bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wetting Fim Effects on Steady-State Two-Phase Fow in Pore Networks using the DeProF Theoretical Model
Authors: Vaavanides Marios S. , Payatakes Alkiviades C. 
Published: December 2007

Abstract
The motion of oil ganglia and droplets in chamber-and-throat pore networks in two-phase flow in porous media can be modeled without or with wetting films. The existence of wetting films around ganglia and droplets is favored by small contact angles (say, smaller than ca. 10 deg) and wall roughness.
The predictive model DeProF (Decomposition into Prototype Flows) considers steady-state two-phase flow in porous media as a composition of three flow patterns, namely connected-oil pathway flow, ganglion dynamics and drop traffic flow. The key difference between these prototype flow patterns is the degree of disconnection of the non-wetting phase (‘oil’) which, in turn, affects the relative magnitude of the rate of energy dissipation caused by capillary effects compared to that caused by viscous stresses. The observed flow is usually a mixture of the basic prototype flows.
In the present work DeProF is used to investigate the effect of the wetting film on two-phase flow in typical 3-D pore networks by including wetting films around droplets. The effects of the wetting film are assessed by comparing the values of key physical characteristics of two-phase flow, specifically, the interfacial area per unit volume, the mechanical power dissipation p.u.v., the degree of disconnectedness of the non-wetting phase, and the energy utilization factor, which are obtained with and without wetting films.
Two Generations of Thermal Decay Tools: A Comparison in a Common, Friendly, Borehole Environment
Authors: Boyd Doug , Al-Hendi Ahmed , Al-Farisi Omar , Okuyiga Moyo 
Published: December 2007

Abstract
Abu Dhabi National Oil Company (ADNOC) and its group of companies completed a review of logging practices in Feb. 2000.1 A recommendation was made to compare PNC tools in a properly characterized well under controlled conditions. This report addresses that recommendation by comparing the accuracy, repeatability and reproducibility of two new and two older generation PNC tools currently available for field monitoring in Abu Dhabi reservoirs. Tools are compared against each other and to core measurements. Elemental analysis of core and reservoir condition fluids provided the benchmark for formation capture cross-section comparisons. One tool displayed much poorer statistics than the other tools. All tools suffered from large inaccuracies in their auxiliary porosity measurements. Reproducibility was good for sigma measurements but poor for porosity. Three of the four tools are acceptable for qualitative field monitoring operations. Two of the tools are preferred for accurate residual oil measurement.
How to Manage and Produce from a Low Permeability Zone in a High Permeability Contrast Reservoir
Authors: Talabani Soran 
Published: December 2007

Abstract
The most difficult practice in the oil industry is to displace oil in the low permeability zones in a heterogeneous reservoir. This situation becomes worse when the permeability contrast is high and is hydrocarbon properties dependant. In this study, experiments were conducted to investigate on how to temporarily plug the high permeable zones and flood the low permeable zones within the reservoir. Plugging the high permeability zone temporary is important because fluid segregation might complicate the outcome of production management.
Different permeability contrasts of rock samples were used in the experiments. These experiments were conducted in the presence of one type of oil followed by water injection, while injection fluid properties, quality, injected slug size and velocity were controlled.
Results show that the injection of mixed surfactants-fluid followed by water could stand plugging the high permeability zone and diverting water injection into the low permeability zones. Though, the mixture should be pumped with certain pore volume. Only some specific surfactants-fluid mixture (not used in the oil industry) resulted in stable fluid for the diversion process. When water was followed by the mixture, most of the oil in the low permeability zones were removed and flowed out of the rock. Certain slug sizes were needed in different permeability contrasts. As a result of the experiments, an easy way was observed to predict fluid rate and quality from laboratory experiments before the application in the field. Field application confirmed the lab experiments and higher production rate were managed.
Occupational Health Program - Integrated Medical Information System (IMIS)
Authors: Bakinson Mohiedeen A. A. , Al-Mandhry Ali S. 
Published: December 2007

Abstract
A quality improvement project by the Medical department identified the need of an integrated computerized system to support and improve the Medical department's processes and also modernize the running of the department. GERMS was the proposed Shell Medical information system at the time and it was looked into and found to fall short with the PDO requirements. Third party packages were then evaluated and led to the birth of a customized IT system which was named as Integrated Medical Information System (IMIS).
This paper will describe this system and highlight the Occupational Health Module which has been the bed rock of information for Medical and Health Safety & Environmental reporting in PDO. Further improvement to IMIS is planned to provide facility to monitor and identify staff who not be complying with the recommended frequency of medical examinations, as well as manage health of staff who may have work/location restrictions due to results of medical examinations.
Implementations of New Technologies for Oil and Gas Industry
Authors: Shaker Moh'd Mamdouh , Moh'd Hussain Ali 
Published: December 2007

ABSTRACT
Deflecting Conductor Sleeve "DCS" is a slot recovery tool that proved a valuable system for the economical salvaging of the previously used slots of the offshore platforms in the late development stage. It is used when there is a need to drill infill wells while most of the platforms' slots are already used, and installing new platforms or making extension for the existing platforms are not justified.
Dynamic Surge Device "DSD" is a sub, normally installed below the production packer on the bottom of the completion string acting as a blanking plug to set the packer, test tubing and automatically unload the well without any need to the risky wire line operations.
Lifting Platform "L.P" is a hydraulically operated lift platform to provide additional storage area and to facilitate the movement of heavy equipment while working on the main platform (tower).
Solvent Injector "SI" is developed to clean the gas lift mandrel and valves by injecting only the required volume of solvent around the valve, avoiding unnecessary dripping volumes of the solvent to affect other parts of completion.
Jack-up Mover Assistance "JMA" is a special technique which uses a prefabricated floating concrete breakwater in front of the offshore platforms at the rigs' approach side, providing protections to the rig from waves during jacking up and down at rig approach and move, minimizing waiting on weather time and saving lots of money. The system is still under development.
Back Allocation System with Network Visualization
Authors: Hamad Marwan , Sudharman Satheesh , Al-Mutairi Ali 
Published: December 2007

Abstract
The use of Back Allocation is crucial in the Oil and Gas industry to facilitate accurate allocation of actual production and injection volumes at every node of a production network. Production engineers frequently use back allocation to estimate actual production volumes from wells based on frequent well test data or theoretical calculations using well and reservoir characteristics.
ZADCO implemented an optimized back allocation system to cope with the growing business needs, after a thorough system study of the legacy back allocation system. This presentation will present the considerations that led to this implementation and the project success.
ZADCO is a major operating company in Abu Dhabi operating in offshore fields, and is one of the largest oil companies in the world. Being a highly productive operator, ZADCO needed a back allocation system for apportioning fluids among upstream sources within a production network.
The new system provides a means to visualize complex networks, verify the production streams, track gathering systems functionality through time and derive the allocation networks.
This project has proven to be a reliable and comprehensive back allocation system, capable of providing all the necessary features required for a robust and solid back allocation system.
After the new Back Allocation System became fully operational, ZADCO started to realize the following benefits from this successful implementation. Ability to correctly apportion production, where accurate measurements are not possible or cost effective.Ability to determine fluid flow quantities through every strategic point in the network and determine the production quantities of each well and reservoir for production accounting.Reduced time and effort to setup and execute fluid disposition allocations.Better quality back allocated resultsThe new system optimizes the allocation system workflow, resulting in the routine monthly allocation work being greatly simplified.
Development and Applications of Sustaining Integrated Asset Modeling Tool
Authors: Liao T. T. , Lazaro G. E. , Vergari A. M. , Schmohr D. R. , Waligura N. J. , Stein M. H. 
Published: December 2007

AbstractAn enabling application tool was developed for updating and maintaining Integrated Asset Models (IAM) for production optimization, surface network debottlenecking, and production allocation. The tool automates the routine tedious tasks required to update and maintain large-scale IAM models. Application of this tool in many BP Business Units (BU) consistently resulted in about a 90% reduction in model maintenance and management time, streamlined the IAM model application process, and improved production allocation accuracy. Deployment of this tool in the last few years has brought a step change to IAM model application across asset teams within BP.
Modeling and Validation of Initial Water Saturation in the Transition Zone of Carbonate Oil Reservoirs
Authors: Ghedan Shawket G. , Thiebot Bertrand M. , Boyd Douglas A. 
Published: December 2007

Abstract
The modeling of initial water saturation distribution in simulation models could be achieved by one of two techniques. The upscaling the log interpreted water saturation distribution of the finer 3D geological model constitutes the first technique. The challenge in this technique is to accurately describe the important rather thick transition zone of carbonate reservoirs. A large and non-achievable number of control points (wells) are needed. Rock type controlled restored state oil-brine capillary pressure, Pc, curves is the second technique. This results in an accurate picture of oil reserves providing that the rock types are distributed correctly. Significant numbers of oil-brine Pc measurements are needed however, to address all rock types, wettability, porosity and permeability ranges.
Frequently, not all the necessary Pc curves are available. To fill this gap, reservoir characterization data along with log-derived water saturation, Sw, data are utilized to generate representative Sw-height functions for all rock types of a carbonate oil reservoir. Only cored wells are employed, ensuring the most accurate rock-type profiles. To match the span of Sw at a given depth, sorting by porosity, permeability and reservoir quality index within each rock type is carried out. Describing the large span of log-derived Sw in the transition zone is especially challenging.
The technique assumes the log-derived saturations are correct and emphasize the need for laboratory tests of resistivity indices and cementation factors representative of the dominant rock types for accurate log interpretation.
The attainability of a good matching between the log-derived and the Pc-derived Sw and bulk volumes of water depth profiles for the cored and un-cored wells validated the modeling process. This is supported by statistical analysis and mapping of the water saturations in all layers of the simulation model.
Gel-cement, a water shut-off system: qualification in a Syrian field
Authors: van Eijden Jip , Arkesteijn Fred , Akil Ihab , van Vliet Jacques , van Batenburg Diederik , McGinn Paul 
Published: December 2007

Abstract
Water production in the North-east of Syria has increased significantly in recent years. As a result costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity.
PLT surveys combined with a reservoir study showed that good-quality sands were not properly swept by the water, probably due to poor connectivity in the reservoir. It was anticipated that these un-swept sands could contribute to production if the watered out sands were shut-off.
A newly developed gel-cement has been used to shut-off the watered out sands in a cost-effective manner. The gel-cement system combines the properties of two shut-off techniques: ■Cement for mechanically strong perforation shut off.■Gel for excellent matrix shut off.
The gel, used as ‘mix water’ of the cement, will be squeezed into the matrix creating a shallow matrix shut off. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shut off performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will reestablish the oil production. The shut off zones can be reopened later in the well's life when artificial lift has been installed.
In the first field trial 84 meters of perforations (gross) were squeezed of with the gel-cement in a single attempt. After re-perforation of the top and the middle zone the well produced at a strongly reduced water cut, i.e. 25–33% compared to 60–62% before the treatment, and an increased oil production, i.e. 3000 bopd compared to 1000 bopd before the treatment. The oil production declined to 2000 bopd over a year. The water cut gradually increased over that period to 56%.
Maturing Field: A Case History Offshore Abu Dhabi
Authors: Glière L. , Brun B. , Bure E. , Ryan M. , Jasmi A. Al 
Published: December 2007

Abstract
The field is a very mature field. 30 years after its production start-up, it is now producing with an average water-cut of 84 %.
This paper presents the continuous adaptation efforts deployed throughout the years to further valorise resources, in response to the growing maturity of the field.
Well activation started very early, first through ESP's, then by full field gas-lift implementation. As an answer to an important depletion of some reservoirs, a water injection scheme has been implemented as early as 1979. In 1997, a major field revamping campaign was performed to implement an EOR technique which proved to be very efficient: tertiary gas injection after water flooding. After the first horizontal wells, drilled in 1994, ever increasing well architecture complexity allows now to target more and more precisely heterogeneities, to produce residual oil pockets, and to develop tight reservoirs. A 3D seismic acquired in 1995 has opened the path for quadruple and quintuple multilateral wells.
At the current maturity level, field management appears as the next challenge. The complex gas scheme, which comprises at the same time gas production, gas lift, gas injection, gas recompression and gas export, needs constant arbitration between activation gain and tertiary recovery.
In parallel, a global water management policy must be set up, as the water disposal network is more and more heavily loaded. A water management study is currently under the way, to review long term fluid production predictions, surface facilities limitations, and long term reliability of disposal well, and to screen for solutions, ranging from reservoir and well control to surface facilities de-bottlenecking.
Re-Birth of a Mature Carbonate Gas Pool
Authors: Carr K. C. , Fiori M. 
Published: December 2007

Abstract
Operation of a mature pool requires increasing cost control and infrastructure optimization and consolidation to maintain profitability. The decision to initiate this type of reservoir management plan, sometimes described as harvest, is driven in part by reservoir performance analysis and in part by commodity prices at the time the decision is made. The impact is not limited to operating cost; it can affect reservoir performance itself and the ultimate recovery of reserves.
This paper presents the account of a 3.7 TCF sour gas pool in Alberta, Canada and the technical impact of harvest on field operations, reservoir performance and ultimate recovery. The combination of new production decline analysis, well work-over with surprising results, and key field observations led to a complete change in reservoir interpretation. A new model emerged where near wellbore regions are deeply damaged and the gas-water contact (GWC) is much lower than expected.
Waterflood Strategy – Challenges and Innovations
Authors: Bibars O. A. , Hanafy H. H. 
Published: December 2007

Abstract
More than thirty years ago, Gulf of Suez Petroleum Company (Gupco) - Egypt, initiated the first waterflood project for El Morgan oil field. The company now operating 14 different waterflood reservoirs. These reservoirs have produced a cumulative oil representing 40% of their original oil-in-place. On average, the projected waterflood recovery factor is 54% of OOIP. Due to non-uniform lithology and non-uniform pattern of existing well locations in most reservoirs, peripheral waterflood was found to be the most suitable and economic waterflood pattern at project startup. Peripheral waterflooding has the advantage that it minimizes the number of injection wells by converting the watered-out producers. As these reservoirs become more mature, the line-drive pattern (peripheral + internal injection) was found to be more effective. Since most of the reservoirs are currently in the mature stage, good managing and close monitoring for each waterflood project is extremely important. This paper presents major strategies in managing the different waterflood projects to maximize both the oil production rate and oil recovery in optimum manners. This is being achieved through several common and familiar waterflood issues including in-fill drilling, zonal injection improvement, injection pattern modification, injection below formation parting pressure, pressure maintenance, workovers for production and injection wells, continuous data collection, and water quality monitoring. The paper also addresses the waterflood side effects such as scale buildup, reservoir souring and facilities corrosion. In addition, the paper discusses some of the innovative techniques that have been used to maximize waterflood recovery and enable waterflooding of marginal fields at a cost effective manner. Examples for these techniques are gas-cap water barrier injection, heavy oil waterflooding, coiled-tube water injection lines, slim-tube dual completions, and satellite waterflooding for pilot and marginal fields waterflooding.
Study of Compositional Processes in Oil Recovery from Andrew Field due to Submiscible Gas Injection
Authors: Mirzaei M. , Khamehchi E. , Clifford P. J. 
Published: December 2007

Abstract
This study is part of a development study to investigate the mid and late life options for the Andrew Field. The focus was placed on the benefit of Compositional Simulation compared to the Black Oil Simulation in predicting the recovery of condensate from gas cap and residual oil in water-invaded area of oil-leg. The impact of converting a former horizontal producer, which has been shut in for a period of time due to high water-cut, to gas injection was considered.
One dimensional (1D) simulation models of the oil-leg were used to ascertain the Minimum Miscibility Pressure (MMP) with injected gas and the nature of displacement mechanism. Different grid block dimensions were used to consider the effect of numerical dispersion on MMP. A pressure of about 6000 psi, significantly higher than current reservoir pressure, would be needed to produce a fully miscible system. A Minimum Miscibility Enrichment (MME) analysis was carried out whereby a conceptual addition of 50:50 mixture of C3:C4 components in terms of molar proportion as NGL was added to the injected gas stream. NGL enrichment of 35% and above results in a miscible injectant at saturation pressure. Strongly vaporising gas drive process dominates in all cases and therefore continuous injection of lean gas will provide sub-miscible displacement of residual oil.
1D Compositional and Black Oil Simulation models of the gas cap region were used to measure the condensate recovery of the gas cap under different possible depletion scenarios. Condensate recovery due to primary depletion is 40% whilst different gas injection plans have resulted in higher condensate recovery, an average around 85%.
Three dimensional (3D) Black Oil and Compositional sector models of a pattern element were used to investigate the benefit of converting a producer to a gas injection well, to mobilize the residual oil in the water-invaded area. Results indicate substantial residual oil vaporization and condensate recovery by Compositional model, which is not predicted by the Black Oil model.
There is reservoir heterogeneity due to the different structural setting and faulting in upper and lower hydrocarbon bearing units. Injecting to upper unit rather than the lower unit maximizes condensate recovery. Residual oil recovery by injecting to the lower unit is higher than the upper part due to higher residual oil saturation to water sweep and larger gas flooded area. This provides an important justification for gas injection, particularly into the lower unit.
Lessons Learned from Static Reservoir Modelling on Complex Carbonate Fields, Onshore UAE
Authors: Gomes J. S. , Ribeiro M. T. , El Deeb M. , Silva F. P. , Bockel-Rebelle M. O. , King R. F. 
Published: December 2007

ABSTRACT
Commercially available software packages used to develop geocellular models are becoming increasingly user friendly. However, workflows for data quality control, modelling procedures and evaluation of results are not always well established, tempting inexperienced users to build 3D models without the necessary rigor. The economical and technical implications of using 3D models on reservoir simulation studies, volumetrics, and field development, on the other hand, are of paramount importance.
The need to adopt methodical and systematic processes during all stages of 3D model building and dynamic simulation is now widely recognized. This paper compiles some key data flow, process flow and quality management practices. It presents the chain of activities in 3D model building and usage, highlighting critical parts of the process, rules of thumb for obtaining quality results, best practices to be adopted, pitfalls in various assumptions and some of the prevalent misconceptions.
Issues addressed include: data analysis; quality control; data density; integration of disparate data types; framework modeling; incorporation of chrono-stratigraphic zonation; fault and fracture modeling; deterministic and stochastic property modeling; depth and property uncertainty analysis; upscaling, downscaling and visualization.
Experience on large and diverse carbonate fields, in a variety of conditions and different stages of maturity, presenting different sets of data types and well densities are combined to present a summary of useful hints and best practices to other professionals involved in doing static modelling. It is emphasized that if data QC, geologic rules, mapping principles and geostatistics are not handled properly, the resulting model will be less precise, regardless of the sophistication of the software and algorithms deployed.