bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Approach for Assessment of Water Holdup in a Multilayer Carbonate Reservoir
Authors: Abdelmawla A. , Dabbouk C. , Urasaki D. , Ateeq B. , Kutty A. R. 
Published: December 2007

Summary
This paper gives a Field case history of a giant multilayer carbonate reservoir located offshore Abu Dhabi. This reservoir has field-wide lower permeability Stylolite layers between the main producing zones. Interestingly, some water hold up phenomena has been observed above Stylolite layers which gives doubt on the degree of vertical communication between the different reservoir producing zones (Fig. 1). This phenomenon can be related to the negative capillary forces in the oil wet reservoir rock and/or the vertical permeability across the Stylolite layers.
An integrated approach is given for the evaluation of water hold up by investigating both the vertical transmissibility across the Stylolite layers throughout the reservoir and the capillary forces due to oil wetting characteristics of the carbonate rock. The results of different methods for evaluation of the vertical permeability (Kv) will be given. These methods include: laboratory results from whole core vertical permeability (Kv) measurements at reservoir conditions using brine, multi-well vertical interference tests (VIT), single well VIT across the stylolite layers combined with MDT/RFT data, specially designed tracer injection tests in dual injector/producer well, and estimations from transient well test data for horizontal wells. Laboratory measurements of capillary pressure at reservoir conditions will also be shown explaining its role in water hold up.
The results from a simulation sector model study will be presented for assessment of vertical communication through Stylolite layers by integrating different sources of data. This study quantifies the effect of Kv uncertainty on the expected field performance.
Case History of Cost Reduction Optimization Efforts in a Mature Field
Authors: Van Gisbergen S. , Kumar S. , Harris J. , Al-Barwani B. , Himawan E. 
Published: December 2007

Abstract
Application of technically sound well and reservoir management (WRM) principles together with cost reduction measures utilising the latest technologies are the key to maximising economic recovery from mature reservoirs. The fields are in one cluster in Petroleum Development Oman. More than 250 major well entries are executed each year. The main measures that are applied to improve production and reduce costs are: integrated reservoir surveillance plans, better sequencing of the workover units, muli-disciplinary input to workover proposals, ESP monitoring and the introduction of new technology such as one-rig-up coiled tubing for cleanout, saturation-logging, perforation & stimulation. Together these processes have reduced well intervention costs by 20% and increased net oil gains by 10%. This paper aims to demonstrate that the application of intensive WRM techniques and appropriate technologies can reduce the unit cost for well interventions.
Grid and Streamline Models: Comparative Study Related to the Production History of Fractured Carbonate Reservoir
Authors: Anissimov L. , Kilaykov V. , Chizhov S. 
Published: December 2007

Abstract
The Upper Devonian carbonate reservoir characterization of the Pamyatno-Sasovskoe Oilfield, Volgograd Region, Russia, is based on geological data, geophysical log, hydrodynamic and tracer investigations. The reservoir model based on geostatistical techniques with grid blocks has been used to update a flow simulation to available data on production history. The reliability of this reservoir model is lower because of the match to available data is unacceptable. The method to model permeability on the coarse scale presents the combination of the borehole radon indication and tracer investigation. According to tracing results, a streamline-based model is to be most realistic, gives a basis to propose the parameters and properties of streamlines and to predict the water-cut process.
Visualization Experiments on Immiscible Gas and Water Injection by Using 2D-Fractured Glass Micromodels
Authors: Shariatpanahi S. F. , Dastyari A. , Bashukooh B. , Haghighi M. , Sahimi M. , Ayatollahi S. S. 
Published: December 2007

Abstract
Two series of flow visualization experiments were carried out to examine the behaviour of immiscible gas injection and water flooding in two-dimensional porous micromodels with fractures at various orientations. One main objective of the study was to test the validity of several contradictory speculative theories that have been proposed in the past in order to explain oil recovery in fractured reservoirs, produced as the result of gas injection or water flooding. All tests were performed under water-wet condition at various injection rates of immiscible gas and water. Our experiments indicated that the average of the maximum oil recovery obtained by immiscible gas injection is about 60%, while it is about 75% by water flooding. The experiments also suggest that, the average oil recovery during gas injection is a strong function of the fracture orientation, whereas the recovery by water flooding is not very sensitive to fracture orientation.Gas injection at rates higher than the free-gravity drainage rate results in displacement fronts that are not stable. The instability is caused by viscous fingering (channelized transport) of the displacing gas through the oil.
Evaluation of Multiphase-Flow Correlations for Gas Wells Located Off the Trinidad Southeast Coast
Authors: Persad Shelley Lucy 
Published: December 2007

ABSTRACT
Multiphase flow correlations are used to determine the pressure losses incurred as a result of fluid flow through pipe.This evaluation is necessary since energy is ultimately lost as a fluid moves through pipe.These losses are incurred due to frictional losses, acceleration and the effects of the fluid weight for vertical flow. The predicted vertical tubing pressure drop for twenty-three (23) gas wells, using fourteen (14) multiphase flow correlations, were compared to measured field data.The results were analyzed to determine suitability and accuracy for varying reservoir and fluid characteristics such as gas rate, condensate gas ratio (CGR), water gas ratio (WGR), tubing size, age and angle of inclination for three Trinidad southeast coast gas fields; Field A, Field B and Field C.These fields are owned and operated by bp Trinidad and Tobago LLC.A total of two hundred and eighty (280) well tests were used for the analysis and this amounted to 3920 data points.
The results obtained showed that none of the correlations used to predict the tubing pressure losses perfectly matched the measured field data.The percentage error (pressure) was calculated and together with other criteria, was used to recommend which of the correlations would be most appropriate for use in each of the three fields under specific conditions. The analysis conducted showed that the Gray correlation met all the specified criteria and is the recommended correlation to be used in all fields.

INTRODUCTION

Background
The calculation of the pressure drop in gas wells is important for cost effective design of well completions and production optimization.Since none of the predictive multiphase flow correlations accurately predicts the pressure drop for all fields inclusive, it is essential that the analysis for best fit be done on a field-by-field basis.This study summarizes the findings when these multiphase flow correlations were analyzed for three Trinidad southeast coast gas reservoirs.The parameters of the wells used in this study, in some instances, far surpasses the range of parameters used to develop the correlations and also in similar past studies.
The three fields are located approximately 40 miles off the south east coast of Trinidad.The fields are part of the Columbus basin and the reservoirs are comprised of sands, which were formed from the Orinoco Delta deposits.
Efficient Evaluation of a Fractured Reservoir in the Syria Kurrachine Dolomite—A Case Study
Authors: Maretic S. , Trgovec-Grief N. , Žirkovic M. , Kenawy A. , Hook P. 
Published: December 2007

Abstract
Efficiently identifying and evaluating the producibility of fractures after drilling through potential reservoirs remains a challenge to both the oilfield operator and explorationist.Timely identification of features crossing the drilled borehole, indication of feature permeability, and testing of the well at the most promising depths with the drilling rig still on location are the keys to cost-effective development of tight and fractured reservoirs.
The Kurrachine Dolomite formation in central Syria is of Middle Triassic age and has low primary porosity.Economical production from Kurrachine reservoirs is therefore highly dependent on the drilled wells encountering zones of permeable secondary porosity.
This paper presents a field example demonstrating the success of wireline-conveyed services in evaluating the producibility of the Kurrachine Dolomite. The services involve the latest technology sensors for petrophysical formation evaluation, electrical imaging of the borehole to evaluate the depths of electrically conductive features crossing the hole, acoustic measurements to evaluate the relative permeability of the conductive features, and testing of the depths of interest by sampling, pressure measurement, and real-time formation fluid analysis.Analysis is presented to show which wireline measurements are particularly important to the operator in this environment.The paper presents techniques successfully implemented to overcome the challenges in formation pressure evaluation and fluid sampling of the Kurrachine formation.
Because the formation is accurately evaluated in real time with the drilling rig on location, the combination of services permits efficient, cost-effective decision making for development of Kurrachine Dolomite reservoirs.
A New Production Logging Tool Allows a Superior Mapping of the Fluid Velocities and Holdups inside the Well Bore
Authors: Dandarawy H. , AlMutairi A. , Abdouche G. , Khedr O. , Elkadi A. 
Published: December 2007

Abstract
Drawing the flow profile of the three phases (oil, water and gas) downhole is the ultimate goal of production logging. However the flow regimes that develop inside the well bore can be very complex (e.g. stratification, mist, annular, recirculation, etc) and the mapping of the fluid velocities and holdups inside the well bore is key to the proper evaluation of the individual phases flowrates at every depth level along the survey interval.
The mapping ability of the present production logging tools is somewhat limited; consequently difficulties are encountered when interpreting data sets that were acquired in such complex downhole conditions at the present time.
Flow Scan Imager is a new tool which comprises five mini-spinners, six electrical and six optical probes that get deployed downhole once the tool is across the survey interval. Each mini-spinner will evaluate the localized fluid velocity that is passing by it, whilst each electrical and optical probe will respectively evaluate the localized water and gas holdup that prevail around its place. When deployed, these sensors will be positioned in such a way that their measurements will constitute a map of the fluid velocities and holdups along a vertical cross section of the well bore at every depth level thus enabling a superior estimation of the individual phases flow rates in complex flow regimes downhole.
The use of this tool in deviated and horizontal wells will undoubtedly enable the users to better understand their production regimes, to define a more accurate flow profiles and consequently plan more efficient remedial works or production strategies, which will inevitably improve their ultimate hydrocarbon recovery.
Designing Effective Sand Control Systems to Overcome Problems in Water Injection Wells
Authors: Sadrpanah H. , Allam R. , Acock A. , Norris M. , O’Rourke T. , Murray L. R. , Wood D. J. 
Published: December 2007

Abstract
This paper provides guidance for selecting and designing optimum sand control systems for water injector wells. This guidance is based on a detailed study on issues and problems in water injection wells in the Foinaven field operated by BP.
Given openhole, stand-alone screen failures experienced on two Foinaven water injector wells, a water-injector sandface-completion study was commissioned with the following objectives: to review the issues and problems in water injector wells, propose possible solutions, and conduct engineering designs for water-injector sandface completions listed below.
Cased and perforated Openhole stand-alone screens Openhole gravel packs Openhole frac packs Cased hole frac packs Expandable screens
The paper summarises possible causes of sand control failure in the Foinaven field water injection wells and provides potential mitigations by selecting solutions using conventional and innovative technology.
Determination of WAG Ratios and Slug Sizes Under Uncertainty in a Smart Wells Environment
Authors: Esmaiel T. E. H. , Fallah S. , van Kruijsdijk C. P. J. W. 
Published: December 2007

Abstract
Smart well technology (down-hole measurement and control) has progressed significantly over the last few years. Previous research has concentrated on the application of the technology to secondary recovery[1,2,6]. This study aims to advance the technical application to tertiary recovery concentrating on WAG processes. The primary operational problem cited in literature is early breakthrough in production wells. This makes it potentially a prime candidate for smart wells based on initial success with smart wells in mitigating early water breakthrough.
A 3-D 3-phase compositional reservoir simulation model with smart wells is implemented in a commercial reservoir simulator. The goal is optimization of the global sweep efficiency under economic constraints through the control of the injection size of each slug, and the controlled injection rate of each well segment along the wellbore under uncertain geological and fluid parameters.
The WAG process is sensitive to reservoir, fluid, and economic parameters which justifies the need to quantify the uncertainty in production and associated risk involved. Gradients are determined through perturbation of the forward simulation.The gradients provide optimal control settings for the injection and production settings of each well. This study demonstrates the feasibility of creating a response surface proxy model, using experimental design and analysis, to facilitate Monte Carlo simulation, uncertainty analysis and screening of performance forecasts.
The proxy model is several orders of magnitude faster than a simulation run allowing a statistical analysis of the uncertainty. Initial results on this model show significant improvements over an uncontrolled WAG production in optimizing the initial WAG and smart well production settings under uncertainty.
Reservoir Connectivity Analysis – Defining Reservoir Connections and Plumbing
Authors: Vrolijk P. , James B. , Myers R. , Maynard J. , Sumpter L. , Sweet M. 
Published: December 2007

Abstract
Gas, oil, and water fluids in channelized or faulted reservoirscan create complex reservoir plumbing relationships. Variable hydrocarbon contacts can develop when some, but not all, fluids are in pressure communication. Reservoir Connectivity Analyis (RCA) is a series of analyses and approaches to integrate structural, stratigraphic, and fluid pressure and composition data into permissible but non-unique scenarios offluid contacts and pressures. RCA provides the basis for fluid contact and pressure scenarios at all business stages, allowing the creation of fluid contact and segmentation scenarios earlier in an exploration or development setting, and the identification of by-passed pays or new exploration opportunities in aproduction setting. Combining conventional structural and fault juxtaposition spill concepts with a renewed appreciation of fluid breakover (contacts controlled by spill of pressure-driven, denser fluid, like water over a dam) and capillary leak (to define the ratio of gas and oil where capillary gas leak determines the GOC), we define permissible but non-unique scenarios of the full fluid fill/displacement/spill pathways of ahydrocarbon accumulation comprised of single or multiple reservoir intervals.
This new analytical approach has been used in a wide range of reservoirs, including clastic (from fluvial to shoreface to deepwater) and carbonate reservoirs, in fields around the world.RCA models have been used to predict fluid contacts in faulted reservoirs where other approaches failed, to locateby-passed pay opportunities for in fill drilling in mature fields,and to condition connections in reservoir simulation models. RCA is an integrated technology that challenges the interpreter to evaluate and incorporate fluid property, composition, and pressure data with stratigraphic and structural interpretations of a reservoir to achieve a deeper, more comprehensive understanding of reservoir compartments and the connections between them.
GTL Update
Authors: Apanel G. 
Published: December 2007

Abstract
Proven world natural gas reserves, which currently exceed 5,000 trillion cubic feet (TCF), have been growing at a faster rate than proven oil reserves. These gas reserves currently represent over 83% of the energy equivalence of proven oil reserves, of which about 75% is considered to be the less desirable heavy crude. In some remote locations, wellhead costs of natural gas have been estimated to be below $0.25/MMBtu, while the cost of reinjecting "associated" gas from crude oil production as an alternative to flaring may greatly exceed its value. About 3,000 TCF of such gas reserves is considered to be "stranded"; i.e., accessible by drilling but located too far from potential markets for economical transportation to those markets.
The chemical conversion of methane to liquid fuels and other higher value products or derivatives which may be more cost effective to transport long distances from remote gas sources has therefore attracted renewed interest. Even though Fischer-Tropsch (FT) synthesis is a technically proven gas-to-liquids (GTL) technology, the conversion of natural gas to liquid fuels such as diesel and gasoline as opposed to higher value chemical products such as chemical grade methanol has only relatively recently been perceived to be a potentially viable commercial proposition. Recent advances in FT synthesis technologies, particularly with regard to natural gas reforming and catalytic partial oxidation, coupled with anticipated increased demand for "clean" diesel fuel appear to be enhancing the economic viability of this route to GTL.
The focus of this paper is the prospective economics of promising technologies for FT based GTL diesel production.The scope of this paper includes a brief discussion of potentially important new developments which could have a significant impact on GTL process economics.
Using Coiled Tubing Equipment to Run Complex Jointed Tubing Velocity Strings
Authors: Rignol J. , Krepa J. -M. , Hogan E. , den Besten H. 
Published: December 2007

Abstract
The cost of remedial work on marginal gas wells suffering from water unloading problems can be prohibitive, especially in an offshore environment. The expected financial return often does not justify the rig costs associated with pulling and running a new completion, while the formation damage caused by many well-killing methods can reduce the production potential of already marginal wells.
A Coiled Tubing velocity string can often prove a quick and cost-effective method of assisting in water unloading. The ability to work in live well conditions avoids damaging the formation, making it an ideal solution in many cases. However, the limited lifespan of carbon steel strings in corrosive environments calls for a different solution. The next option is often to run and hang off a chrome tubing string with a snubbing unit, which makes running corrosion-resistant tubing in live well conditions possible. However, the higher costs and increased time associated with a snubbing unit reduce its attractiveness.
The unconventional operational procedure of running corrosion-resistant jointed tubing with Coiled Tubing equipment has been used on few occasions to combine the benefits of Coiled Tubing and snubbing interventions. Although generally restricted to relatively short tailpipes, this method has on occasion been extended to running full velocity strings. The limited tensile load capacity of the externally flush threads has limited the length of the string in some cases.
A solution to this problem where a complex string is run in two independent sections has been applied in the field to increase the total velocity string length to 4115m.
The paper discusses the design and execution of the operation where Coiled Tubing and jointed tubing were used as a complex velocity string in order to restore production on a gas well, while retaining the full functionality of the downhole safety valve. Particular attention will be paid to the design of the string, which had to be tailored to remain within the operating envelope of the externally flush thread.
External corrosion of pipelines: What risk?
Authors: Roche M. 
Published: December 2007

Abstract
The paper gives a contribution to the problematic of external corrosion of pipelines. The performance of plant and field joint coatings is detailed and interference between coatings performance and cathodic protection efficiency is evaluated.
Recent failures on a buried onshore 18" refinery pipeline coated with FBE and a buried onshore 18" oil pipeline coated with 3 layer low-density polyethylene and heat-shrinkable sleeves applied over a liquid epoxy primer are presented and commented. The so-called "cathodic protection shielding ef-fect" prevents cathodic protection current to flow to areas submitted to corrosion risk under disbonded coatings.
The most critical zone for offshore pipelines is the transi-tion area between riser thick coatings and atmospheric paint system where accelerated corrosion may occur.