bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study on the Effect of Spiral Flow on Wax Deposition Volume
Authors: Theyab Muhammad Ali , Diaz Pedro Antonio 
Published: November 2016

Abstract
One of the main flow assurance challenges in the oil industry is wax deposition. It can result in the restriction of crude oil flow in the pipeline, creating pressure abnormalities and causing an artificial blockage leading to a reduction in the production. Wax can precipitate as a solid phase on the pipe wall when its temperature drops below the Wax Appearance Temperature. The objective of this study is using spiral flow to mitigate wax deposition.
An experimental flow loop system was built in the lab to study the variation of wax deposition thickness under the single phase transport. A series of experiments were carried out at different flow rates (2.7 and 4.8 L/min) to study wax deposition and measure the wax thickness. The effect of factors on wax formation such as spiral flow, inlet coolant temperature, pressure drop, temperature drop, flow rates, time and shear stress have been examined.
The spiral flow created inside the pipe by inserting a twisted metal along the pipe, which will create high shear stress affecting to wax deposition. The results show that the wax inhibition percentage WI % by using the spiral flow at flow rate 2.7 L/min, inlet coolant temperature14 °C, was 65%. At flow rate 4.8 L/min, inlet coolant temperature 14 °C the wax inhibition percentage was 73%. Experimentally, it was found the spiral flow more efficient than the chemical inhibitors. The WI % increased, by merging the effect of the spiral flow and the inhibitor at flow rate 2.7 L/min, to 75, 92.2 and 100 % at inlet coolant temperatures 14, 24 and 33 °C, respectively. The WI % was increased by combining the influence of the spiral flow and the inhibitor to 4.8 L/min, to 83.5% at inlet coolant temperature 14 °C, 94.3% at 24 °C and to 100% at temperature 33 °C.
This percentage of inhibition will increased rapidly by increasing the inlet coolant temperature and decreased by reducing the inlet coolant temperature.
This technique of creating spiral flow inside the test section of the pipe will provide a step forward in flow assurance technology to mitigate the deposition of wax.
Completion Planning and Execution of the World's Longest ICD Partially Cemented Production System in an Offshore Horizontal Well
Authors: Aljubran M. J. , Looni Q. D. , Ramadhan A. A. , Neacsu M. , Mora C. T. , Emam A. A. , Alomoush J. , Ali A. M. 
Published: November 2016

Abstract
Under the current downturn in the oil and gas industry, the smart design and implementation of state-of-art drilling and completion technologies are key factors toward optimum return on investment. This serves toward authority for expenditure savings, maximum productivity index (PI), and effective operational strategy with minimum risks involved. As part of these efforts, Saudi Aramco successfully deployed the world's longest 4-1/2 in., partially cemented off-bottom liner with a sandstone production equalizer system in an offshore field in Saudi Arabia.
This record was achieved through close monitoring of the wellbore condition and accurate torque and drag simulation prior to the job. The 7,389 ft. open hole was horizontally drilled in a 6-1/8 in. section and carefully geosteered through the reservoir to yield a 90% net gross ratio (NGR). As soon as the target depth was reached, a reservoir model was built using the acquired petrophysical and reservoir data, and was employed for design optimization. A hydraulically-set, off-bottom liner system was utilized to spot the ICD screen completion across the desired zones in a single run. The completion liner was designed to provide the appropriate centralization and stiffness, and ensure reaching the borehole bottom.
It was challenging to place the well trajectory across the target layer which was just below a gas cap. A reservoir mapping was utilized to better understand the well placement relative to the gas cap. The sandstone production equalizer system and openhole packers were designed to divide the wellbore into sections and balance influx from high and low permeability zones. Restricting flow across the desired sections through introducing higher pressure drops serves into preventing early gas breakthrough from the overlaying gas cap.
This achievement was a result of the extensive engineering planning and close operational alertness during sidetracking and deployment. This paper will provide further details on the design and operation phases of this project.
The Impact of CO2 Injection for EOR & its Breakthrough on Corrosion and Integrity of New and Existing Facilities
Authors: Luqman Abdulla , Moosavi Ali 
Published: November 2016

Abstract
Carbon Dioxide (CO2) Injections for Enhanced Oil Recovery (EOR) is used to increase the amount of crude oil that can be extracted from reservoirs. The CO2 injected becomes miscible with the reservoir oil. The resulting miscible fluid has the favorable properties of lower viscosity, enhanced mobility and lower interfacial tension as compared to an oil reservoir without CO2. However, the produced oil through this EOR contains greater amounts of CO2 and with the re-injection of produced CO2 this breakthrough will increase over time.
This paper is based on Abu Dhabi Company for Onshore Petroleum Operations' (ADCO) experience with regards to CO2 EOR studies on asset integrity, material selection and corrosion mitigation. It serves as a guide to the main factors effecting CO2 corrosion, an assessment on what to look for in major equipment and the recommended material of construction and corrosion mitigation / control methods.
Dry CO2 is not corrosive, however when dissolved in an aqueous phase it will produce carbonic acid (H2CO3) which starts the corrosion process. Under ideal conditions Iron Carbonate (FeCO3) scales will form which act as a protective layer preventing further corrosion. As the CO2 increases this will increase the corrosion rate as no protective scale will be present.
Factors effecting CO2 corrosion and the FeCO3 protective scale are discussed; Water Wetting, Partial Pressure, Temperature, pH, Flow Regime & Velocity and Effect of H2S. In addition, a corrosion assessment highlighting areas of importance, material selection and mitigation methods is made on new and existing facilities; CO2 Injection Systems, Downhole Equipment, New Oil Producers and Existing Facilities.
Lack of free water will prevent any CO2 corrosion from occurring. This is especially important in the injection systems for transporting CO2 as, in the absence of free water, Carbon Steel can be used. Based on ADCO's experience, downhole completion material of non-sour CO2 injector wells should be Super 13 Chromium and for Oil Producers Carbon Steel with Corrosion Inhibition with Nickel Alloy for the tubing section under the packer.
For Oil Producers, this is subject to a case by case study. The use of Corrosion Resistant Alloys (CRA) or going with Carbon Steel with Corrosion Inhibition is the main dilemma. This is dependent on the dominating form of corrosion, formation of protective scales and the ability to maintain a stringent corrosion mitigation and monitoring regime.
Finally, for existing equipment, evaluation of the current condition of the equipment is important. This will guide the mitigations required. Some prevention methods include corrosion inhibition, neutralizing acidity of service and material upgrade to CRA. Type of method used should be based on company preference and life cycle cost analysis.
This paper serves as a guide to ADCO's experience for knowledge sharing and further development of ideas and innovations.
Accelerated Learning Curve Through Industry Collaboration: Case Studies from Large Tight Gas Project Executed in an International Marketplace
Authors: Riyami Qassim Al , Briner Andreas , Nadezhdin Sergey , Plus Packers , Gurmen Nihat , Kelkar Shrihari 
Published: November 2016

Abstract
A large, strategically important tight gas project in the Sultanate of Oman progressed over 5 years on an accelerated path from exploration to the development stage. Collaboration between operator and service provider helped advance the deployment of technology that made this acceleration possible. Poor initial success in both hydraulic fracturing treatment placement and hydrocarbon productivity along with limited resources with ever-expanding work scope were the main challenges faced in the first 2 years of exploration. To address these challenges, an integrated approach to the project was taken. Technology trials and the selective deployment of technology along with improved operations gave flexibility to this new efficiency model. Close collaboration with the service provider allowed smoother and faster progress. Collaboration included joint technology mapping exercises, team visits to North American locations of the operator and the service provider with the goal of knowledge sharing, faster technology transfer, and the secondment of a senior engineer from the service provider as a full-time production technologist to the operators' subsurface team. The effective execution of strategy and implementation of various technologies resulted in an increase in the success rate of fracture placement and zonal evaluation from the initially low 50% to 100%. The integration of several disciplines was critical to achieving this goal. Technologies deployed in the project comprised of rock and core mechanical tests, such as reservoir coring, openhole stress testing, sonic measurements, continuous unconfined compressive strength measurements, abrasive perforating, various fracturing treatment designs, and several geomechanical studies targeting different aspects of fracture initiation. An additional focus was on the assessment of fracture geometry using radioactive tracers, advanced sonic logging, geomechanical evaluation coupled with geological mapping, microseismic monitoring, and cutting-edge fracture design methodology in both vertical and horizontal wells. The collaborative efforts led to evaluation of similarities and differences between North American and international unconventional projects and suggested techniques and best practices that can be applied in the tight gas project in the Sultanate of Oman. This project has been deemed one of the first commercially successful gas deliveries in the Middle East from a tight gas reservoir. Technologies, methods, and strategies developed for this large tight gas project and tested in the field will contribute to improving the success rate on similar projects around the world.
Investigation of The Reliability of Hollow Glass Spheres as a Density Reduction Agent for Drilling Fluids under Physical Impact Forces Simulating Drilling Conditions
Authors: AlBahrani Hussain I. , Al-Yami A. S. , Amanullah M. 
Published: November 2016

Abstract
The use of hollow glass spheres (HGS) is emerging as a leading solution for reducing the density of drilling fluids. With the continuous depletion of reservoirs, the presence of naturally fractured formations, and high permeability formations, the need for low-density drilling fluids is greater than ever. Gases are commonly used to bring the density of water-based drilling fluids below that of water. HGS is an incompressible alternative that has proven to be capable of eliminating deployment complications of gases while achieving satisfactory results. There is a need to examine the behavior of HGS drilling fluids overtime under downhole drilling conditions that include high temperature (HT), high pressure (HP), and, most importantly, physical impact forces associated with the attrition effect of downhole tools and equipment.
The purpose of this study is to monitor the degradation and behavior of HGS drilling fluids while being subjected to conditions simulating a downhole drilling environment. A major part of the downhole environment is the physical impact forces resulting from the interaction of the drilling fluid with the circulation system components. A specially designed experiment was employed to investigate the crushing effect of the downhole drilling components on the glass spheres. As there are different pressure ratings of HGS available, the results of the experiment provide a measure of the reliability of HGS for specific operations.
The experimental procedure was designed with a focus on the Wasia formation considering that its pore pressure falls in the range 51-58 lb/ft3. Therefore, the HGS fluids were subjected to HPHT degradation periods in a hot rolling oven with the addition of a destructive element to the dynamic aging cell. The degradation period duration is approximated to be similar to that typically required for drilling through Wasia. The results showed that certain ratings of HGS can degrade significantly enough for the drilling fluid to gain up to 14 lb/ft3 in density. The magnitude of this failure in HGS means that selecting the wrong rating has the potential to put the well under substantial risk. The potential drilling troubles due to this failure include significant loss of circulation, formation damage, reduction in rate of penetration (ROP), aquifer water contamination, and stuck pipe.
Comparison Between The Mixed-In-Place Technology and Driven Piles as Offshore Foundations
Authors: Spagnoli G. , Scheller P. 
Published: November 2016

Abstract
In certain ground conditions, open-end driven piles are not a suitable foundation option. In calcareous sand, driven piles may cause particle breakage which leads to high levels of contraction and very low pile shaft capacities. The traditional alternative to driven piles is to employ a drilled-and-grouted pile system (D&G), which is however time consuming and expensive. The MIDOS (MIxed Drilled Offshore Steel) pile is a novel pile that utilizes the mixed-in-place (MIP) technology as an alternative to D&G piles. One of the key environmental advantages relative to driven piles is the reduced noise levels during installation. The following paper summarizes the in situ tests performed in quartz sand (with interbedded clayey layers) and laboratory tests on calcareous sands. Preliminary calculations were undertaken to assess the length required to support the design loading at ultimate capacity for a driven steel tube pile and an equivalent MIDOS pile. The results show that the MIDOS pile can provide significant savings in pile length when compared to a driven, open-ended steel pile with the same loads and ground conditions in silica sands and even more in calcareous sands.
Optimizing LNG Cooling Water System Performance-Biofouling Control Through Pulse-Chlorination®
Authors: Al Din Sabry Houssam , Venhuis Lars P. 
Published: November 2016

Abstract
Abu Dhabi Gas Liquefaction Company Ltd (ADGAS) owns and operates three LNG trains at DAS island. Trains 1 and 2 have common utilities while train 3 has a separate utilities system. The three LNG trains have a once-through sea cooling water (SCW) system which includes a series of heat-exchangers. The integrity and operational availability of these heat-exchangers is is vital for LNG facilities, and they operate most efficiently at an optimised water flow conditions which are required to prevent internal fouling, scaling, erosion corrosion and/or microbially induced corrosion (MIC).
To maintain the flow of seawater cooling system at the optimum parameters and to prevent blockage and corrosion due to micro and macro fouling (bivalves (oysters, mussels) and other marine organisms) the procedure at ADGAS is continuous injection of hypochlorite at the seawater intake of the trains. During the previous years, marine growth was however observed together with an increased fouling rate within the SCW system. Hence ADGAS initiated a review of the chlorination system and its efficiency. Sweco Nederland BV (SWNL) was contracted to perform a scouting survey for the seawater species at DAS island and a review on the existing chlorination system. For optimal control of biofouling, it was concluded the Pulse-Chlorination® technology (Bruijs, 2015) was feasible and recommended. During the second phase of this work, SWNL mobilised a laboratory on site at DAS Island for an optimization study on site. During this study, procedures are followed to monitor the target species behavioural response to a variety of hypochlorite dosing settings. Through a period of 6 weeks of experimentation the optimal Pulse-Chlorination dosage procedure was assessed. This Pulse-Chlorination procedure is an optimized intermittent dosing method that enhances a repetitive mode (on /off) of hypochlorite dosing, typically varying between 10 – 20 minutes. This procedure forces bivalves to continuous switch between metabolic mode (aerobic vs. anaerobic), whereby a physiological exhaustion of the bivalve is reached, resulting in a highly effective biofouling control. Through application of the Pulse-Chlorination dosing procedure an environment is created inside the SCW system in which larvae of fouling species will not settle and thus will not develop large fouling communities. Hereby settlement and growth of biofouling is prevented. In general, the advantages of Pulse-Chlorination are numerous. For ADGAS, the optimised chlorine dosing results in increased production due to the improved cooling water hydraulics, reduced operational risks, less consumption / production of hypochlorite (hence less ECP operation and maintenance expenditures) and more importantly less chlorine levels in the outfall, which is the largest benefit from an environmental point of view.
High-Profile Rigless Well Interventions with Coiled Tubing Tower
Authors: Gaidanov Robert , Burov Anton , Zhumagaliyev Yerlan , Elkurd Hani 
Published: November 2016

Abstract
Many wellbore recompletion and recommissioning operations requires a post-drilling well interventions without a drilling rig because a rig is either unavailable or uneconomical. Rigless operations are very relevant for the well interventions performed in one of the most challenging offshore development projects in the northern Caspian basin. These complex jobs are heavily impacted by extreme climate conditions, confined offshore installations, and strict safety regulations.
To overcome these challenges and to minimize operational risks, a rigless well intervention approach was selected with a specially designed multipurpose coiled cubing (CT) support tower that can perform a wide range of service operations with a unified well rigup. All the services can be kept under a single operational umbrella with a smaller crew, and a common base pattern erected around the well can be transferred to the next service line without major modifications.
Several innovative ideas were implemented to fulfill the offshore and operational requirements: A special base section of the tower with telescopic legs fits on the narrow working pad around the well and keeps permanent structures and service manifolds around the wellhead area intact.A specially designed CT tower skid system with a three-axes moving jacking frame on top includes a rotary table to allow the injector head to revolve into the required position.
This paper describes the success story of complex rigless well interventions using a newly designed multipurpose CT tower. The provided solution is proved to be more cost effective for the same applications as a drilling rig, and effectively reduced the necessary crew size and equipment footprint. This solution is designed for effective and safe operation in diverse environments, and can be customized to accommodate new solutions that would be and technologies developed in the future.
A Methodology for Multilateral Wells Optimization - Field Case Study
Authors: Cetkovic Ivan , Shammari Majed , Sager Talal 
Published: November 2016

Abstract
During the recent decades, a significant number of multi-laterals wells with smart completions controlled by different flow control technologies has been installed worldwide. This case study is based on a reservoir developed completely with multi-lateral wells. Each well is completed with three to seven laterals with different flow control technologies.
The study covers an analytical methodology and a multiphase flow model to optimize production that has multi-lateral wells equipped with flow control devices. Optimizing the complexity of this system, and understanding the contribution of each lateral during commingled production, has become a challenging process and is the main objective of this study.
A multi-lateral well modelling process was developed to obtain a representative model, which can predict accurate results under different operational conditions. The paper also covers a well test procedure, which is essential to guarantee the good quality of the data and ensure representative results.
This methodology covers two main factors affecting multi-lateral productivity, which are a flow dependent gas-oil ratio (GOR) rate and interference between the laterals.
The multilateral production optimization process was developed successfully to represent the operational conditions and optimize the well for different scenarios based on their specific reservoir management strategy. This model was extended successfully from a single to a multi-well model, including their actual surface facility network. The model will be considered in future production strategy plans.
Wealth from Waste
Authors: Al-Ghanem Fahad , Dominic Thomas 
Published: November 2016

Abstract
Kuwait Oil Company (KOC) owns and operates eight Gas Booster Stations with around 38 Gas Turbine drivers. These Turbines work on the Brayton Cycle exhausting hot gases to the atmosphere in an Open Cycle. Every 100 MW of Open Cycle Gas Turbine has the potential to generate 50 MW of electrical energy out of exhaust heat recovery. Considering the total installed number of Gas Turbines, there is the potential to generate 450 MW of electrical energy. The study to recover this energy, which is currently wasted, is the subject of this paper.
Traditionally the heat is recovered from the exhaust of the Gas Turbines by diverting the exhaust of the Turbines through a Heat Recovery Seam Generator. In the conventional system, the working fluid is water, which is converted into steam, which turns a steam turbo-generator. Furthermore, large quantity of water is required for cooling the steam condenser. As all the Company's Booster Stations are at dessert type of locations with difficulty in sourcing fresh water for the working fluid and seawater for condenser cooling, hence the idea did not takeoff.
We have now come to know of a heat recovery system which uses Cyclopentane as working fluid and ambient air for condenser cooling. A Thermal fluid is interposed between the exhaust gases and the Cyclopentane loop to transfer heat from the exhaust gas to the Cyclopentane loop. The pressures in the Cyclopentane loop is maintained in such a way that the heat from the Thermal Fluid converts the Cyclopentane to superheated vapor and the air in the condenser condenses it after passing through a power turbine to recover the mechanical energy. The stack will be fitted with diversion damper to direct the gas either to the heat recovery system or to the exhaust in case the heat recovery is down for maintenance without disturbing gas compression. The loss of power output from the Turbine to the Compressor shaft is negligible, only of the order of 1 to 2 %.
With the implementation of this technology, the Company can ultimately recover about 300 MW of electrical power with no additional fuel. This is a very big monetary gain, around 40 million dollars per annum. It also provides an environmental edge because this energy is obtained with absolutely no emission. At current electrical energy rates, the capital cost can be recovered in very short time. It will also give the Company all the advantages of having its own power for its development needs without depending on external agencies.