bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effective Wells Corrosion Mitigation in Two Major Middle East Fields: A Case Study
Authors: Alzahrani Mohammed S. , Senusi Kamel X. , Lewis David R. , Al Aty Adel Y. , Shinaiber Fahad A. 
Published: March 2015

Abstract
The focus of most waterflood or pressure maintenance projects is on the performance of the production and injection systems to ensure maximizing field rates and efficiencies. Yet there is a third leg to this operational triangle: the water supply system including wells and gathering system. This paper presents a case study of operational strategies and programs developed from experience from mature Field "B," and then translated to a revitalized re-started Field "F." These strategies include the use of tubeless completions of the water supply wells to maximize the water production rate and the subsequent implementation of a "build-down" strategy consisting of the installation of smaller casing sizes to isolate impaired casing sections and well monitoring with corrosion logs to address casing integrity issues.
Over time, the casing profiles became smaller, the rate of casing integrity issues accelerated and the overall supply well rates could not meet the increased injection demand. These casing integrity issues (up to 60% metal loss in some wells) necessitated a shift in strategy from the mechanical "build-down" to a mitigation strategy to extend the life of the existing supply wells. The "build-down" strategy was effective from 1975 to approximately 2006 in isolating casing integrity issues. The initial chemical squeeze inhibition campaign completed from 1979 to 1981 floundered on the monthly treatment requirements and the attendant high cost for these treatments. As casing profiles become smaller over time, a revamped corrosion inhibitor treatment program was completed quarterly and has been found to extend the well service life by 7 years so far. Furthermore, this case study will review the efficiency of the use of the same corrosion mitigation squeeze strategy in the revitalized Field "F."

Introduction to the Water Supply System of Field "B"

General Background
The mature Field "B" has been in service since 1967 with a peripheral waterflood operation for pressure maintenance since 1972 into the two primary oil producing zones. Waterflood operations are supported by the use of water supply wells completed in a regional water aquifer, sandstone characterized by very high deliverability, with rates of up to 70,000 barrels of water per day (BWPD). This supply water flows to the surface supported by the formation pressure with surface flowing wellhead pressures (WHPs) of between 100 to 125 psig. Initial injection requirements were in the order of 250,000 BWPD in 1983 and have expanded to approximately 363,000 BWPD as of July 2013. At injection startup, there were 21 supply wells, and at July 2013 there are 18 active supply wells. Supply water is gathered from the wells through two flanks to the main operational facilities where the water is pumped into the various water injection wells. It should be noted that these main operational facilities are located within 1500 meters of the Arabian Gulf.
Development and Testing of Advanced Wireline Conveyance Technology for Rugose Open Hole Conditions
Authors: Ahmad Zamri A.  F. , Myers C. H. , Abdelzaher O. , El-Ghammal M. , Ahmed S. , Remmert S. 
Published: March 2015

Abstract
A newly developed style of bottom nose assembly for wireline logging tools is capable of maintaining logging string momentum as the toolstring traverses highly rugose sections of the wellbore. This can reduce or eliminate the need for other conveyance technologies in deviated wells and aid successful descent in horizontal wells.
Although current technology has addressed a significant portion of the market, conveyance in rugose open hole still presents a significant challenge. Drillpipe and coiled-tubing conveyance of wireline logging tools has cost and risk considerations, for example logging tool hold-up on ledges in rugose hole can result in costly hole conditioning and re-logging operations. More recent advances in conveyance technology, particularly open hole tractors, have provided additional options for conveying open hole wireline logs. However, rugose hole also presents challenges for open hole tractors including limited opening diameters that result in loss of wall contact, effect of contact forces on rugose formations, and ledges that hold-up logging toolstrings.
Starting from a novel physics based modeling approach of the conveyance operation in rugose open hole, and armed with years of logging experience and data, a family of wireline conveyance tools (Fig. 1) were developed and tested to address this challenge. Exhaustive laboratory based testing supported by virtual testing and simulation verified the proposed tool concepts. Intellectual property protection through invention disclosures and filing of patents was then completed. A number of field-worthy prototypes were then developed. Finally several promising field trials were conducted confirming the viability of the developed technology.

Introduction
Hole rugosity, typical of certain formation zones in Qatar's North Field, poses a significant challenge to achieving the RasGas 100% wireline conveyance vision. The main contributors to such hole conditions are ledge effects, and cutting effects. Conveyance through such zones is critical to enable access to the target reservoir. Claystones in this zone are mechanically weak and break out, while neighboring anhydrites, limestones, and dolomites can withstand stresses and remain effectively in gauge (8.5"). This results in sharp transitions between broken claystones and competent rock intervals (ledge effects). It is noted there is insufficient rock integrity in the overall interval to increase mudweight to balance rock stresses in certain weak intervals. As well, increased mudweights would significantly increase logging risks in the reservoir itself. These breakout zones encompass all 360 degrees around the wellbore wall and can contribute to holding-up descent of the toolstring [1–7].
Challenges in Uninterrupted Production and Supply of Gas to Mega LNG Trains
Authors: Kumar P. , Mitra S. 
Published: March 2015

Abstract
The paper will highlight key production and operational challenges with complexity in feeding natural gas to mega LNG trains. The unique feature of Qatar's LNG project is the integrated energy value chain, starting from offshore gas reservoir and wells then all the way to liquefaction, transportation terminal and delivery to international customers. The natural gas starts its journey from giant North Field reservoir; is produced through huge mono-bore wells, flow continues via subsea wet gas pipelines to onshore where it is separated into condensate, water and feed to the world's largest LNG trains. The major ventures Qatargas2 and Qatargas3&Qatargas4 operate gas wells, completed in Khuff reservoir, spread over several wellhead platforms, transport gas through multiple multiphase wet gas pipelines to four mega LNG trains at onshore.
The planning strategy for start from right amount of gas extraction with right composition while achieving uniform draw down at reservoir level continues until controlling gas volume from each well complying with facility design limit, within operating boundaries from flow assurance point etc. Time delay from offshore to onshore through pipeline transfers, must be considered on volume and composition estimation of gas. Several activities on wells, wellheads, subsea pipelines add further complexity to the process.
As gas is becoming the energy of choice for the world community, sharing knowledge and experience of producing and continuous gas delivering to maintain the critical supply chain will add value to the hydrocarbon industry.
The paper is focused on the complexity of factors, challenges of planning and executing supply along with several other factors to this element of big energy supply chain. Multiple boundaries, affecting gas movement need to be respected, monitored and achieved. The responsibility lies in having complete knowledge of all factors, ability and experience to steer through the complex set up; fail proof procedures supported by world class execution style.

Qatargas - World's largest LNG Producer
Qatargas Operating Company Limited was established in 1984 and became the largest LNG producing company in the world, with an annual LNG production capacity of 42 million tons per annum (MTA) in 2011. Qatargas LNG reaches to customers all over the world with LNG production through seven trains, of which four are the largest in the world - known as mega-trains.
Qatargas offshore production is located approximately 80 kilometers northeast of Qatar's mainland and is sitting on the world's largest non-associated gas reserve named Qatar North Field. Qatargas onshore LNG trains are located in northern tip of the country at Ras-Laffan industrial City within a plot of 3.9 square kilometers area.
Spatial Modeling of Jurassic Arab Reservoir Depositional Environments as a Guide to Reservoir Connectivity Anisotropies: An Example from the Dukhan Field, State of Qatar
Authors: Stanley Rowan , Al-Ansi Hussain , Weber L. James , Snow John 
Published: March 2015

Abstract
The Arab C reservoir interval of Qatar Petroleum's Dukhan Field is a prolific oil producer. After sixty years of development activity and with hundreds of logged and cored wells, there is an extensive database of rock, geophysical and production surveillance information available for interrogation. The reservoir hosts an accumulation of carbonate lithologies and textures representing a depositional organization of subtidal, intertidal and sabkha environments. A Transgressive System Tract defines the Lower Arab C, migrating upwards from a complex of beach grainstones to a maximum flooding surface featuring muddy carbonates with sporadic encrustations and associated Thrombolite growths. High frequency parasequences within the overlying Highstand System Tract (HST) of the Upper Arab C form a sedimentological pattern from intertidal to sabkha facies, with increasing prevalence of thin isolated high productivity grainstones.
From a practical engineering perspective, the upper parts of the HST collocate with development uncertainties associated with erratic patterns of producer support from offset water injectors. Core descriptions characterize these intervals as low permeability mud dominated tidal flats hosting sporadic conductive grainstone tidal channels, leeward of beach barrier islands.
Qatar Petroleum has adopted coastal hydrodynamic principles to predict grainstone anisotropic variations. The model for the shelf area has been compartmentalized into depositional tracts based on core descriptions, supplemented by predicted facies at non-cored vertical and horizontal wells using inter-dependent 3D-spatial and 1D log-based fuzzy probability. Vector representations of interpreted tidal flux directions have been used to assign analogy-realistic geometries for beach and tidal channel deposits within an environment of deposition framework. The output distributions reflect a close coupling of control data at wells within the context of sedimentary depositional dynamics, linked to production surveillance. An objective for high resolution 3D static modeling of rock textural and petrophysical anisotropy is the optimization of future infill horizontal wells to maximize IOR sweep efficiency.
Effective Utilization of Smart Oil Fields Infrastructure towards Optimal Production and Real Time Reservoir Surveillance
Authors: Al-Yateem Karam , Al-Amri Meshal , Ahyed Rabea , Aminzadeh Fred , Althukair Ahmed , Al-Khelaiwi Faisal 
Published: March 2015

Abstract
Exploration for fossil fuels has resulted in finding thousands of hydrocarbon fields around the globe for over a century. During this timeframe, technology has advanced in a rapid mode with several innovation milestones in this journey. One of those milestones is the implementation of horizontal, multilateral and complex wells that require best-in-class technology to ensure control of the well for optimum production through downhole devices, such as smart chokes and inflow control valves (ICV). Lately, the concept of an "intelligent field" has been embraced by more and more operators with expectations for higher recovery from the reservoir. In addition, installation of permanent downhole monitoring systems (PDHMS) in both free flowing and wells equipped with electrical submersible pumps (ESP)provides continuous monitoring of reservoir parameters as an indispensable tool for reservoir surveillance. Their installation eliminates well intervention data acquisition operations and reduces nonproductive shut-in time during rig-ups, which enables significant improvement of reservoir surveillance in real-time and focused utilization of resources in manpower, capital and assets.
Saudi Aramco is tackling existing problems through the utilization of technologies from smart maximum reservoir contact (MRC)/multilateral wells and mega-cell reservoir simulation to the implementation of fully integrated intelligent fields and geosteering on real-time mode, all offering a widerange of interdisciplinary domains for development and progression. This paper will discuss the integration of smart sensory and control devices within the company's fields, deployed towards finding the optimal production strategy whether the wells are producing naturally or artificially lifted, meeting the designated targets and providing the much needed flexibility in its operations. The latter is of particular importance in fields that are located in remote, offshore, or near populated areas where safety considerations dictate less human intervention. In addition, effective methodologies of data mining and computational modeling are necessary to attain these goals. Such methodologies are effectively placed to ensure the best utilization of integrated operations, as well as to obtain accurate and useful data flow paths. In a nutshell, the implementation of technological advancements result in a positive impact on field performance in a real time fashion, extending the producing life of wells, harmonizing sweep efficiency and ultimately maximizing oil recovery from the fields.
Clad through Clad: A Mechanical Water Shut Off Solution for Commingled Production from Multilayered Reservoirs
Authors: Bourgoin Sebastien , Sobirin Muhammad , Mahardhini Antus , Nathanael Christian Andriko , Jones Mike 
Published: March 2015

Abstract
A casing or tubing clad is a metal sleeve that can be run by several intervention means into a well to isolate an area of interest, be it to provide a permanent seal over splits, holes, or perforations in tubing and casing or for water shut off. Once it is on depth, the clad or metal sleeve is expanded out against the tubing or casing wall to form a seal.
Taking the example of water shut-off isolation, conventional clad technology only permits a ‘bottom up isolation’, the current technology does not have the ability to pass through an expanded clad of the same size thus it is not possible at a later date to install a second clad below an existing clad.
To resolve this issue, in 2006 TOTAL instigated the development of a "Clad thru Clad" technology through a JIP (Joint Industrial Program) Water Management R&D Project with Maersk, Statoil, Chevron, and BP as partners. Meta was selected to develop the clad through clad technology. The project objective was to design an electric line conveyed clad able to pass through other similarly sized clads previously installed in a well incorporating a metal-to-metal interference fit with elastomer seal against the 5-1/2" production casing or tubing wall.
In addition to the dimensional, pressure rating (5000 psi absolute, 2000 psi differential) and temperature rating (125 degC) constraints, one of the major challenges was to achieve sufficient collapse rating for the clad once expanded.
The Internal Clad™ is deployed using a hydraulic expansion system. The setting tool consists of a standard electric line cable head, an electronic section (consisting of gamma ray (GR), a casing collar locator (CCL), a motor control module and pressure sensors), a down-hole reservoir, hydraulic module (consisting of motor, a pump, an intensifier and valves), and the setting tool itself.
The first trial was performed in Total Indonesia's Peciko field; well C, a gas well producing from a multilayered reservoir. The field trial was SUCCESSFUL although a number of improvements for future operations were identified.
A Tool to Tackle the Challenges of the Treatment of the Back Produced Viscosified Water
Authors: Rambeau O. , Jacob M. , Rondon M. , Jouenne S. , Cordelier P. 
Published: March 2015

Abstract
When the Enhanced Oil Recovery process involves a polymer injection (P, and/or SP), both surfactants and polymer are expected to be produced with production fluid, at different ratio along field life. This means changes of miscibility of fluids versus time, leading to some challenges with regard to the process and its flexibility against time. Depending on the start up of the EOR production through field life, more water treatment difficulties would have to be managed comparing to separation issues; otherwise the efficiency of both water treatment and separation could be partially lost.
This paper is focusing on water treatment technologies assessment regarding inlet characteristics of produced water in presence of HPAM polymer back production. Technologies to be tested have been chosen to tackle expected thinner oil droplets in water emulsion. To answer the request of high quality of water (oil and solids contents targets) for re-injection, water technologies like filtration and centrifugation have been assessed through lab bench screening.
Results are variable depending on technologies and severity of inlet conditions but they look promising. A pilot scale has been designed, a platform of tests has been built to help projects better design their process and subsidiaries optimize existing processes. This platform supplies viscosified water with degraded polymer to mimic field conditions, which is mixed with oil and solids to generate actual field produced water. This recombined back produced viscosified water feeds the open loop for the testing of various water treatment equipment. Oil droplet size is controlled on line as well as oil content. The scale of this platform allows screening of a rather large range of characteristics of back produced water in terms of oil droplet size, polymer content and viscosity, in order to qualify a suitable technology for a given range of operability.
Recent Advancements In Vessel Desanding Technology
Authors: Opawale Adekunle , Abdalla Tarig 
Published: March 2015

Abstract
Production of formation sand and other solids with wellstreams has been a big challenge in the petroleum industry. Presence of sand in the production stream can cause erosion of upstream facilities and - even more commonly - clogging of flowlines and accumulation in production vessels; reducing residence time and performance of separator internals.
Several methods have been applied in the petroleum industry to remove deposited sand from production vessels. Some of the drawbacks with these technologies are: localized sand removal, excessive use of water, interference on vessel liquid levels, compromise of water and oil quality, risks of clogging, huge sand system infrastructural size etc. Direct consequence of these situations would be unmanageable disturbances on production operations, and eventually leading to unplanned shutdown, and production loss.
Recent innovations on design of vessel desanding internals at FMC Technologies are the Dual and Single Vessel Desanding Systems. While the dual desanding system integrates a set of systematically arranged jet nozzles and a novel hydrodynamically designed suction system, the single desanding system is a unique combination of a smart elliptical fluidization technique and suction in a single compact design. This paper presents both technologies, with special focus on their developments and qualifications. Case studies are presented; highlighting the benefits of the new technologies, as well as their application possibilities.

Introduction
Sand and other solid particles are usually produced with oil, gas and water from most reservoirs in the world. In the United States, reservoirs in the Gulf of Mexico, California and Texas tend to produce more sand. Around the world, sand production is common in West Africa, Canada, China, Venezuela Trinidad, Cameroon, Middle East, Indonesia and parts of the North Sea1. The phenomenon of sand production is directly related to any/combination of the following: unconsolidated nature of some reservoirs, high drag forces created by increased produced fluid and accelerated water influx.
As explained by the illustrative schematics in figure 1, disintegrated sand particles from the formation rock matrix are transported up the wellbore, through the production system. Thus unconsolidated sandstone reservoirs would tend to produce more sand particles, especially when the wells are becoming mature, with lots more water influxing. Proppant solids are also produced from wells following fracturing treatment programs.
Although downhole sand control mechanisms are usually in place in most wells, certain cut-size of sand particles would eventually get produced to the surface because wide particle size distributions always exist in the reservoir. This ranges from 1micron to over 10,000 micron. Sand particles produced to the surface leads to a wide range of operational challenges.
Program Acceleration - CASE STUDY
Authors: Al Utaibi Abdulwahed Zayid 
Published: March 2015

Introduction / Summary
Karan Gas Program has successfully completed Saudi Aramco's first offshore, non-associated gas development achieving record early gas in 2 years and 3 months with full production in 3 years and 4 months. Figure 1 shows completion of the first offshore non-associated gas production platforms. The Karan gas field is located offshore approximately 110 KM in Saudi Arabian Gulf territorial waters. It was discovered in 2007 and has a production capacity of 1,800 million standard cubic feet per day (MMSCFD) of natural gas.
The Karan Program achieved the corporate objective of maintaining sales gas supply to Saudi Arabia from 2011 onwards by executing the 1,800 MMSCFD non-associated sour gas program. The increased gas supply will be utilized for power generation, water desalination, chemical feed stocks, and as sales gas. The increased utilization of natural gas for domestic consumption decreases the amount of fuel oil required, thereby freeing up that valuable commodity for export and commercial utilization.
In order to meet its business objectives and provide value to its stakeholders, the program was executed under four sub - projects that were developed concurrently. A brief description of these four sub-projects is as follows.