bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dielectric Measurement Improves Formation Water Saturation Evaluation in Variable Water Salinity Conditions, Upper Bahariya Formation, Egypt
Authors: Van Steene M.. , Giussani M.. , Corbella M.. , Tornaghi M.. 
Published: April 2013

Abstract
In Egypt's Western Desert, water saturation evaluation of the Upper Bahariya reservoirs is complicated by significant uncertainties in the resistivity-based saturation equation inputs, mainly the formation water salinity, but also the cementation factor and the clay cation exchange capacity (CEC).
A novel dielectric multifrequency measurement was able to clearly identify zones in which oil was present, regardless of these inputs. It provided a residual oil saturation and clear differentiation of oil-bearing zones from water-saturated zones. The measurement also permitted us to apply constraints to the conventional saturation interpretation from shallow and deep resistivities. This process highlighted the variability of formation water salinity across the well and the mixing of filtrate and formation waters in the zone investigated by microresistivity tools.
The dielectric tool also measures dielectric dispersion, from which a parameter (MN) related to the tortuosity of the conduction path can be extracted. This MN parameter was used to refine the water saturation computation from deep-resistivity logs. Variation of the MN parameter between 1.8 and 2 was observed in the reservoir zones. In the zone of interest, a water saturation difference of 7-8 % was observed in the cleanest zone between water saturation computed using the variable MN parameter and that computed using a fixed cementation factor of 1.9. The water saturation recomputed using the data from the dielectric log matches well the irreducible water computed from the nuclear magnetic resonance (NMR) data.
Dielectric dispersion was also used to derive the CEC, which was then input as a direct measure of shaliness in the deep-resistivity saturation equation.
The dielectric measurement increased the accuracy of the water saturation computation in this challenging environment and provided data that are not directly available with conventional logging.
New 16" PDC Bit Design with Improved Cutter Technology Delivers High Rate of Success and Increased Rate of Penetration Drilling in Deep Gas Field in the Arabian Peninsular
Authors: Teasdale P.. , Djaoui M.. , Ahmad R. T. , Markandeya S Holalkere , Roberts T 
Published: April 2013

AbstractThis paper details the step by step process undertaken by a dedicated focus group established to provide a solution to inconsistent drilling performance with the 16" section in a deep gas field on the Arabian Peninusular. The paper reviews the analysis undertaken as well as focusing on new design concepts and improved technology introduced.Drilling in these deep gas fields, especially the 16" sections has always been a challenge for Polycrystalline Diamond Compact (PDC) drill bits due to the complex lithology that consists of a variety of carbonates with high interfacial severity, followed by a highly abrasive sandstone and dense dolomite formations. Despite improving the ability to consistently drill the 16" sections in a single run over the past few years, the new challenge is to make further improvements to the consistency while at the same time providing further improvements in rate of penetration.Having experienced inconsistent performance and a series of premature PDC bit failures in these applications over the last few years the vendor assembled an integrated project team to investigate the issue. This team carried out an in depth analysis of all the available field data and identified several factors that were responsible for PDC bit damage, such as bit/BHA whirl, poor operating parameters with their associated vibrations and the limited ability of existing PDC cutters to drill such formations.The findings led to the development of a new PDC bit design solution with high lateral and torsional stability capable of drilling with high drilling efficiency, the introduction of new cutter technology; along with optimised operating parameters. The successful implementation of the new drill bit and recommended drilling parameters has enabled the operator to more consistently drill these challenging 16" sections in a single run at higher ROPs than previously achieved. This has resulted in significant cost saving for the operator.
Novel Technique to Increase Production from Tight Reservoirs using Channel Fracturing Technique for the first time in the Middle East and North Africa
Authors: Samir M.. 
Published: April 2013

AbstractHydrocarbon production from tight reservoirs with ultra-low permeabilities in commercial rates for extended periods is difficult to achieve with the current stimulation technologies used in the industry. Normal hydraulic fracturing with conventional techniques to enhance conductivity has been directed towards improving the ability of oil and gas to flow through a porous proppant pack. The industry has extended significant efforts towards the goal of increasing proppant pack permeability through the development of less damaging carrier fluids, higher strength man-made proppants, more efficient fracturing fluid breakers etc. but with no assurance of maintaining long-term production.The concept of the novel channel fracturing technique is to create flow paths inside the proppant porous media to give infinite conductivity, which delivers a number of consequential benefits: better post-frac cleanup, lower pressure loss within the fracture, and longer effective fracture half-lengths, all of which contribute towards improved short and long-term production.This new channel fracturing technique was applied and implemented in reservoirs located in the Egyptian western desert for the Abu Roash ‘G’ and Upper Bahariya formations, which usually undergo a steeper than normal decline in production even after hydraulic fracturing with conventional techniques.This paper will discuss the results of four well stimulation treatments utilizing the channel fracturing technique proving the increase and stabilization of oil production over extended periods even with decreasing reservoir pressures around the wellbore.
Novel Controlled-Release Breakers for High-Temperature Fracturing
Authors: Patil Prajakta , Muthusamy Ramesh , Pandya Nisha 
Published: April 2013

AbstractVarious types of breaker systems are used for viscosity degradation of fluids in fracture stimulation operations. Achieving improved fracture conductivity is one of the key advantages of using effective breaker systems, but there could be an increased risk of poor proppant placement and premature screenouts resulting from early viscosity reductions as the fluid is exposed to temperature. To resolve this issue, a controlled release of the breaker over a period of time is very desirable.This paper highlights the controlled release of encapsulated oxidizers and chelating types of breakers that are effective in bottomhole static temperatures (BHSTs) up to 275°F. Oxidizers without encapsulation begin to decompose fluids at low to moderate temperature, which can lead to a rapid decrease in gel viscosity before completion of the fracturing operation. Neat chelating breakers can absorb the crosslinker rapidly; thus, little to no crosslinking action would be present, even at moderate temperatures. A newly developed encapsulant makes oxidizers and chelating agents viable for reducing the crosslinked viscosity gradually with temperature.The new encapsulant is a blend of selected polymers that release the active breaker through diffusion. It is possible to optimize the release rate of a breaker by simply adjusting its ratio in a polymer blend. The controlled release of a breaker through an encapsulant was evaluated at 200°F under static conditions. The dynamic rheology of fracturing fluids was also studied as a function of encapsulated breaker concentration in temperatures up to 275°F. The results derived from this investigation are of significant importance to the oilfield industry.
Field Example of the Application of a Probabilistic Workflow to Forecast Future Development Potential in a Heterogeneous Fluviatile Reservoir
Authors: Dros A. N. , Benhammadi Z.. , Vernain-Perriot V.. 
Published: April 2013

Abstract
Probabilistic workflows become more and more applied in the current industry. Especially in fields with large uncertainties or property variations these techniques allow to capture the possible realizations of the reservoir and the range of outcomes for applied field development scenarios.
This document describes the application of a probabilistic workflow on a field located in Northern Africa. The field is an oil field producing from a fluvial formation. It has produced 0.5 MM stb to date from one production well.
In order to assess the future potential of the field, multiple static realizations were created based on probabilistic modelling of uncertainties in structure, channel characteristics (geometry, amount over the field and orientation) and properties. These static models were consequently initialized in a dynamic modelling environment. Several thousand static models were screened revealing the information implicitly stored in the data resulting in seven realizations for which an acceptable history match was achieved. All matching realizations showed a channel belt oriented in a SW-NE direction, apparently parallel to the main fault. Within the channel belt the net sand is high, but the area away from it is either predominantly non-reservoir or very poorly connected to the main channel belt. Some uncertainties remain, the most significant being the structure and the amount and distribution of the net reservoir and as a result the STOIIP.
Carbonate Reservoir Characterization at Different Scales: Proving the Value of Integration
Authors: Cañas Jesus A. , Junk Elmar , Essenfeld David , Ortiz Rubiel 
Published: April 2013

Abstract
Much has been written about carbonate reservoir complexities, heterogeneity, and data integration at different scales. However, there are not many published examples that show a comparison of producibility modeling predictions and actual field results that include data from core, advanced openhole well logs, formation testers, and drillstem tests.
In this study, we present the integration of data and measurements from advanced technologies to evaluate reservoir heterogeneity of carbonate formations on multiple scales. Quantitative textural analyses based on a comprehensive suite of petrophysical logging measurements were integrated with core data and formation testing data to characterize hydrocarbon/water transition zones and formation permeability and producibility. The offshore carbonate reservoir studied is composed of limestones and dolomites. Despite the inherent chemical complexities and hidden modes of origin, dolomites often exhibit favorable reservoir quality with high porosity and permeability properties. For this reason, E&P companies continue to predict where drilling targets are most likely to encounter these sweet spots.
Traditional permeability correlations are not effective in these systems, leading to overdependence on porosity-based reservoir descriptions to predict fluid flow. Using nonparametric regression, we have established a relationship between permeability and porosity from logs that are available fieldwide. Subsequent integration of this data with interval pressure transient test data in zones selected based on the observed rock heterogeneity enables further optimization of the final permeability correlation. The descriptions of the field examples confirm the success of this integrated approach and include the planning, real-time monitoring, and final validation of permeability and anisotropy at different scale during the exploration phase of a field.
Selecting the well locations for development using the proposed approach has proved valuable for improving field development practices. The results have led to enhanced reservoir characterization based on flow (permeability) and storage-capacity analyses (porosity partitioning), and a better understanding of the reservoir heterogeneity at different scales; the results have been used to improve drillstem test designs and reservoir production strategies.
Challenges and Practical Aspects in Commingling Different Reservoirs: Theory and Case Study
Authors: Darhim Noureldien 
Published: April 2013

Abstract
GS327 is a small field located 7 km east of southern Morgan field. It was discovered in May 1983 by well GS327-A1. An excellent sand quality was found in both Upper Rudeis ASL & KAREEM reservoirs (Lower Miocene). The field initial rate was about 6,000 BOPD, and after drilling 12 wells, the production hit 11,000 BOPD. After that production declined dramatically reaching 3,000 BOPD in 2011.
Currently and after an extraordinary job, GUPCO succeeded to double the field rate by commingling the totally different isolated reservoirs (ASL & KAREEM) in the well EM327-1ST1 after intensive multidisciplinary study. This paper presents the methodology of that study and analysis done to commingle two different reservoirs safely highlighting challenges and uncertainties we had in both data and procedures. It shows how to estimate the new STOOIP and how to predict the new well/reservoir performance by using a combination of MBE, Well Modeling and DCA.
The study covers three main sections of challenges; first one is Productivity of each reservoir in terms of Pressure and Fluid Mobility through different reservoirs to mitigate/evaluate cross-flow possibility, second section is Scaling Tendency issue since both reservoirs are expected to produce significant volume of water which may have different incompatible ions, third section is surface facility capacity to handle large amount of fluids expected to be produced from that multi-layer well.
In this paper, you will find an integrated work processes at which different tools were combined; MDT's and Pressure Data interpretation, Geological and Petrophysical evaluation, Water compatibility analysis in Chemical Lab, use of different Models (Well, Reservoir & IPM basis), and finally verification of the result against actual data. Through this paper, you will know how to use every piece of data to answer uncertainty or overcome a challenge resulted in a doubled production.
North Bahariya Concession Transaction-A Novel Strategy for Acquiring the Micro-Scale Producing Fields
Authors: Abdel-Nabi M.. , El-Behiry A.. , Rizk Mahmoud , Abdel-Moneim E.. 
Published: April 2013

AbstractSince the last decade of the twentieth century, the Egyptian government started enacting new policies aiming at attracting national and international investments through facilitating the regulations and procedures which hinder production and investment resolutions. In this concern, the laws were issued as a step to attract the investment of the Egyptian private sector, international investment and financing corporations. Of the transactions that have recently occurred is the Sale and Purchase of the 50% operatorship interest of North Bahariya Concession.The North Bahariya Concession is an onshore oil concession located in the Western Desert of Egypt, 190 Km SW Cairo City. Currently, the concession covers two development leases namely North Bahariya and Rawda with total approximate area of 117 km2 containing six producing oil fields; Abrar, Ferdaus, Ganna, Rawda, Rayan, and the most recent field Sidra. The primary productive horizons are the Cretaceous Abu Roash 'G' and Upper Bahariya with secondary production from the Abu Roash 'E'.This paper aims to have an outlook on the evaluation process procedures as well as address the different views on the blocks by many evaluators. The seller had a certain view for the concession potentiality while the buyer has believed in additional potentials based on which the acquisition has been evaluated.Exploration, appraisal, and development activities have been done by the acquirer to prove/disprove the idea of the unseen, by the ex-operator, potentiality. The activities results have had a great effect on the picture of the reserves and resources estimates with new aggressive development plan.The current estimates of OOIP, reserves, upside potential, and field development plans have been completely refurbished according to the new potentiality view as the production and reserve have been increase by 4 times. Trusting the judgment is the key to prove the ideas.
«Hot Shales» Facies Heterogeneity: Highlights from the Mineralogical and Geochemical Analyses of the Lower Silurian Source Rock of a Palaezoic Basin (SW Algeria)
Authors: Rigollet Christophe , Hofmann Andreas , Burns Suzi , Portier Eric , Paul Andreas , Kollschijn Michiel 
Published: April 2013

Abstract
In Northern Africa, the Lower Silurian organic-rich shales charge both intra-paleozoic and basal Triassic reservoirs and might have an important potential for shale gas. The shales were deposited in a confined marine environment during the Lower Silurian transgression. On the Gondwana scale, they are laterally discontinuous while their distribution and thickness are controlled by palaeo-reliefs inherited from tectonic and Ordovician glacial events (Luning et al., 2000). On the field-scale, the mineralogical and geochemical analyses of cutting samples indicate significant vertical and lateral facies variations, which contradict the apparent homogeneity of this formation.
The study is based on 80 cutting samples from 5 wells of a Palaezoic basin in SW Algeria, with a maximum spacing of 13 km (Fig. 1). Each sample has been analysed in terms of its mineralogy / petrography (QEMSCAN analysis) and organic matter features (Rockeval pyrolysis). The fully automated QEMSCAN system (Quantitative Evaluation of Materials by Scanning Electron Microscopy) provided a bulk modal analysis, particle maps, a textural analysis, mineral-by-mineral chemical assay and trace mineral hunt.
The cutting analysis facilitated the identification of 21 minerals, which were subsequently clustered into 5 assemblages (1) carbonate, (2) mica, Fe-oxide and siderite, (3) Clay, (4) Clay, pyrite, chlorite and feldspar and (5) remaining minor minerals. The focus of this presentation is to describe the observed heterogeneity and to discuss the parameters that control the vertical and lateral distribution of these facies (sedimentology, diagenesis...).
The Lower Silurian "Hot Shales" are highly heterogeneous and exhibit strong vertical and lateral facies variations, which might explain the complex distribution of TOC values and brittleness properties. Through a combination of geochemical and mineralogical analyses from cutting samples, it will be possible to model the source rock heterogeneity, predict the distribution of TOC values and brittleness properties and ultimately evaluate the shale gas potential.
Maximizing Cost Efficiencies through Real-Time Well Testing
Authors: Awara Abdalla , Mansilla Cidar , Fink Kevin 
Published: April 2013

Abstract
When well testing is conducted, the reservoir response during the initial surge to stable drawdown and pressure buildup will define productivity expectations for a new well. The quality of the reservoir fluid samples further defines the value of the reservoir assets.
To ensure that operations will be conducted safely, rig-time efficiency will be maximized, and the overall well test objectives will be met, several critical well testing decisions must be made.
This paper describes the value of real-time access to reservoir information and tools to control well testing operations. Also described is a system that has been used to provide immediate access to the reservoir through the use of wireless downhole telemetry, data acquisition and control, and instantaneous visibility of data from any location around the world. While the idea of providing access to some reservoir information in near real time is not a new concept, the system described is not dependent on formation geology and is the only one with the capability to provide access to all reservoir information in real time, perform analysis using this information, and control well testing operations remotely with the click of a mouse button. Case histories will be presented to demonstrate the capabilities of the system described.
Effect of Petrophysical Re-interpretation on Matured Fields' Development Planning and Producing Reserves Boosting Up in Abu El Gharadig Basin, Western Desert, Egypt.
Authors: Rizk Mahmoud , Rafik M.. , Ell-Behiry A , Abdel-Nabi M.. 
Published: April 2013

Abstract
West Qarun (WQ) and Abrar fields are located in Abu El Gharadig (A/G) basin in the Egyptian Western Desert with a combined area of about (82) Km2. Drilling activities in this area were commenced in late 1980s till first oil discovery was announced by (AMOCO) in (1994), Since that; and through February 2009; a total of (4.2) MMSTB oil was produced from six wells in both fields.
This paper demonstrates that an intensive review of petrophysical parameters had led to re-discovering the actual unforeseen bigger volume of the old matured fields that had been producing since decades; resulting in boosting up the combined production levels from about 600 BOPD to about 7000 BOPD while still development activities continues to prove extensions to both field and add more reserves.
Subject fields are producing upper cretaceous reservoirs of both Abu Roash G (A/R_G) and Upper Bahariya (U.B.) formations; this area was formerly famous for low well productivity and non-encouraging economics; but after Sahara Oil and Gas Co. (SOG) received the operatorship of these oil leases in Feb 2009, a petrophysical interpretation review was applied to find out the reason behind more than 10 years of stable production rates, the review included investigating the validity of the formerly used models for interpreting the existing shaly sand that indicated high water saturations that never matched the production data; also, an individual well interpretation parameters were considered instead of the formerly generalized set of parameters over-all the fields.
The conclusion of this paper could be summarized in attracting attention to the importance of a new eye vision when considering a new evaluation of reserves of an oil field that had been formerly considered as a matured one; while still investigating each piece of information that might have over-estimated or under-estimated the never-seen reservoir volume.