bluuebunny/crossref_metadata_2025_split huggingface dataset:
Progressive-Recursive Self-Organizing Maps PR-SOM for Identifying Potential Drilling Target Areas
Authors: Dossary Mubarak , Al-Turki Ali , Harbi Badr , Faleh Abdulhamid 
Published: February 2017

Abstract
Identifying potential productive reservoir units for infill drilling is a major challenge in developing giant fields in order to meet production targets and extend plateau. A common practice in identifying potential drilling locations is using oil saturation from production logs or near-by wells performance. Literature already recommended combining static and dynamic parameters from reservoir models (geological or numerical) to calculate cell performance indices such as Reservoir Opportunity Index (ROI) or Simulation Opportunity Index (SOI). It is difficult for those methodologies to provide volumetric representation of the hydrocarbons in potential areas since they do not specify the details of the clustering mechanism of similarly performing cells. The proposed algorithm allows the reservoir engineer to, progressively and recursively, define hydrocarbon sweet spots areas.
In this work, progressive-recursive self-organizing maps (PR-SOM) is developed and tested on a carbonate reservoir model. PR-SOM is an unsupervised artificial intelligence neural network algorithm that classifies the simulation grid cells into potential drilling targets by using a progressive list of dynamic or static reservoir parameters to identify similarly "good" contiguous regions. This is achieved by applying SOM on geomodels based on relative permeability, fluid saturation, pressure, and displacing fluid influx in the first iteration. The second iteration, PR-SOM explores the already selected regions and applies SOM on mobile and immobile hydrocarbons. The last iteration recursively applies PR-SOM to identify areas away from existing wells on the already defined regions from last iteration. The algorithm allows further definition of sweet spots based on more parameters and will further increase the potential value of the classified regions.
PR-SOM was applied to a carbonate reservoir with the objective of identifying un-swept areas as potential candidates for infill drilling. To compare the resulting potential target regions, an implementation of sweet spot identification algorithm and conventional approaches were applied on the same field. The results show that PR-SOM generated more accurate and conservative regions reducing the risks and increasing the confidence in the designated regions. In addition to obtaining more accurate clustering results, using PR-SOM allows extending the search to increase the value of required targets whereas previous work has to adhere to the original selected parameters (static or dynamic) for region identification and selection.
Geological Models Comparison and Selection for Multi-layered Sandstone Reservoirs
Authors: Yong Li , Chunxia Jia , Benbiao Song , Baozhu Li , Yixiang Zhu , Qihao Qian , Chenji Wei 
Published: February 2017

Abstract
The inter-zone and intra-zone heterogeneity are the key issues for multi-layered sandstone reservoirs. While usually lots of equal probability fine geological models which match all constrained data can be built, and how to select the representative models for reservoir simulation is a problem. This paper presents how to compare different geological models and select representative models in detail for a multi-layered sandstone reservoir in Middle East.
Through detailed geological characterization and dynamic description, different equal-probability geological models are built. And through geological check and analysis on each model, a preliminary comparison and understanding of each model are conducted, including gridding method comparison, vertical and lateral connectivity comparison etc. Then based on streamline numerical simulation, performance of each zone, each well for each model are compared in detail. Most performance are as we expected, but some are outliers. Through detailed analysis, the fundamental reasons for performance difference and major factors impacting on reservoir performance are determined. Finally, three models are selected for next reservoir simulation.
Take K reservoir in Middle East for example, it is a large multi-layered sandstone reservoir of deltaic environment. K is influenced by fluvial, tide and wave, which results in great variations of sand bodies’ distribution, reservoir quality and connectivity. Nine equal-probability geocellular models of K reservoir are built, which use three different lateral connectivity patterns with three vertical gridding approaches representing different vertical connectivity during modelling. Model expected performance are firstly determined based on geological analysis of each model. Then, based on streamline simulation, performance comparison including water cut variation, recovery, etc. are conducted to all models for the zone level, member level and model level. Three models are finally selected which represent Upside model with good lateral and vertical connectivity, Expected model with medium connectivity and Downside model with poor connectivity respectively. These models can be used for reservoir development strategy and risk management study.
This paper offers a case study of geological model comparison and selection mainly based on streamline simulation for a multi-layered sandstone reservoir. It ensures the selected models have reservoir heterogeneity correctly characterized, and the selected models are then used for the next development strategy and risk management study. It also provides a methodology and reference case for engineers to study on other similar reservoirs.
First Five-Zone Smart Completion Technology Deployment in ERC Well
Authors: Zahrani A. M. , Amri M. A. , Yateem K. S. , Mendes G. D. 
Published: February 2017

Abstract
The global demand for energy is on the rise daily, this puts a heavy burden on Oil and Gas companies as the drilling and production challenges are increasing. Efficient and cost-effective solutions are always sought. Drilling multilateral horizontal wells is considered as one of the optimum solutions to maximize recovery with minimal cost in terms of wells drilled. The production from multilateral wells imposes it is own challenges, such as flow distribution and contribution from laterals. Installing smart completions in multilateral wells was a huge breakthrough and revolutionized the industry. The idea behind smart completions is to continuously monitor and control the production from each lateral individually. With the current configuration of downhole packers, the number of interval control valves (ICV) installed per well is four at most, which limits the number of effective laterals in a well. Considering the primary objective of minimizing drawdown and hence maximizing sweep efficiency from each well, it was studied and simulated that some reservoir compartments have an optimum number of five laterals, which makes it complicated to control and optimize the production.
This paper exhibits the deployment of the first "5-Zone Smart Completion" technology in a five lateral well, to control the flow contribution from each lateral. Each completion section installed is comprised of a gauge carrier, a hydraulic flow control valve, a packer with feed-through ports and a sub to accommodate and secure control line splices. The technology enabled the control of the flow rate from five different zones and the measurement of pressure and temperature from each compartment. The completion design included another two pressure and temperature sensors downstream of the flow, only a few hundred feet above the gauge of the upper zone, utilizing a single electric cable to power up and communicate with the surface panels. All hydraulic valves were successfully tested and fully cycled in place and the packers installed at the programmed depths upon installation. The technology enhancement that supported five zones completions ranges from material technology, which permitted enough metal to be removed from the packers, where seven, quarter-inch bores, have to be drilled for control lines to be run to accommodate electronics and telecommunications. This development enabled up to 16 sensors to be connected by one single electrical conduit. The paper presents the production string concept, the technology used to achieve seven bores in the packer, while maintaining the packer's integrity, the complete sequence of pre-job preparation, and the installation outcomes, with its impact on the downhole flow controls.
Capillary Based Surface Controlled Subsurface Safety Valve Systems Solution for Problematic Wells
Authors: Wagner Alan N. 
Published: February 2017

Abstract
With growing regulatory requirements focusing on well safety and risk mitigating barriers, there is an increased requirement for surface-controlled subsurface safety valves (SCSSVs). Most SCSSV's provide well protection by means of a normally closed flapper-type closure mechanism that prohibits deployment of capillary or through-tubing based solutions which would not allow the flapper to fully close in the event of an ESD.
Operators desire cost effective rig-less deployment of capillary-based solution(s) to increase production and or reconnect a non-functional hydraulic control system. To date flow actuated subsurface controlled safety valves have provided a solution for loss of hydraulic control of a tubing-mounted SCSS; however, these valves are becoming less desired due to decreasing acceptance from regulatory agencies. Additionally, traditional post-completion chemical injection systems beyond a SCSSV have not been possible for continuous well-stimulant injection, nor has a solution for post-completion gage monitoring past a SCSSV been achieved.
This paper discusses technology enabling rig-less ability to reconnect a hydraulic system to a SCSSV or Safety Valve Landing Nipple by deploying a thru-tubing capillary based system inside the SCSSV / SVLN while maintaining functionality of the safety valve. In addition this solution can be utilized for continual injection of chemicals directly below the SCSSV and onwards to production zone depths. Further a downhole gage can be installed directly below the SCSSV and up to depths of 20,000 feet. Each of these functional characteristics can only be realized though the introduction of this novel capillary based solution, which maintains the "fail-safe" closure capability ensuring well control against a catastrophic event were to occurring at the surface or below.
Optimization of Underbalanced Coiled Tubing Drilling in Hard Sandstones
Authors: Al-Humood Malik Mohammad , Al-Khamees Shaker A , Mehmood Khalid , Cain Pat 
Published: February 2017

Scope & Objective
Underbalanced coiled tubing drilling (UBCTD) is one of the keys to unlock the true potential of the tight and abrasive sandstone.
The sandstone formation is mainly characterized by hard and abrasive sandstones interbedded with shale and siltstone. Typically, the sandstone formations are encountered at very deep depths. They are the most difficult sandstone formations to drill, with rock unconfined compressive strength (UCS) of up to 35,000 psi and internal friction angles ranging from 25 to 60 degrees. These conditions make it very difficult to drill and reach optimal lateral lengths. Additionally, it is very difficult to perform an openhole sidetrack (OHST) in such hard and abrasive formations, compared to more porous carbonates.

Methods Procedures & Process
This paper will cover some of the key steps in optimizing underbalanced coiled tubing drilling in hard sandstones from different aspects such as drilling challenging profiles at high build rates, optimizing the rate of penetration (ROP), and also increasing formation contact by successfully performing OHST to deliver multiple laterals. The paper covers the following topics:

Results, Observations, Conclusions
The combination of technology and process has so far resulted in successful delivery of many sandstone wells with multiple laterals drilled on most of the wells, totalling more than 35000 ft in this hard and abrasive formation. The first-time success rate of openhole sidetracks was 96%. The average ROP and bit run lengths have also improved consistently.

Novel/Additive Information
It is expected that the recent improvements and consistency in delivering the sandstone UBCTD wells, will enable engineers to expand the horizon of UBCTD to several other fields, and tap the true potential of sandstone formations.
Fluidic Diode Autonomous ICD Multiphase Performance in Light-Oil Reservoirs
Authors: Corona Georgina , Fripp Michael , Yin Weiqi 
Published: February 2017

Abstract
Light-oil reservoirs are affected by the undesired production of water and gas. After breakthrough, these undesired fluids decrease the life of the well, leaving valuable reserves downhole. Inflow control devices (ICDs) delay the production of these undesired fluids; however, they become ineffective after water and gas production begins. Multiphase data and production installation history show how the Autonomous ICD (AICD) with fluidic dynamic technology favors the production of light oil while restricting gas and water.
The fluidic diode AICD completions have been successfully installed since 2011 in carbonate, sandstone reservoirs, as well as standalone screens and gravel pack completions. The fluidic diode AICD responds to changing well conditions with no action from the operator. When water and/or gas reach the wellbore, the AICD changes (with no moving parts) the flow path of the fluid and restricts its production. The flow through the device has been validated with extensive testing for single-phase oil, water, and gas. To characterize its performance with the mixture of oil and undesired fluids, multiphase testing has been performed simulating various water cuts (WCs) and gas volume fractions (GVFs).
The AICD was characterized by measuring the pressure drop vs. the flow rate at various oil viscosities that represent the light-oil formations in the Middle East. The WC and GVF of the test fluids were altered by increasing the water and gas ratio. This ratio increase enables representative testing of downhole conditions for Middle East reservoirs. The flow performance tests show that the fluidic diode AICD enhances the production of light oil and restricts water and gas as the ratio in the mixture of the undesired fluid increases. When comparing the AICD to a traditional ICD, the AICD exhibits at least 40% more flow of oil than water and approximately 50% less production of gas. Reduced water and gas flow helps reduce operating costs and represents more revenue from the oil production as a result of extending the life of the well.
The fluidic diode AICD is a reliable solution to increase the ultimate recovery with no intervention or moving parts. It has been proven that it can promote hydrocarbon production and restrict the production of gas and/or water. The AICD flow performance is predictable in single and multiphase flow. The fluidic diode AICD has been successfully installed in light-oil reservoirs in the Middle East and the North Sea.
The Use of Rock Physics Models in Exploration Contexts
Authors: Debec P. 
Published: February 2017

Abstract
The use of seismic amplitudes is crucial to understand the reservoir properties and fluid content. Because the Exploration themes and targets are changing, a very well informed and conscious interpretation of amplitudes is compulsory: are they illustrating petrophysical properties, facies, pressures, fluid content? The need for Rock Physics Models is more pressing than ever.
A Rock Physics Model (RPM) is a set of equations, relating rock density, incompressibility and shearing moduli (K and MU resp.) to intrinsic parameters such as mineralogy, porosity, facies, texture, etc. and external parameters such as burial, fluid, pore pressure, stress history, etc. A Rock Physics Model, when available, can help in estimating the elastic parameters of "any" rock, in "any" (calibrated) condition… [elastic parameters]=RPMRPM ([petrophysics]; [pore pressure].
Any combination of elastic parameter can be calculated. Density, K and Mu moduli are the native ones, then Vp, Vs, impedances (acoustic, elastic, shear), Lamé coefficients, reflectivity (near, far at any angle) can be easilly inferred. With a given wavelet, Near and Far synthetic traces, as well as AVO responses will give a priceless guide to seismic interpretation.
This paper doesn't aim at describing what an RPM is or how it is built and calibrated; but at describing the different uses, mainly in Exploration contexts.
This paper will illustrate the different fields of application of Rock Physics Models in Exploration contexts: –the first domain in which Rock Physics Models are not typically expected is Pore Pressure Prediction–one of the typical use of Rock Physics Models is for Reservoir Characterization (petrophysical properties)–it will also help risking geological scenari, selecting the ones that are fully consistent with seismic images (fullstack, near or far substack, avo…), and optimizing the others–Rock Physics Models may as well help to challenge the presence of hydrocarbon, by comparing the expected effects to those potentially due to lithology, porosity, burial and pressure variations.
This approach definitely leads to a better risk assessment: all those steps must be part of any DHI evaluation workflow.
Increasing Oil and Gas Production by the Application of Black Oil Foamers
Authors: Chakraborty Soma , Lehrer Scott E. 
Published: February 2017

Abstract

Objectives/Scope
As petroleum wells age, reservoir pressures decrease, and the hydrostatic head of liquid in the production tubing increases. In gas field applications, aqueous surfactant-based foamers and condensate foamers have successfully unloaded well fluids and increased production. However, neither technology is effective for crude oil wells.

Methods, Procedures, Process
Laboratory research was conducted to develop a black oil foamer (BOF) that could meet numerous field application requirements. The foamer had to be effective for a wide variety of crude oils and suitable for batch applications and continuous application by umbilical, capillary, or gas lift. The foamer also had to be thermally stable in the wellbore, not negatively impact asset integrity, and be non-emulsifying. The resulting foam had to be sufficiently stable to unload liquid from the well and resolvable by common defoamers. This paper describes several successful field applications of the new BOF.

Results, Observations, Conclusions
The BOF was applied into a subsea Gulf of Mexico oil well. This well experienced slugging and flowed intermittently for only 2 weeks, followed by an extended 6-month shut-in. After the well had been shut in for 2-months, the BOF was applied via umbilical and successfully unloaded the flowline and riser. The production cycle increased from 2 to 8 weeks and annualized oil recovery from 100,000 to 550,000 barrels oil. The foamer did not negatively impact oil/water separation or overboard water quality.

Novel/Additive Information
The application of a BOF can provide several benefits to the oil producer. It can alleviate liquid loading in flowing oil wells, increase oil and gas production, reduce slugging and downtime of cycling wells, improve suboptimal gas lift performance, and restart wells temporarily shut in for maintenance or due to liquid loading.
Innovative Non-Conductive Mud Borehole Imaging Technology Improves Turbidite Reservoir Characterization; Offshore Nile Delta, Egypt
Authors: Emam M. , El Araby A. , Nassar M. , Felifel E. 
Published: February 2017

Abstract
The Eastern Mediterranean hosts some of the largest and most prolific gas reservoirs in the region. These reservoirs have been deposited as slope submarine channels and basin floor turbidite sand sheets. The quantity and quality of production is often controlled by the architectural elements encountered. Slumped and deformed facies could hinder production in submarine channels of the slope setting, which are limited in lateral extent. Although laterally continuous and parallel thinly bedded turbidite sheets of the basin floor offer great lateral extent, they often exhibit poor vertical connectivity and low apparent resistivity due to thinly bedded sand/shale sequences.
An exploratory well was drilled in the Offshore Nile Delta targeting slope and basin floor deposits. Although seismic attribute interpretation provided a general outline of the area, there remained the uncertainty of whether the depositional setting encountered by the penetrated succession belonged to slope channels or basin floor setting. The value added through borehole image integration provided information regarding some unanswered questions: 1) Are sidewall cores representative of surrounding lithology? 2) Do sedimentary features support a slope or basin floor model? 3) Are there natural fractures to enhance porosity? 4) What is the reason for low porosity in the sands? 5) Are there additional thin beds between channel elements?
To answer all these questions, detailed structural, sedimentological and sand count analyses were performed on the micro-resistivity image, logged over a 500 m succession. Interpreted electro-facies differentiated the internal architectural elements from structural events within the penetrated succession. Slumping and water escape structures supported a slope channel setting while dip patterns directly above channel fills were interpreted as levee complexes of nearby channels. Sand counting of the image resistivity arrays included all possible thin beds that could contribute to pay while excluding all deformed facies that would hinder production performance.