bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Lateral Migration of the Serravallian Turbiditic Reservoir Bodies in Temsah Concession, Offshore Nile Delta, Egypt and its Impact on the Explorative Potentail in the Area
Authors: Ibrahim M. A. , Zaki A.. , Avella A.. 
Published: September 2015

Abstract
The study area covers Temsah concession in the eastern sub-basin, offshore Nile Delta, Egypt.
Despite the Serravallian play within this area is proven, observations made on recently acquired seismic data suggest its potentiality might be significantly larger than initially evaluated.
Over 25 wells have been drilled within Temsah Development Lease since late 70's targeting turbiditic channelized flow deposits fitting a part of the four way dip closure Akhen-Temsah anticline.
The interval of study shows a general fining upwards GR log pattern with a sub-parallel thinning up-dip seismic reflectivity.
Amplitude map analysis through this interval shows southwest-northeast anomaly trends, shifting upwards to the southeast and becoming thinner and narrower.
New hydrocarbon potential arises under the assumption that reservoir rock distribution is restricted to the anomaly trends mapped on the over-laying levels, from those producing from the main field area, and located down-dip on the southeastern flank of the structure. The associated risk derives from the reservoir architecture and possible lateral up-dip communication to underlying beds through permeable beds.
Fracturing Fluid Rationalization: First Dual-Viscosity Fracturing Fluid Application in the Middle East
Authors: Mira Ali , Samir Mohamed , Naby Mohamed Abdel , Mohamed Nelly , Rojas Jose , Kamar Ahmed , El Sebaee Mohamed 
Published: September 2015

Abstract
Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location.
The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential.
This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance.
Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.
Gulf of Suez Integrated Gas Lift Optimization Study
Authors: Hamshary Adham , Sheta Ibrahim , Basha Kareem , Atteiya Mohamed , Davies Nick , Girgis Fady , Fouad Raed , Kamal Mohamed 
Published: September 2015

Abstract
The Gulf of Suez Petroleum Company (GUPCO) is a leading Egyptian petroleum company. GUPCO production is primarily dependent on gas lift with 90% of its producing wells utilizing this artificial lift method, consuming more than 450 MMSCF of gas per day. One of the main hindrances to maximizing GUPCO's production is insufficient gas supply which leads to shutting in many producers resulting in significant production deferrals.
GUPCO's Base Management Team (BMT) initiated an integrated system optimization project in 2013 which combined four different technical pieces of work. It was introduced for the first time in GUPCO to ensure gas is used efficiently in the Gulf of Suez (GoS) to maximize the value of GUPCO's old data, build trust in well and surface modelling and increase BMT capabilities. The main challenges of this project were data gathering and quality, engineering capabilities in the use of Prosper and GAP modelling and lack of integration between field and office technical personnel regarding the system optimization.
Working through these challenges created tangible value through enhanced understanding of the gas sy stem, identifying additional opportunities to save gas and increased oil production. This boosted the modelling capabilities of all team members. The BMT approach was divided into four different phases as follows: Gas balance study for better understanding of the gas systems in the different areas across the GoS.Prosper modelling for gas-lifted wells that resulted in 20 gas lift valve change opportunities that lead to increased production of 1000 BOPD.GAP modelling for the production system that resulted in a 7700 BOPD potential oil gain, 16.5 MMSCFD potential gas saving and debottlenecked pipelines.Creaming curves which became a very good tool to prioritize the GL wells with respect to gas availability, evaluating well work value, and quantifying the impact of surface facilities failures and/or repairs.
Until the time of this paper, the project was in the execution phase and has resulted in saving 7 MMSCFD from optimizing gas lift injection in 8 wells. The forward plan of the project is as follows: Continue the execution phase and ensure good communication between all teams.Install recommended meters/scanners to enhance data measurement in order to ensure sy stem balance.Complete GL optimization execution in SC GoS & share the outcomes.Install MPFM on some offshore platforms which will help in evaluating the optimization.Utilize a Portable Test Package for further enhancement of system evaluation & optimization.
The objective of this paper is to show the technical processes used to initiate an integrated gas lift optimization project in the GoS and how the opportunities created will add considerable benefits to the business.
Poroperm Characterization and Rock Typing of Tight Carbonate Reservoir Using Core Calibrated Image Perm Technique: Turonian Carbonates in Abu Sennan Field, Western Desert, Egypt, A Case Study
Authors: Helba Adly , Ali Wael , Fattah Mohsen Abdel , Mokhtar Hesham , Farouk Mona 
Published: September 2015

Abstract
The recent achievement in unconventional reservoirs has established the objective of reevaluating the oil-bearing tight carbonates as potential oil production reservoirs. Of these carbonates, the Turonian Abu Roash D (AR/D) tight limestone in the Abu Sennan field of the Western Desert, Egypt contains oil, but has extremely poor recovery. The challenge in this study is to define the effective parameters that control the various petrophysical attributes of this tight reservoir and their influence on reservoir recovery.
Integrated sedimentological analysis and poroperm characterization was performed based on various data sets, including conventional core analysis, mercury injection tests, and petrographic inspection. A core-calibrated image-perm software algorithm was processed to evaluate the heterogeneity of reservoir pore system and to provide a continuous and azimuthal output of high resolution porosity and permeability.
The AR/D limestone succession (approximately 82 m thick) consists almost entirely of offshore-outer ramp bioclastic wackestone-mudstone facies, with the exception of a reduced reservoir-forming interval (approximately 10 m thick), which consists of inner- to mid-ramp facies. The outer-ramp offshore facies have very poor reservoir quality, with total porosity of less than 9% and permeability values that never exceed 0.1 mD. The reservoir-forming interval begins with storm beds of whole fossil rudstone and bioclastic wackestone, and gradationally terminates upward with inner-ramp shoal beds (5 m thick) of benthic foraminiferal peloidal packstone. The shoal facies measure a noticeably enhanced porosity (15 to 27%) with a relative increase in permeability (up to 2.3 mD). However, a petrographic inspection with resistivity image analysis showed a clear paucity of visible mega- and meso-pores or significant natural open fractures. This means that the reservoir pore system is of the intercrystalline microporosity type, which is confirmed by scanning electron microscope (SEM) and the measured pore throat radii ranging between 1 and 0.005μ. The prevalence of microporosity in the best zone of AR/D reservoir is also evident by a unimodal porosity range distribution shown by an image-perm output. This homogeneous and volumetrically significant microporosity nature may provide a favorable recovery if a suitable fracturing design is applied.
This study highlights the effect of microporosity types on the permeability of tight limestone reservoir, and emphasizes the workflow and benefits of the image-perm technique in evaluating the poroperm system and heterogeneity in the porosity distribution in carbonate reservoirs.
Multi-Well Correlation to delineate Stacked-Channel Reservoir using High Resolution Micro-imaging Facies
Authors: Hassan Sahar S. , Megawer Abdel Khalek , Zahran Hemida , Emam Mahmoud , Abu El Fotoh Ahmed M. , Haddad Elia 
Published: September 2015

Abstract
The Western Desert accounts for approximately two thirds of Egypt's surface area. The region can be divided into a number of large scale structural provinces which developed along lines of weakness in the African basement, in response to lateral movements between Europe and Africa. Seismic evidence has revealed a subsurface comprising a series of low relief horsts and grabens. In places however, the structural history is more complex.
The Yusif field located near the Qatara depression, is habituated and, therefore has poor seimic data. Three wells were drilled in the field, Yusif -1X, Yusif-3, and Yusif-4 respectively. The fourth well is planned for the most promising area between the three wells. Formation microimaging was performed in the three wells, and interpretation of the images helped to delineate the sand body propagation and geometry in the field and choose the most promising area for drilling the fourth well.
The Lower Abu Roash “G” member usually appears as a fining upward profile from conventional openhole logs. Facies analysis was performed on the “G” member with manual sedimentary dip picking, which revealed the internal structures and directions that can't be observed from conventional logs.
Correlation with existing openhole logs showed continuity in the vertical and lateral distribution of the sand body, and queries about the relation between the sand bodies in the three wells arose. The relationship between sand bodies can't be solved by conventional openhole logs correlation.
Paleocurrent analysis was performed for the sand bodies in the three wells. The results showed that the main trend of the channel belt propagation is NE. Yusif-3 and Yusif-4 wells were drilled within the channel belt while Yusif-1X location was at the channel margin.
Correlation is based on electrofacies, which was extracted from high-resolution formation microimaging in the three wells. It was found that the “G” member top is changed based on high-resolution electrofacies detection, and the fourth well was placed closer to Yusif-3 and Yusif-4 based on the recommendations on the channel activity propagation as identified in the formation microimaging. The sand body thickness in the fourth well was almost double the thickness that was found in the previous three wells.
Electric Submersible Pumps as an Artificial Lift Solution for Complex Wells Operation in a Caspian Sea Offshore Oil and Gas Field
Authors: Berdiyev Yunus , Kortukov Dmitry , Atabayev Dovletgeldi 
Published: September 2015

AbstractDragon Oil needed to extend the production lifecycle for it's offshore field wells with lower than expected natural flow regime duration. After reviewing multiple of running the Electrical Submersible Pumping options, Dragon Oil chose to implement tubing conveyed and rigless ESP's to return the candidate wells to the required production levels. This case study highlights the technological rational, challenges in implementing decided strategy and prognosticates expected results & benefits from running the two types of ESP's as an additional well investments. Candidate wells for ESP Artificial Lifting have been drilled from offshore wellhead platforms “1” and “2” into the flanks of the Main Field Reservoirs. Commissioning of the pilot ESP projects is expected by end of 2015.
Effective Fracturing Stimulation in the BRN Field in Algeria Using a Residue Free Gelled Fluid System
Authors: Forno Luca Dal , Latronico Roberto , Mohammed Omar , Kateb Mahmoud , Rispler Keith , Ainouche Dalil , Squires Scott , Petteruti Ernesto , Fragola Daniele , Allal Mohammed A. , Hachelaf Houari , Albani Danilo , Hamdane Toufik , Carpineta Gabriele 
Published: September 2015

Abstract
Hydraulic fracturing for well performance optimization has been implemented for many years in BRN field in north-eastern part of Algeria, operated by Groupement Sonatrach-Agip (a JV between ENI and Sonatrach). Because of unfavorable petro-physical properties of the reservoir, some challenges have been encountered in avoiding any additional damage to the fracture faces and to facilitate the post-job treating fluids flowback. Effective fracturing treatment designs should consider preventive actions for possible fracture conductivity impairment, such as damage attributed to stress, proppant embedment, and damage caused by fracturing fluid residues. Correct proppant selection can minimize effects from stress and embedment, while a suitable fluid system can minimize conductivity impairment from gelling agent solid residue.
Traditional guar-based fluid systems, which are often a preferred choice in the industry for fracturing operations, can have damaging effects on fracture conductivity attributed to inherent insoluble residue that can plug proppant pack pore spaces. Implementing a less damaging fluid system can not only maximize retained conductivity, but furthermore provide longer effective fracture half-lengths which may result in more efficient treatment fluid recovery. Therefore, to overcome such issues, a new fracturing fluid has been developed, leaving little or no residue after breaking. Moreover, this fluid system can be tailored to a wide variety of bottom-hole conditions and has comparable properties to guar-borate fluids with respect to proppant transport capacity and rheological characteristics (e.g. viscosity building and breaking behaviors).
This paper presents the first successful implementation of this novel fluid system in the BRN field in Algeria for improving the water injection performance of a well characterized by a tight sandstone reservoir. Field data collected after performing the propped fracturing treatment confirm the effectiveness of the fracturing fluid design. Specifically, the following topics will be extensively described within this paper: Characteristics of the BRN field and history of conventional guar-base fluid systems used previously within this field;Specifics of the near residue free fluid system (cross-linker types, pH requirements, etc.);Design considerations for the implementation in the BRN field of this novel fracturing fluid;Results of post fracturing water injection performances.
Proper Selection of Multiphase Flow Correlations
Authors: Abd El Moniem Mohamed. A. , El-Banbi Ahmed H. 
Published: September 2015

Abstract
Multiphase pressure drop calculations represent a challenge for petroleum engineers. We normally rely on multiphase flow correlations to calculate pressure traverses through tubing from the sand face to the wellhead. Although there are many multiphase flow correlations covering most flow conditions; there are still no clear criteria to select appropriate correlations in absence of flowing gradient survey data.
The objective of this work is to help petroleum engineers select the most accurate multiphase flow correlation(s) for any flow conditions, fluid properties, and well configuration.
The method depends on analyzing a large database of pressure drop data from many wells. Our database is composed of more than 3,200 measured pressure points taken from survey and single point measurements on 879 wells representing large variations of flow conditions (oil rate ranges from very low rate to 31,000 BBL/D, water cut from 0 to 98%, gas-oil ratio from 0 to 20,000 SCF/STB, gas rate from very low rate to 200 MMSCFD, water gas ratio from 0 to 200 BBL/MMSCF, condensate gas ratio from 0 to 200 BBL/MMSCF for vertical, deviated and horizontal wells with different tubing sizes).
We built models for all these wells and tested many available multi-phase flow correlations and recorded the error in their prediction against the actual measurements of pressure points. We then classified the large database into groups and found all multi-phase flow correlations within this group that have the lowest error. For every group, we can now identify the best correlation(s) with their estimated error value. We also defined a term to reflect the strength of the appropriate correlation(s) (how many times this particular correlation was best in each group of data) to help engineers select appropriate correlation for each well and its flowing conditions.
The strength term for all groups varies from 100 % to 30% which indicates that for several groups we can now select the multiphase flow correlation with significant accuracy. The expected error for all correlations is also reported. The parameters that mostly affect each correlation are also highlighted so engineers would know which parameters need to be accurate in using the recommended correlations.
Drilling Optimization in Achimov Horizontal Wells by Integrating Geomechanics and Drilling Practices
Authors: Dymov S.. , Kretsul V.. , Dobrokhleb P.. 
Published: September 2015

Abstract
A workflow was developed for effectively handling the development challenges in the Yamal oil and gas province of Western Siberia. The workflow integrates geomechanics with efficient drilling practices and leads to the implementation of an engineered drilling system (EDS).
The workflow for development in the Yamal region encompasses phases from modeling to drilling practices, incorporating an understanding of challenges faced and lessons learned from previous drilling. The majority of Achimov operations in the Yamal region have been conducted in the Urengoy gas condensate field, which is divided into different blocks. The Achimov deposits are deep (true vertical depth is about 3,750 m), exhibit abnormally high formation pressure (over 600 atm), and contain multiphase hydrocarbons with the presence of heavy paraffins. Unstable shale formations must be drilled prior to penetrating the Achimov itself. These challenges affect drilling efficiency and interfere with the well construction schedule. The Achimov formations present two main challenges to horizontal drilling: wellbore instability leading to stuck pipe incidents in the build section or inability to run liner/casing to total depth and loss circulation, potentially compromising well delivery and project objectives. Thus, previous drilling has shown that developing and producing from these enigmatic resources requires more than just horizontal wells and hydraulic fracturing.
Companies are aggressively pursuing Achimov deposits, hoping to extract additional gas and gas condensate volumes from the declining fields and to implement a strategy to raise natural gas production. Successful operations require an integrated approach, using multiple data sources, to determine the key parameters needed to understand the Achimov formations and extract the hydrocarbons. Among the successes, an operator company for Urengoy field demonstrated how developing a mechanical earth model (MEM) of the reservoir and continually improving processes paid big dividends.
By implementing the EDS approach, unique results have been achieved in drilling and completion of Achimov horizontal wells. Outstanding drilling performance in Achimov horizontal wells has led to a revision of the field development plan.
Prediction of True Resistivity and Resistivity index using Neural Networks with Different Combinations of Wireline Logs
Authors: Sbiga H.. , Mousa N.. 
Published: September 2015

Abstract
This study has been undertaken in two oil fields (A-Libya, and B-Libya) in Sirte basin located in Libya. Nubian sandstone Formation is the main reservoir in the studied oil fields. Laboratory resistivity measurements were performed at Libyan Petroleum institute (LPI). The majority of wells, however, are logged and the use of wireline log data in conjunction with some core data has been proposed as a rapid, cheap, and alternative to predict some special core analysis (SCAL) parameters instead of collecting extensive core or performing SCAL measurements in all wells. Neural network predictors are potentially very useful in the present study due to the limited SCAL data for the studied wells. In this work some of SCAL parameters were predicted using neural networks based on different combinations of wireline logs. The procedure firstly involved training the neural network predictors using data in training well A-02. These predictors were then applied to an adjacent well A-01 in the same oil field, and to another test well B-01 in a different oil field. The most frequently used type of neural network is a feed forward neural network using a back-propagation learning algorithm, due to its popularity and simplicity.
Some good neural network SCAL parameter predictors for Rt, and RI were generated using different combinations of standard wireline logs in the training well A-02. The best predictors were produced using the dataset from the entire 478 ft cored interval of the training well and all 7 available wireline logs. Predictors trained on data at 1.0 ft depth spacing appeared to be better in the training well. However, the prediction of resistivity parameters in an adjacent well and a further test well in a different oil field gave slightly better results in general for predictors trained on data at 0.5ft depth spacing rather than at 1.0 ft depth spacing.