bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure and Rate Rebalancing to Improve Recovery in a Miscible CO2 EOR Project
Authors: Linroth Mark A. , Rickard Andrew E. 
Published: June 2014

Abstract
In a CO2 EOR project the injected CO2 seldom sweeps all portions of each injection pattern uniformly. This is compounded by the fact that injection patterns are not always symmetrical and the injector itself may not be centered within the pattern. Areal sweep within a pattern is further influenced by pressure gradients which may not be uniform in all directions.
At the SACROC unit the approach to maximizing the areal sweep involves detailed monitoring of individual producing well pump intake pressures and producing GOR's as well as the calculated streamlines to identify opportunities for changing the direction of CO2 migration in the reservoir. It is frequently observed that response to CO2 injection occurs in only one well or on only one side of a pattern with little to no effect in the other directions. The remedy presented in this paper involves converting to flow or slowing down the pump in the responding wells (and thus raising the pump intake pressure) when their GOR exceeds a certain threshold and upsizing or speeding up the pumps in the wells on the opposite side of the pattern.
The effect of these changes is to alter the pressure distribution within the pattern and change the portion of the reservoir being processed by CO2. We have documented cases where the pattern recovery has more than doubled due to altering the streamlines in this manner. This technique of monitoring and altering the streamlines is time and data intensive but in the patterns where it is applicable significant increases in the ultimate EOR recovery can be obtained for essentially zero capital cost.
This paper discusses the pattern selection criteria, data requirements, and the timing and method of adjusting the withdrawal rates to alter the streamlines and increase areal sweep efficiency.
Analyzing The Benefits Of Utilizing 360° Panoramic Photo Survey Technology On A Shell Offshore Platform
Authors: Berger P. E. , Matsuura J. P. , Barrios A. , Hopkins P. , Wagner M. T. , Weston M. 
Published: June 2014

Abstract
Shell's Enchilada offshore platform has been surveyed in September 2012 with a specially built, fully automated 100 megapixel 360° HDR panoramic photography camera system with 3D measurement capability. Subsequently, a 360° PanoramicGuide web-based viewer was produced and made available to Shell users. The spherical photos were indexed to the facility's general arrangement drawings. Interactive descriptive menus and maps were made available to quickly locate and navigate to points of interest. Users can choose from multiple viewpoints of the Enchilada facility, view 360° in all directions around those viewpoints to virtually examine various areas/equipment in the platform, zoom in to view precise detail, and take 3D measurements between visually recognizable shapes and patterns from the viewpoints.
The paper will discuss a number of potential and tested applications, the latter where the technology has been used for the Enchilada platform:
Detailed visual assessments for engineering design, project planning, operations and safety reviews; Visual reference during conference collaboration meetings with offsite subject matter experts and email communications to assure common understanding; Visual assessments by subject matter experts, including consultants and sub-contractors that are not possible with video, standard photography or 3D models/images created from laser scans alone.
Experience using the viewer has demonstrated that users are able to improve quality and collaboration in planning work related to construction and modifications, potentially resulting in decreased cost and project recycle, improved HSE and reduced liability and risk, by minimizing or even eliminating offshore trips and time on site for vendors and other personnel. Development of new advanced visualization and communication technologies will be a key success factor for future improvements in planning, asset management and Integrated Operations, among other remote operations activities.
Micronized Ilmenite - A Non-damaging & Non-sagging New Weight Material for Drilling Fluids
Authors: Al-Bagoury Mohamed 
Published: June 2014

Abstract
Ilmenite (FeTiO3) was first introduced as a weight material in the North Sea area in the early 1980's. The quality of ilmenite suitable for drilling fluids was continuously improved to meet the drilling criteria. Ilmenite as a weight material offers many benefits over API barite such as high density (4.6SG), mineral hardness (6 Mohs), low heavy metals content, acid solubility and sustainability due to the large reserves.
Currently there are certain drilling areas such as narrow pressure margin wells, HPHT wells, deep water, ERD, and slim hole, where API barite may not offer the required performance. For those wells a controlled rheology and minimal sag is the key to success and a specialty weight material can provide this. To fulfill such needs a micronized ilmenite grade (5μm) has been developed for use as a weight material for drilling fluids. The paper will show the testing of the new grade in both aqueous and non-aqueous drilling fluids. High temperature dynamic sag and filtration results will be presented. Acid solubility in hydrochloric acid will be highlighted. The new grade shows excellent dynamic sag, stable rheology and high acid solubility, which are very useful for many drilling operations particularly deep offshore drilling. On a top of the high performance this new advanced material is a cost-effective solution for some of the high costly drilling challenges.
Failsafe Polisher for Produced Water Discharge
Authors: Rodeman Lance , Stamp Nick 
Published: June 2014

Abstract
Deepwater production facilities in the Gulf of Mexico (GoM) and other regions periodically experience short intense upsets of their produced water treatment. These upsets are due to many factors inherent in their geological formation and physical location:
Hydrate formation and associated chemical dosing procedures (LDHI, Methanol, etc.) Frequent startup/shutdown of production wells due to weather threats, new wells, tiebacks etc. Large motions on board the platform from adverse weather conditions Frequent rate changes in fluid production (slugging, debottlenecking)
Improved Zonal Isolation in Open Hole Applications
Authors: Bårdsen Johnny , Hazel Paul , Vasques Ricardo R. , Hjorteland Øyvind , Eikeskog Øystein 
Published: June 2014

Abstract
Achieving effective zonal isolation within long reach horizontal wells via conventional means, such as cement or swell packers, is becoming increasingly challenging to the industry. The longer step outs limit the Equivalent Circulation Density (ECD) due to frac/pore pressure limitations. Subsequent complex stimulation operations impose higher differential pressure (dP) across the packers.
To address these challenges, a novel design was introduced, effectively creating an expandable metal, sleeve-type annular barrier that allows cementless completions and effective zonal isolation. The design of the new annular barriers, assembled on a full bore liner, minimizes the running outside diameter (OD) whilst delivering a high differential pressure seal even within a washed out hole.
The qualification process was designed to meet the International Organization for Standardization ISO14310 V3 standard and to simulate the lifecycle of the packer during acid stimulation and later-life water management.
The benefits to operators include increased reliability and certainty for success, both in the short-term and over the life of the wells.
This paper reports recent implementation of the new annular barrier to meet the unique challenges of annular high pressure containment. Findings are supported by specific case examples, and the paper includes a discussion on design, application and performance.
Well Collision Detector
Authors: Walle Eirik , Instanes Geir 
Published: June 2014

Abstract
The ClampOn DSP Well Collision Detector is a real time ultrasonic monitoring system for detection of a drill bit in the proximity of existing wells. The system provides real time data during drilling and thus supplements collision risk analyses and positioning data. The monitoring system lends from ClampOn's well-proven series of ultrasound sensors for sand monitoring, PIG detection, and leak detection. The working principle of the Well Collision Detector is discussed briefly. An application example from a drilling operation is shown to illustrate the utility of the system.
Subsea Inspection of Vibration and Acoustic Noise
Authors: Nysæter Kjetil 
Published: June 2014

Abstract
Statistics tells us that 21% of all topside pipework failure in the UK sector is due to vibration-induced fatigue, whilst erosion and corrosion stands for 13% (Figure 1). This is not directly comparable with the subsea world. Still, we now know that aging subsea pipework and structures suffer from fatigue, in many cases caused by vibration. The number one cause of vibration-induced fatigue is flow line induced vibration (FIV). Advanced simulation and modelling are used when designing subsea structures and subsea pipework to ensure that the design minimizes the risk of harmful vibration occurring. Simulation and modelling does not fully reflect real conditions due to the complexity of the pipework in combination with the unpredictability of multiphase flow regimes. Therefore, these models are usually very conservative, with a significant safety margin built in. In some cases, this may lead to a "permitted production rate" that is less than is safely possible. Installation of permanent or temporary vibration monitoring is the only way to be sure what the actual state is. Data from instrumentation is useful for several reasons. Firstly, because it provides actual displacement/acceleration data at any given frequency and this is directly related to the rate of fatigue. By post processing raw data together with modelling, it is possible to estimate what the vibration is at locations downstream or upstream of the instrument. Secondly, by further analysis of the raw data the models can be "calibrated" to give more accurate fatigue estimates.
Development, Test and Offshore Use of a Fouling Repellent Coating for Plate Heat Exchangers
Authors: Bischoff C. , Poulsen T. , Søhoel H. , Holberg S. 
Published: June 2014

Abstract
Fouling of top-side equipment is a common but non-trivial challenge in oil production. Especially offshore, where servicing is costly and time consuming, technologies to prevent or reduce fouling is wanted. For plate heat exchangers (PHE), fouling, of both organic (e.g. wax deposits) and inorganic (e.g. limestone scaling) nature, is capable of reducing the performance of the PHE to a state where on-shore servicing is required, in just six months.
We here present the development and test of a coating system, coined CORE Coat 010, which has demonstrated excellent results in the prevention of fouling formation on titanium PHEs used in offshore crude oil processing. The coating is a Sol-Gel derived glass ceramic organic:inorganic hybrid system. Given the glass ceramic nature, the coating system exhibits efficient thermal conductivity, is highly flexible, very wear resistant and only 5 µm thick.
From initial laboratory scale tests to full scale application on complete PHE units for offshore operation, the coating has demonstrated excellent stability in crude oil contact, minimal impact on heat transfer and an excellent ability to repel fouling that would otherwise hamper operation. To date, the longest operating PHE has been in position for approx. 1000 days, compared to approx. 180 days for non-coated units, operated under similar circumstances. Besides the use on crude oil PHE's the coating technology may be applicable in other crude oil processes where fouling is an issue.
Remotely Activated Completion Technology Improves Wellbore Productivity
Authors: Harestad Fredrik , Forsyth David , Adam Malcolm 
Published: June 2014

Abstract
The Command Activated Sandface Valve (CA-SFV) was developed to significantly improve productivity by enabling improved wellbore clean-up, particularly in extended reach and open-hole completions. Inefficient wellbore clean-up of highly deviated completions is common in production wells. Current solutions include smart well technology or time consuming clean up procedures that are both expensive and difficult to implement, leading to loss in well productivity, restricted access to reserves and in some cases a requirement to sidetrack the well.
A UK operator had observed no flow from the toe of one of its wells, while experiencing high drawdown at the heel section due to the dominance of high productive intervals. This threatened the economics for the overall field development. The CA-SFV was developed based on this operator's requirement to bring a high level of control over how they selectively cleaned up and flowed the reservoir sections. The key objectives of the valve were to allow sequential clean-up of the reservoir section from the toe to the heel without intervention or incremental rig time. Each valve had to be remotely activated by a pressure recognition signal and also had to deliver the mechanical functionality of a sliding side door for future water shut-off capability along the well bore.
Development of the valve was closely monitored by the operator including a technical assurance review and failure mode and effects analysis process. The result is a successfully field proven completion tool and a new completion technique for a more optimal production regime and increased oil recovery. The increased production and recovery from using this technology made the field development economically feasible. The Sandface Valve technology has now seen well over 100 installations with a functional 100% success rate.
Based on these successful installations, the remote technology platform has been developed further to allow this remote activation technology to become applicable for other common well applications.
Evaluation of Coordinated Control During Back Pressure MPD Operations
Authors: Siahaan Hardy B. , Vefring Erlend H. , Nikolaou Michael , Gravdal Jan E. 
Published: June 2014

Abstract
Automatic control becomes increasingly important to assist drilling operations. Basically, the first stage of designing an automatic control for a simple system is by selecting a variable to be manipulated and a variable to be controlled in the system. A drilling rig has a large number of variables. This makes the design of automatic control more complex due to the number of variables. Here, we discuss three ways of dealing with ‘multivariable control’ design and evaluate them by simulation studies.
The first approach is by designing a control system to coordinate all different variables in a centralised way. The second approach is by dividing the system into subsystems, each of which has fewer variables. A control system can be designed independently for each subsystem provided that the interactions between different subsystems are small. The third one is combination between the first and the second approach.
The three different approaches of design are compared for coordination of variables in MPD. When drilling with narrow pressure margins, back pressure MPD is often used with the choke being manipulated to control the BHP. It is of interest to evaluate the possibility of having additional variables like pump rate and back pressure pump rate as manipulated variables. In particular, for the design using centralised approach we consider the model predictive control (MPC) while for the decentralised approach we consider a class of PI control. For the third approach we design internal model control (IMC). We focus on drill pipe connections where we need to control the BHP and the gel breaking simultaneously.
The design of MPC depends on a predictive model and the tuning of its parameters which can be challenging. However, MPC has an attractive feature where it is easy to include constraints in the computation. IMC has the advantage of simplicity and ease of tuning compared to MPC. The drawback of IMC is that we need to compute an inverse of a model representing our system which can be cumbersome when the dimension of multivariables increases. While the design of PI control is the simplest one, we have to observe that the interaction between the subsystems should not be critical for a certain period of time during drilling operations. The results improve our understanding of the possibilities and challenges of introducing automatic control to drilling operations.
CO2 and NOx Emissions From Cuttings Handling Operations
Authors: Saasen A. , Jødestøl K. , Furuholt E. 
Published: June 2014

Abstract
Drilling operations at a new oil and gas field will produce a significant amount of drilling waste. In the Norwegian part of the North Sea, oil contaminated cuttings have not been discharged to sea for the last 20 years because of the OSPAR requirement for max 1 % oil on cuttings. The most frequently used option when drilling with oil based fluids is to send cuttings onshore for treatment. The affiliated volumes of hydrocarbons are distilled off using different methods. On older fields it is not uncommon to recomplete a well to become a waste reinjection well.
In the later years, technology has been developed to treat oil contaminated cuttings to below 1 %. This technology has been in use on drilling rigs on the UK shelf for several years, discharging cuttings from exploration wells drilled with oil based fluids. The technology for cuttings cleaning has been improved in later years, and several operators in the Norwegian sector are now investigating the possibility for cleaning and discharge of drill cuttings when using oil based drilling fluids. The three options for handling oil contaminated cuttings, transport to shore for treatment, discharge to sea and reinjection show different environmental impacts. In the current paper, environmental aspects such as the CO2 and NOx emissions from all these three options will be presented in detail. The consequences of drilling with different rate of penetrations are outlined. The economical consequences of selecting one of these options will also be discussed.
The current analysis is based on a realistic example. The example is the development of a thought field in the North Sea area that can be drilled with a jack-up rig. The consequence of using a semi-submersible rig will be outlined. However, there will be no detailed calculation of those cases.
Real-time Fiber-optic Integrated System Used For Maximizing Coiled Tubing Wellbore Cleanouts in the Latin American Region
Authors: Webb Earl , Howard Robert , Garcia Alexis , Gleaves Jorge 
Published: June 2014

Abstract
Producing well conditions in the southern region of Mexico present challenges that can benefit from the use of a newly developed intervention technology. This paper describes the development of this real-time fiber-optic (RTFO) integrated system. RTFO is used for depth correlation and real-time pressure and temperature monitoring inside the coiled tubing (CT) and the outer annulus. Additionally, distributed temperature sensing (DTS) survey capabilities can provide instantaneous evaluation of downhole treatments in real-time. The data is transmitted by means of a 4-mm fiber-optic (FO) capillary to surface data acquisition equipment, allowing both monitoring and job execution changes in real-time. This technology allows operators to make immediate treatment decisions to help achieve the best results possible. Additional sensor expansion is possible because of the modular design of the bottomhole assembly (BHA).
This paper discusses the fast-track developmental process of the RTFO system as well as quantitative lab and full-scale yard testing. Case histories from three high-temperature deep candidate wells in the Latin American region are presented. Lessons learned from the initial field trials and the resulting next-generation design enhancements and sensor expansion capability of the tool are also highlighted.
The synergy of the CT RTFO system, cleaning nozzle selection, and a tailored fluid program proved to be a successful combination for effective cleaning of the case history wells discussed.
Measurement While Drilling, Logging While Drilling, and Rotary Steerable Systems Performance, Benefits, and Challenges in Managed Pressure Drilling and Underbalanced Drilling
Authors: Hussain Sajjad , Huelvan Yvon , Adams Waleed 
Published: June 2014

Abstract
Drilling engineers have been calculating hydrostatic pressure greater than reservoir pressure in almost all conventional drilling applications. This has resulted in various drilling challenges, such as reduced rate of penetration, differential sticking, mud losses, formation damage, wellbore stability, and formation fracture and associated cost. Managed pressure drilling (MPD) and underbalanced drilling (UBD) have played a vital role to significantly minimize these drilling problems onshore as well as offshore. Since most of the wells being drilled today include measurement-while-drilling (MWD), logging-while-drilling (LWD), and rotary steerable system (RSS) tools, the interface between these tools with MPD and UBD technologies has become extremely critical not only to understand but also to execute. These logging and steering tools have huge proven combined benefits in both MPD and UBD environments. The performance of all these tools in MPD and UBD environments is influenced by different challenges in terms of data transmission (mud pulse telemetry), hydraulics, steerability, and maintenance.
Smart Wells for Improved Water Management in the Presence of Geological Uncertainty
Authors: Valestrand Randi , Khrulenko Alexey , Hatzignatiou Dimitrios G. 
Published: June 2014

Abstract
This work investigates how smart well completions can be potentially used to delay breakthrough of injected fluids, and how to manage water/gas production while improving sweep efficiency and maximizing oil recovery factors at late stages of a fields life. The study objectives are to address, on a general and not field-specific basis, the following:
How should smart well completions be operated to effectively minimize water production and maximize economic gains? For which geological formations can smart well completions provide an added value compared to traditional ones?
A simulation model was built based on the Brugge static model, which consists of both fluvial and non-fluvial layers. Five deviated producers equipped with smart completions in different layers are used to control water production and study the impact of geological formations on the field's performance. The geological uncertainty is taken into account by using an ensemble of realizations of the reservoir properties. Both reactive and proactive control strategies are considered for the management of smart wells. The latter is achieved by optimizing oil production over a certain time period; several optimization procedures are examined and their influence on both wells and field fluids production is examined and evaluated. The results are validated for the whole ensemble to account for geological uncertainties, and a reliability study is performed to assess oil production losses that may result from a potential malfunction of smart completions. Based on the results obtained in this work, the following can be stated:
Smart wells provide the ability to effectively managing oil production while minimizing water production even when accounting for geological uncertainties; the economic gain is more significant for certain types of geological formations than others. Generally, proactive control strategies are more effective than reactive ones, if a sufficient time window is considered when conducting the proactive optimization. Depending on the reliability of the installed down-hole devices, potential malfunctions, which may occur during the smart wells life, could during the smart wells life could decrease their added value.