole sampling of reservoir fluids, or alternatively through fluid profiling where downhole fluid analysis (DFA) is performed at a number of depths to characterize the reservoir fluid properties at a vertical resolution much higher than traditional samping methods.
The utilization of these new measurements are outlined, to illustrate the emerging importance of quantifying fluid variations in real time. This leads to more complete reservoir understanding, resulting in better decisions regarding field modelling, facilities planning and production strategy.
An overview of the D-V sensor is presented together with specifications, and extensive laboratory testing is discussed to show validity of the measurements. Five case studies from around the world are examined to show different applications of this measurement in a wide range of environments.
Fluid density and viscosity have long been primary objectives of formation evaluation, as they bear significant impact on field production and economics. The ability to measure true fluid density and viscosity of formation fluids in-situ at reservoir conditions, is a major advancement for reservoir fluid characterization.