bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Interpretation Method of 4D Seismic for Estimating Steam Chamber Extent
Authors: Tanaka Motonao , Endo Kenji , Nakayama Toru , Onozuka Shigenobu 
Published: October 2009

Abstract
This paper presents a new interpretation methodology of 4D seismic data to determine the steam-chamber distribution generated by the SAGD operation in the Athabasca oil sands. Thin mudstone layers and abrupt changes in facies present difficulties upon SAGD implementation. 3D seismic surveys were conducted in 2002 to aid in understanding of the facies distribution, and in 2006 to evaluate SAGD performance.
Two methods are demonstrated to estimate the steam-chamber areal distribution. The first approach is based on comparison of seismic traveltime maps from the two 3D surveys, and the second method uses the interval P-wave velocity (Vp) from the top to the bottom of the reservoir transformed from the seismic traveltime. We formulated a petrophysical model that expresses Vp as a function of temperature, pressure, and water saturation based on the previous experimental measurements of seismic velocity with oil-sands cores. Scaling factors for Vp reduction were first estimated to adjust the laboratory scale to field scale and distributions of Vp reduction and traveltime changes corresponding to the steam-chamber conditions were calculated.
Vp and traveltime maps that reflect the high pressure and high temperature zones generated by the SAGD process were obtained and distributions of Vp reduction and traveltime were calculated with the petrophysical model in order to decouple composite effects of temperature and pressure. Effects of pressure were assumed to be areally more extensive than temperature effects. By distinguishing high temperature and high pore-pressure zones from low temperature and high pore-pressure zones, the steam-chamber distribution was determined. The steam-chamber distribution obtained by the traveltime approach did not show a very good agreement with the well production performance, while the Vp approach presented consistent results. The bitumen volume in the steam-chamber zone estimated by the new approach was calculated, and compared with the actual bitumen production.
The methodology demonstrated here can be applied to other 4D seismic data at fields under thermal recovery processes.
Flow Assurance Design and Initial Operating Experience from Blind Faith in Deepwater Gulf of Mexico
Authors: Subramanian S. , Price M. P. , Pinnick R. A. 
Published: October 2009

Abstract
This paper discusses the flow assurance design and operating strategies for the high pressure high temperature Blind Faith development located in deepwater Gulf of Mexico. Key fluid property issues identified during the early design stages and appropriate flow assurance strategies adopted to mitigate risks in developing the field will be presented. Design aspects of the subsea insulation systems deployed to support flow assurance will be discussed in detail. An OLGA® model based Flow Management Tool (FMT) was developed prior to field start-up to provide asset team engineers and operators with live information on calculated well production rates, steady state thermal performance of the flowlines with forward looking projections on cooldown times for hydrate management.
Results from initial benchmarking efforts aimed at comparing the flow assurance design against actual subsea system operating performance will be presented. Field observed cooldown data for subsea equipment (trees and manifold) and data relevant to flowline thermal performance will be presented as part of the discussion on benchmarking efforts. Results will be presented from field tests done after start-up to test impact of flow assurance strategies such as LDHI (Low Dosage Hydrate Inhibitor) injection for hydrate mitigation on the topsides water handling system. Lessons learned and best practices from the start-up and early operating phase of the project will be shared.
Experimental and Theoretical Studies of Three-Phase Relative Permeability
Authors: Ahmadloo F. , Asghari K. , Jamaloei B. Yadali 
Published: October 2009

AbstractThe three-phase relative permeability relations define the hydrodynamics of fluid flow in porous medium. These relations are necessary for simulation of various phenomena occurring in the reservoir during various production and enhanced oil recovery (EOR) processes; such as chemical flooding, steam flooding, enhanced gas drives, etc.Despite the availability of a modest number of relative permeability measurements reported in literature since 1941, there is no universally accepted conclusion reached on the shape of the isoperms. Given this scarcity of consistent experimental data, it is difficult to recommend any of the developed predictive models, e.g. empirical, mechanistic, or pore-level, for the estimation of isoperms of each phase under reservoir conditions. This paper presents a review of a wide rage of experimental results reported on three-phase relative permeability and highlights their salient features and distinctive findings. It also provides indepth evaluation of technical achievements in this field. The present study is a useful reference for engineers and scientists interested in modeling of multi-phase flow in porous media, and provides guidelines on the selection of predictive models for generation of three-phase relative permeability isoperms.
Application of Risk Based Inspection to Offshore Facilities
Authors: Poulassichidis Tony 
Published: October 2009

Abstract
The Risk Based Inspection (RBI) process delivers a calculated risk value for each fixed equipment item in a facility. Fixed equipment risk values are the product of the Likelihood-of-Failure (LOF) and the Consequence-of-Failure (COF) factors. The calculated equipment risk values are used to optimize the facility inspection program in accordance with industry best practices (API-580/2002, API-581/2008).
This paper will present the results from a RBI analysis of Gulf of Mexico (GOM) topsides facilities. Requirements for successfully implementing and maintaining a RBI program will be reviewed.
Using the RBI calculated risk values, a fixed equipment relative risk ranking is established that strengthens the facility mechanical integrity program by allowing the operator to:
– set priorities and focus their attention on the critical areas – justify capital investment for lifetime extension projects – proactively address loss of primary containment and process safety issues
In addition to improved mechanical integrity, using RBI as a basis for inspection planning can aid in a cost/benefit optimization analysis of inspection work year over year.
Recent regulation updates require compliance with the API-510 inspection code for production operations in the "outer continental shelf" (30 CFR 250.803.b). API-510 code translates to a time-based inspection interval requirement after a maximum of 10 or 15 years in-service depending on pressure vessel classification. As an alternative to the time-based inspection requirements, the API-510 inspection code allows the use of RBI analysis.
In the case of this particular GOM platform, the RBI analysis resulted in an 80% reduction of the above-mentioned time-based inspection requirements while at the same time ensuring equipment mechanical integrity needs are met.
In conclusion, RBI technology is an intelligent database system compliant with industry best practices for fixed equipment risk management
decision enabler for asset management based on a quantitative data analysis allowing the operator to do the "right thing", focusing on cost effectively reducing operational risk
Experimental Study on High Viscosity Oil/Water Flow in Horizontal and Vertical Pipes
Authors: Vuong D. H. , Zhang H. -Q. , Sarica C. , Li M. 
Published: October 2009

Abstract
The average crude oil produced around the world becomes heavier every year. High viscosity oil multiphase pipe flows are experienced during the production and transportation of heavy oils at normal temperatures or conventional oil at low temperatures. Heavy oil is normally produced with low GOR but considerable water cut due to cognate or enhance oil recovery reasons. Since high viscosity oil-water two-phase flows were not well understood, an experimental study of high viscosity oil-water flows in horizontal and vertical pipes with a 50.8-mm ID has been conducted to investigate the effect of high oil viscosity on flow pattern, pressure gradient and water holdup.
The observations and measurements of flow pattern, pressure gradient and water holdup were obtained over the ranges of oil and water superficial velocities from 0.1 to 1m/s for horizontal and verical upward flows. The pressure was maintained at 2 MPa using compressed Tulsa City natural gas. Non-additive Lubsoil ND 50 was used as test oil and filtered tap water as water phase. Oil viscosities varied from 0.22 to 1.07 Pa·s. The flow patterns and oil-water mixing status were observed through a sapphire window and the images were recorded using high speed and high definition video cameras. The flow patterns were mostly dispersion of oil in water and water layer (DO/W&W) for horizontal flows and core annular flow for vertical flows. Extensive measurements of water holdups and pressure gradients at different superficial velocities, viscosities and inclinations were acquired and analyzed.
A Simplified Subsea Separation and Pumping System
Authors: Håheim Svein , Gaillard Xavier 
Published: October 2009

Abstract
Subsea gas/liquid separation and pumping is an effective means of providing artificial lift for enhanced oil production from subsea oilfield developments. Compared to multiphase pumping the energy efficiency may be improved by a factor of two to four, depending on the water depth. A subsea separation and pumping system is, however, more challenging to operate, as the liquid level in the separator needs to be controlled to ensure a stable liquid feed to the pump. The pump must also either be protected from gas surges or designed to be gas tolerant. For deepwater applications this becomes even more challenging, as compact separation solutions are required, due to the difficulty of manufacturing subsea separators to withstand the high hydrostatic pressure.
This paper describes conceptual design and model testing of a subsea separation and pumping system, using a gas tolerant, Hybrid Helicoaxial-Radial pump. The slug-handling characteristics of the system are discussed, and a control strategy capable of handling any realistic slug size and frequency is described. A key feature is that active subsea control valves are not required, reducing the complexity of the subsea facilities and control system.
The system design and control strategy was verified by model testing. A pressurized air water loop was used, with maximum liquid flow rate of 166 m3/h (25.000 bbl/d) with a gas volume fraction (GVF) at separator inlet of up to 70%. Pump suction pressures up to 30 Bar were used. The testing proved that overall control system response time of 1-2 s is required to handle typical slug frequencies, which is well within the capabilities of present subsea control systems and Variable Speed Drives.
Plunger Lift Dynamic Characteristics in Single Well and Network System for Tight Gas Well Deliquification
Authors: Tang Yula 
Published: October 2009

Abstract
This paper presents a study for plunger lift characteristics to dewater tight-gas wells operated in the Piceance basin of Rocky Mountains with multiple-well pads and surface pipeline network. The wells’ TVDs are about 6000 ft with deviated paths, and the water-gas-ratio (WGR) is 40~80 stb/MMscf. The objective is to understand the optimal operating conditions for reasonably controlling deliquification without severe liquid surge while maintaining maximum gas production.
The IPR and reservoir depletion are based on tight gas model, which considers the transient IPR due to very low matrix permeability, hydraulic-fractures and drainage radius. A transient dynamic multiphase flow analysis has been performed to investigate the plunger lift effectiveness, performance and optimization for different scenarios. Simulation runs were performed for early, middle and late field life which corresponds to different reservoir pressure and productivity index. It shows that liquid loading becomes severe and production becomes unstable (heading) with decreased reservoir pressure and increased water influx. Eventually the well production can stop due to liquid loading. Plunger lift helps to maintain the production and reduce the instability. A network model with 22 wells on a pad has been built to study the interaction of the system and the liquid surge control strategy.
Plunger-lift process for tight gas wells with liquid loading problems needs integrated dynamic modeling for both reservoir and wellbore systems. The philosophy of optimization is that, the reservoir and wellbore system should be the "master" for production optimization, and surface control should serve as a "slave" system.
Control-Relevant Selective Grid Coarsening
Authors: Vakili-Ghahani S. A. , Jansen J. D. 
Published: October 2009

Abstract
From a system-theoretical point of view there are only a limited number of degrees of freedom in the input-output dynamics of a reservoir system. This means that, for a given configuration of wells, a large number of combinations of the state variables (pressure and saturation values) are not actually controllable and observable from the wells, and accordingly, they are not affecting the input-output behavior of the system. In an earlier publication we therefore proposed a control-relevant upscaling (CRU) methodology that uniformly coarsens the reservoir model based on the relevant level of information and control. Here we present a selective (i.e. non-uniform) grid coarsening method to allow treatment of very large models with high degree of heterogeneity in their parameter fields. In this control-relevant selective coarsening (CRSC) method, the criterion for selective grid size adaptation is based on the controllability and observability properties of the reservoir system; hence we selectively coarsen only the weakly controllable and observable parts of the model. The CRSC method is particularly attractive for use in flooding optimization or history matching studies for a given configuration of wells. We applied our algorithm to two numerical examples and found that the CRSC algorithm can accurately reproduce results from the corresponding fine-scale simulations, while speeding up the simulation.
All-in-One Concept with Expandable Tubular and Swellable Elastomer Technology—A Systems Approach to Well Design
Authors: Young Ifeh , Ekeigwe Austin , Alabi Tunde , Oluwatosin Adedeji , Obanya Phillip 
Published: October 2009

Abstract
GU field high rate gas campaign was selected by management as a pace setter project to deliver NAG to the Nigerian LNG trains project as part of the overall strategy of implementing the revitalized performance improvement initiative in Nigeria. To deliver top quartile performance at lower unit technical cost without compromising on safety and sustainable community development, an innovative well design philosophy with game changer technology was proposed.
The approach utilized a number of innovative techniques; slim well design with 2-casing string philosophy; 1-skin strategy and casing flow design. The 9 5/8" string acted both as the surface and production casing with the shoe above shallowest hydrocarbon. The build up, landing and drain section was drilled in a single trip through several unstable and reactive shale sections hence the "all-in-one approach". The 7" production liner was combined with 5 ½" expandable sand screen lower completion in a single trip. The 5 ½ Expandable Sand Screen was compliantly expanded to the 8 ½" drain hole.
Unlike previous concepts where zonal isolation was provided with cement, zonal isolation was provided with swellable elastomers bonded and spaced out on the 7" production liner. GU-11ST well was successfully completed as a single string single gas producer with 7" 13 Cr completion tubing.
The well tested to a facility-limited rate of 52 MMscf/d with FTHP of 3423 psig and condensate rate of 3900 bbl/d psi. Extrapolated well test results showed that the well can produce at 120 MMscf/d at a draw down of ca. 18psi; with extra swing capacity to go up to 160 MMscf/d when required. Several well testing challenges were addressed during the cleanup and flow period.
The systems approach on well design in GU-11ST resulted in lower unit technical cost compared to other wells in the campaign. It has also proven to be a future enabler to implementation of the small location concept with light and less expensive rigs without compromising safety and well objectives.
Modeling of Complex Fluid Systems in Gimboa Field Block 4: An Offshore Field in Angola With Biodegraded Heavy Oils
Authors: Yang T. , Mengel F. , Lannotta A. , Lazary J. , Mouzinho E. 
Published: October 2009

Abstract
The Gimboa Field, which came on stream from April 2009, has produced different reservoir fluids compared with the fluid initialization model developed before production. The early exploration well only discovered highly biodegraded heavy oils (low API) in the field. Although some normal black oils (high API) were initialized in some reservoir segments based on the fluid samples taken during drilling of injection wells, the existence of large amount of non-biodegraded black oil had been underestimated before starting of production.
The EOS fluid characterization was developed with good accuracy for limited initial reservoir fluid samples. All the initial reservoir fluid samples were taken from the same geological region. This made it difficult to have a reliable estimation of fluid distributions in other reservoir regions. Different ways to initialize the reservoir fluids have significant impacts for estimation of reservoir fluid in place, the expected drawdown pressure between the water injection wells and the producing wells, water injection speed and volume, the required gas handling capacity and finally the recovery factor.
Drilling of water injectors and producers provided an opportunity to collect more reservoir fluid samples from other parts of the reservoir. Integration of available PVT, pressure gradients, and geochemistry data from the Gimboa Field provided an updated estimation of the reservoir fluids in different reservoirs. An API tracking black oil model has been selected to describe lateral fluid variation. Uncertainty is discussed as a lesson learned from this field for the later design of sampling programs for similar fields.
This paper provides an insight into the importance of fluid initialization for compositional varied reservoirs. Integration of multidiscipline data is an efficient way to reduce uncertainty in fluid initialization.
Analysis of Production Decline in Waterflood Reservoirs
Authors: Yang Zhengming 
Published: October 2009

Abstract
Despite the widespread application of reservoir simulation to forecast waterflood performance, petroleum engineers still need simple production decline analysis methods to forecast oil production and estimate ultimate oil recovery from the production history data.
For pressure depletion recovery processes, Arps proposed an empirical model and Fetkovich validated the Arps model based on the transient and semi-steady state solutions. However, for waterflood reservoirs, reservoir pressure is generally maintained and oil production decline is mainly due to the reduction of oil saturation and oil relative permeability.
This study explains the inconsistencies when the Arps production decline model is used as a framework to forecast the waterflood recovery process. An analytical oil production forecast method specifically for waterflood based on the Buckley-Leverett theory has been developed. This study compares forecasts by the new method with field performance data and reservoir simulation results. These comparisons demonstrate the straightforward, convenient and accurate application of the new forecast method for waterflood reservoirs.
Determining Reservoir Properties and Flood Performance from Tracer Test Analysis
Authors: Shook G. Michael , Pope Gary A. , Asakawa Kazuhiro 
Published: October 2009

Abstract
In the last several years a variety of new tools for interpreting interwell tracer tests have been developed. The new methods are based on residence time distributions of the tracer, where much of the previous work used only the mean residence time. Using the distribution of residence times extends the power of moment analysis by allowing for the determination of reservoir properties and flood performance as a function of time. Flow geometry and construction of flow capacity - storage capacity diagrams also follows directly from the analysis. Swept volume vs. time, and sweep efficiency are also determined from the residence time distribution, as is remaining oil saturation. One important key to these new methods is our use of the integrated tracer recovery histories. Estimating residual oil saturation is greatly simplified by our mathematical treatment of slug tracer injection. Examples are presented that show improved saturation estimates even at early times in a tracer test.
This paper describes the new analysis methods developed recently and shows by comparisons with analytical and experimental data that the methods are accurate and robust. The method is simple and can be done with a spreadsheet using only produced tracer concentration data; it does not require a reservoir model or numerical simulation. The equations are derived from first principles for a very general case that includes both conservative and partitioning tracers produced from any heterogeneous reservoir.
Isolation Valve Contingencies Using Wireline Stroker and Tractor Technologies
Authors: Schwanitz B. 
Published: October 2009

Abstract
With today's high rig operating costs, identifying areas where new technology can be used to improve efficiency and reduce rig-time is critical to many a project's financial success. In deep water regions, new intervention solutions that are not rig dependent are especially desirable. Electric wireline deployed interventions have been shown to offer both technical and financial benefits in mechanical manipulation of downhole hardware, such as isolation valves, in that they are faster to mobilize and execute, saving the operator several days in rig-time and deferred production compared to pipe conveyed methods.
Many deep water completions use down hole isolation valves for temporarily closing off production while awaiting flowline connections for first oil. These isolation valves can be shifted open or closed through surface commands while a backup (contingency) allows the valves to be mechanically shifted. Failure of these valves can result in expensive delays to production with large rig time costs to intervene.
Operators in the Gulf of Mexico, West of Shetland and West Africa have been pioneers in the application of wireline conveyed mechanical solutions for isolation valve contingencies. The contingency consists of an electric wireline hydraulic stroking tool to shift the sleeve open or closed. The wireline stroker is either wireline tractor conveyed in high angles or run with only the shifting tool attached in low angles. A new intelligent shifting tool is also available for opening and closing valves on command to avoid hang ups on downhole profiles that may occur with the conventional spring-loaded shifting tools.