bluuebunny/crossref_metadata_2025_split huggingface dataset:
Kuwait Oil Company Conceptualized & Implemented HSE Traffic Lights for HSE Demonstration & Site Verification
Authors: Al Mansouri Fares , Aftab Alam Mohammad , De La Roche Alberto 
Published: February 2012

Abstract:
The increase in business activities during last decade brought forward several challenges in upstream hydrocarbon industry like KOC which has 40 operational facilities, 65 rigs and around 600 Contractors' worksites. However 5 fatalities within a quarter during 2009-10 was a serious concern that demanded immediate gap analysis focusing most relevant regulatory, procedural & contractual HSE issues compared to actual situation at site. Based on gaps, a unique tool of HSE demonstration & site verification was devised and implemented conceptualizing HSE traffic lights.
Accordingly Site Verification Visits (SVV) process with 5 crucial elements & 25 sub-elements which directly impact worksites' safety & integrity was developed on concept of green, yellow & red traffic lights corresponding to As Required, Need Improvement & Unacceptable Condition at site. The process is supported and explained through specific procedure, online reporting system, verification checklists, brochures, posters and audio-visual film. The system is decentralised at each directorate level for efficient management but progress is monitored at corporate level for effectiveness and improvement scope.
The SVV conducted across facilities & contractors worksites by KOC senior and middle management resulted in significant HSE improvement during 2010-11 comparing the past performance. Taking into account the positive impact, the SVV process has been extended with appropriate modification and support to KOC supervisory levels & Contractors' Managers responsible for the safety & integrity of their worksites.
SVV process is a unique and innovative tool of verifying HSE commitment & demonstration of regulatory, procedural and contractual requirement through HSE oriented critical factors which indicates actual situation at site based on traffic lights concept of green (go), yellow (alert) and red (stop) as relevant action. The paper shall demonstrate a typical but realistic solution for worksite safety & integrity through a comprehensive verification system.
Improve Oil Production Using Blocking and TSO Fracturing in Ultra Low Permeability Reservoir, China
Authors: Dingwei Weng , Qun Lei , Yunhong Ding , Yongjun Lu , Zhenzhou Yang , Biansheng Li , Oilfield Jilin 
Published: February 2012

Abstract
In China, about 70% of new discovered oil reserves and 80% of new discovered natural gas reserves are in the low permeability reservoirs, and the lower limit of reservoir permeability is becoming lower and lower in new oilfields. The blocking and tip-screen-out (TSO) fracturing are introduced to create more complex fractures and increase the stimulating reservoir volume, comparing to the 2-wing symmetrical planar fractures, and so develop these ultra low permeability oilfields.
A model was set up to describe when the complex fractures form, and the key point is when fracturing elevating fracture net pressure to exceed the sum of tensile strength and the difference of maximum and minimum principal stress. And then two cases are detailed to illustrate how the blocking and TSO fracturing are designed and executed. The blocking fracturing is pumping some wax balls or larger size proppant to temporarily block the fracture and so increase the net pressure. And the TSO fracturing is similar to that used in the high permeability reservoir, but the aim is also increasing the net pressure not creating a wide and short fracture. The net pressure and the oil production are only matched when considering multiple fractures, so the blocking and TSO fracturing actually make more fractures spread, and increase the stimulating reservoir volume.
The two fracturing methods have been applied in several ultra low permeability oilfields in China, and average oil production is much more than that of neighbor wells. So the fracturing makes these ultra low permeability oilfields can be developed economically.
Wellbore Alteration - It's Implications on Measurement of Formation Properties
Authors: Abangwu Prince , Dutta Dhruba J. , Baig Mirza Hassan , Miranda Pereira 
Published: February 2012

Abstract
Deep-water offshore exploration has revealed increasing discovery of unconsolidated and under-compacted reservoirs characterized by high porosity and permeability. Formation evaluation becomes challenging since conventional drilling practices adapted for this environment often results in near-wellbore alteration which can reach deeper into the formation due to relatively low competency of the rock. This characteristic is observed for almost all the deep-water Miocene-Oligocene turbiditic sands across the globe.
The concept of near-wellbore damage is a well-known topic, however, its implication in deep-water exploration and production is being studied now in great detail. Measurements of properties like mobility and formation-fluid attributes have been jeopardized by fines migration, damage and alteration. The effect of near wellbore deformation causes development of skin and stiffness change that has a strong impact on formation fluid sampling and pressure acquisition. Multi-pole multi-array sonic acquisition has shown that damage causes variation of sonic-velocity in the radial direction that could be identified and quantified with the current technology. Innovations in Nuclear Magnetic Resonance (NMR) with greater depth-of-investigation (DOI) and radial-imaging and interpretation techniques indicates that the concept of fines migration causes considerable effect on formation permeability and porosity estimation and has a critical impact on reserve estimation.
The current work focuses mainly on two aspects of wellbore alteration on measured logs. First, effect of alteration has been identified by using multi-DOI NMR and sonic measurements in an integrated manner. Secondly, and subsequently, quantification of the damage was measured along with its impact on other measurements like formation-tester. This integrated technique can significantly and efficiently reduce formation sampling duration by locating damaged-zones and effectively reduces acquisition cost in a complex deepwater operation. The implication of identifying the damaged zone has a great value in designing optimum completion and sand management and exclusion technique at the subsequent stages of development.
Development of Unconventional Resources in North Africa: Evaluation Approach
Authors: Melo Ricardo C. , Lakani Ramin 
Published: February 2012

Abstract
The "Shale Gas Revolution" in North America has created both an opportunity and a challenge for the North Africa region for finding such unconventional resources. Approaches to finding them must be based on technology and planning to avoid unwanted expenses and error. Unconventional resources, for the purpose of this paper, are defined as tight and/or shale gas resources, although in North Africa, many of the challenges and potential solutions are equally applicable to oil rich resources. Key challenges specific to the North Africa region include the following:
The availability of gas in North America has shifted LNG shipments to Europe (which is North Africa's biggest export market). The potential spread of this "revolution" to Europe could further erode the region's market share. The region faces a lack of infrastructure and a higher cost base for developing unconventional resources.
As a result, little margin for error exists, nor can you afford to "learn by the drill bit." Therefore, you need to apply technology to reduce costs and increase well productivity and you need to develop a methodology that ensures minimal iterations. The latter requires a fully integrated approach to project evaluation, planning, and execution. As the highest portion of costs associated with developing shale/tight gas resources is for hydraulic stimulation (fracturing), this paper will focus on the best way to integrate:
Reservoir characteristics (rock and fluid properties) Geomechanics Fracturing techniques
A synergy of reservoir consultancy and pumping services has developed a close rapport and integrated approach that could be used by resource holders. This methodology can be modified to fit the requirements of NOCs or IOCs.
This paper aims to highlight these and also offer a potential approach and methodology to evaluate these unconventional resources and secondly to apply technology to unlock their potential. Case studies will be used to demonstrate the pitfalls and challenges faced by projects in North America.
Ultra-Lightweight Proppants: Best Practices for Long Horizontal Gravel Packs Offshore Brazil
Authors: Jardim A. T. , Prata F. G. , Gomez J. R. , Pedroso C. A. , Martins M. O. , Silva D. N. 
Published: February 2012

AbstractOperators developing reservoirs and producing them from deep and ultra-deepwater wells are pushing the technical limits regarding horizontal extension. Deepwater wells completed in uncosilidated formations usually have low fracture gradients, severe leak-off zones and/or significant wash outs. Long horizontal open holes, therefore, may become technically difficult or economically unfeasible to gravel pack using conventional fluids and gravels.Typical completions offshore Brazil start from a 9 5/8-in. or 10 3/4-in. casing, where a 5 1/2-in. premium screen and tubular string is hung along an open hole drilled with 8 1/2-in. or 9 1/2-in. bit. Horizontal extensions range from 980 to 4,000 ft.Ultra-lightweight proppants have enabled gravel packing in these longer horizontal open holes. The reduced gravel density allows a significant reduction in pumping rate, which avoids fracturing the formation, minimizes fluid losses and eliminates the risk of premature screen out due to excessive gravel settling.This paper summarizes the procedures and results of almost 60 wells that have been gravel packed using ultra-lightweight proppants technology pumped for a local operator.
Tight Reservoir Permeability Prediction by Integrated Petrophysical Evaluation, Core Date, and Micro-frac Wireline Formation Tester Analysis
Authors: Elarouci Fethi , Mihail Nicolae , Adnan Iguer , Benaissa Hicham , Nabil Mokrani , Fouzi Bouillouta 
Published: February 2012

Abstract
Most gas reserves in Algeria are located in unconventional tight reservoirs that typically contain multiple rock types from different depositional systems. Identifying and evaluating these reservoirs is difficult. Permeability predictions are very challenging because of results reliability from different downhole tools, and also by its direct relationship on production and economic impact.
This paper presents a case study that used an integrated formation evaluation approach of tight reservoir during an appraisal stage in an Algerian gas field. The workflow includes:
– Petrophysical model using stochastic analysis to get shale volume, effective porosity and water saturation calculation. – Hydraulic flow unit zonation using flow zone indicator (FZI) and global hydraulic element (GHE) methods identified from core data. – Pressure transient analysis from wireline formation tester. – Mathematical phi-k relationship from core data under confining pressure. – Synthetic permeability log using previous relationships
In addition to determining reservoir geomechanical properties from the micro frac operation, Synthetic permeability curve were generated in areas of the reservoir that were not core sampled. These predictions were constraint by core data analysis as well as permeability from wireline formation tester.
This methodology was applied in an Ordovician tight sandstone reservoir in the South east Algerian Sahara gas field.
Guidelines for Selecting Appropriate PVT Correlations for Black Oils
Authors: Al-Zahaby Ahmed , El-Banbi Ahmed , Sayyouh Mohamed H. 
Published: February 2012

AbstractAccurate determination of the crude oil PVT properties is essential for solving many reservoir engineering, production engineering, and surface production and operational problems. A large number of PVT correlations for oil exist in the petroleum literature and numerous studies are also present for with data favoring one correlation over the other. In the absence of PVT data from laboratory experiments, it is often difficult to choose which correlation to use to calculate different PVT properties. We approached this problem in two ways. First, we developed an expert system that checks the input parameters (e.g. reservoir parameters) against the valid ranges of input data for different correlations, and then recommends which correlations to use for specific input parameters. Second, we tested all available PVT correlations for black oil on a database of selected 35 Egyptian crudes to develop guidelines on which correlations to use for each PVT property for the specific range of input data. These specific crudes were selected to allow testing of those guidelines on a wide range of reservoir input data for black oils. Our database included oils with oAPI ranging from 17 to 51, gas-oil-ratios of 8 to 7,800 scf/STB, formation volume factor at bubble point of 1.04 to 4.47 bbl/STB, bubble point pressures of 60 to 4,739 psia, and reservoir temperatures of 40 to 270 °F.The present work included 13 bubble points, 6 solution-gas-oil ratio, 14 formation volume factors, 13 oil compressibilities, 14 dead oil viscosities, 9 saturated oil viscosities, 10 under saturated oil viscosities, 12 under-saturated densities, 2 total formation volume factors and 2 saturated density correlations.Based on this study, guidelines for selecting an appropriate correlation for PVT oil properties are introduced. These guidelines are recommended in programming of PVT correlations regardless of their geographic origin.
Foam Assisted WAG, Snorre Revisit with New Foam Screening Model
Authors: Spirov Pavel , Rudyk Svetlana N. , Khan Arif. A. 
Published: February 2012

Abstract
This study deals with simulation model of Foam Assisted Water Alternating Gas (FAWAG) method that had been implemented to two Norwegian Reservoirs. Being studied on number of pilot projects, the method proved successful, but Field Scale simulation was never understood properly. New phenomenological foam model was tested with sensitivity analysis on foam properties to provide a guideline for the history matching process (GOR alteration) of FAWAG Pilot of Snorre Field (Statoil).
The aim was to check the authenticity of presented new foam model in commercial software whether it is implementable on a complex geological model for quick feasibility studies, either for onward practical pilot or as justification for more detailed technical study.
The simulation showed that Foam model is applicable. The mismatch between history and actual GOR in some periods of injection is due to the complexity of the fluid flows control inside reservoir. The way; how specific properties control the time of gas arrival and values of GOR are described. The analyses of the improvements in the injection schedule are shown.
With increasing number of CO2 and FAWAG methods in preparation worldwide, the use of the simulation contributes to more precise planning of the schedule of water and gas injection, prediction of the injection results and evaluation of the method efficiency. The testing of the surfactant properties allows making grounded choice of surfactant to use. The analysis of the history match gives insight in the physics of in-situ processes.
Detailed Qualitative analysis is presented for foam modeling against the FAWAG historical data that provides sharp idea of the behavior of Foam model for different foam factors, which in turn provides reasons for the unpredictable foam behavior in WFB Project and also serve as quick reference for future general foam pilot simulations at field scale.
Cased Hole Formation Resistivity Evaluation Results in Successful Identification and Isolation of Watered out Zones in Nubia Formation
Authors: Ghadiry Sherif , Ismail Abdallah 
Published: February 2012

Abstract
Water production is one of the main challenges facing oil and gas producers. It is necessary to carefully manage water production in order to enhance oil production. In order to identify watered out zones, a time lapse cased hole resistivity survey was carried out to evaluate hydrocarbon saturation.
In static conditions, the value of cased hole resistivity over other time lapse techniques resides in its deep depth of investigation, which results in increased immunity to borehole fluid reinvasion.
This technique was applied on three wells, where the water cut was ranging from 65 % to 90 %. The cased hole formation resistivity clearly identified the watered out zones. A water shutoff operation followed. The objective of the cased hole resistivity acquisition was met as the water cut dropped down to 1 to 40 % after isolation of the watered out zones.
An Optimization Model to Determine Horizontal Well Location and Parameters for Strong Bottom Water Reservoir in Sudan
Authors: Xianghong Wu , Liangyu Rao , Xianbing Li , Xiangling Li 
Published: February 2012

AbstractThe purpose of this study is to develop a horizontal well closed-looped optimization model for enhancing ultimate recovery of strong bottom water reservoir in Sudan.An optimization model for horizontal well using the statistical properties of geology and development data, numerical simulation and fuzzy mathematics, is presented. The study was carried out as follows: 1) a mechanism model was established based on physical and fluid properties of the oilfields in Block 1/2/4, Sudan. The factors affecting the development performance of horizontal well, such as reservoir and fluid properties, inter-beds distribution, parameters of horizontal segment and production rate were discussed. 2) Development performance of typical massive bottom water reservoir in Sudan was analyzed. 3) The weight of each factor was determined using fuzzy mathematics method based on the mechanism study and on site practice of horizontal wells. 4) Determine the optimized location and production parameters of horizontal well by combining numerical simulation and integrated evaluation model.The optimization model was used in H oilfield of Block 1/2/4, Sudan, the result of numerical simulation show that this model can efficiently determine the location of horizontal well and can lead to increase oil production in bottom water reservoir. It can also give a reference for numerical simulation, and have a great improve place.
Improved Determination of Well Rate From Temperature and Pressure Distributions Along the Well
Authors: Barrett E.. , Abbasy I.. , Wu C.-R.. -R. , You Z.. , Bedrikovetsky P.. 
Published: February 2012

Abstract
The gas flow profile along the wellbore that includes contribution of all productive layers is an important piece of information for reservoir characterization and well management. It provides flow contribution from each producing interval along the wellbore, which is critical for optimizing well performance and maximizing gas recovery. The present work discussed determination of the rate profile from the pressure and temperature profiles in gas wells, which is significantly cheaper and more precise than the direct flow metering. An effective and robust algorithm for calculation of the rate and thermal conductivity profiles from the depth pressure and temperature distributions have been developed by tuning the mathematical model of non-isothermal gas flow in vertical well. The detailed sensitivity analysis shows that the inverse problem is well-posed. The initial values of rate and thermal conductivity for iterative minimization algorithm were obtained by averaging the values directly calculated from the measured pressure and temperature profiles. The initial values are shown to provide the final solution with good accuracy. It allows recommending the initial values for the estimates of the rate profile. Application of the algorithm to field cases shows good agreement between the directly measured and calculated rate profiles; the results are also consistent with flowmeter (PLT) data. It validates the proposed method.
Strategies to Unlock the Unexploited Oil Production Potential in Ashrafi Field, Gulf of Suez, Egypt
Authors: Sabaa Ahmed , Crema Giordano , Salvini Giovanni , Konga Felix I. , Abdelnabi Tamer , Bekheit A.. , El Farahaty M.. 
Published: February 2012

Abstract
Mature fields have the potential to contribute significantly to future reserves provided that the recovery can be optimized. The main objective of this paper is to discuss the application of some techniques and technologies to optimize the production in Ashrafi Field offshore, Gulf of Suez (GOS), Egypt.
Ashrafi Field, located in south-western part of the Gulf of Suez was discovered in 1987 and put in production in 1992 from its Main Area. In 1997, the South-West Area, discovered one year before, started contributing significantly to the overall field production. The field consists of sedimentary reservoir units partially overlying a tilted block of fractured Basement reservoir. The field reached its peak production of 25,800 BOPD in June 2000 from 12 naturally flowing wells and then the production declined drastically. The only artificial lift type that was suitable for the field was the gas lift system and it was implemented starting 2004 in 80% of the wells.
The strategy to unlock the unexploited potential in the field was to search for the bypassed oil through cutting edge technologies, using special techniques for stimulation of fracture Basement reservoir, combating scale and paraffin depositions in an efficient and economical manner.
The final result for the use of such techniques and technologies was the increase of the oil production to more than 225 % of its levels before the intervention campaign, the increase of the gas production needed for gas lift system feeding and the decrease of the amount of produced water.
Use of Water Cut to Optimize Conventional and Smart Wells
Authors: Barreto C. E. , Munerato F. P. , Ravagnani A. T. , Schiozer D. J. 
Published: February 2012

Abstract
Water-cut prediction by reservoir simulation can be used as the main parameter to determine well shutdown time. In general, analytical formulations are used to determine the maximum water cut that a well can reach and this value is used as a monitoring parameter in reservoir simulation. Moreover, water-cut value can be a good indicator to evaluate field performance and it can be used as a variable in optimization process. This paper presents a methodology to optimize production strategy using water cut as a parameter to shut down wells and smart completions as a variable of the optimization process and as an economic indicator to evaluate strategy efficiency. A discussion on the use of water cut in a reservoir simulation is made, regarding the benefits and limitations of the use. The results show that using only analytical formulation to determine the water cut to shut down wells and completions is not a good approach to maximize production strategy Net Present Value (NPV). On the other hand, the optimization of well and valve operation using water cut significantly improves the NPV. Water cut is successfully used to indicate strategy efficiency and to suggest strategy modification. The results also show that it is necessary to be careful in the use of water cut in an optimization process, because it can present several limitations. This study may help engineers to decide if it is necessary to run an optimization process to determine the parameter used to shut down wells. Furthermore, the results show the importance of a good estimation of the time to shut down wells and completions to reach the optimum potential of a production strategy.