bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Distributed Temperature Sensing for Wax Detection and Treatment Optimization
Authors: Guzman Manuel 
Published: May 2012

AbstractState of the art technology has been incorporated into the Seria North Flank waterflood development. Both producer and water injector wells are completed with interval control valves, distributed temperature sensing (DTS) and downhole gauges. DTS has been commercially available for more than a decade, however only recently it has been employed in the oil industry. Interpretation of the data has been difficult and therefore its value questioned.This paper presents an original technique of monitoring wax build up through the use of the DTS data. PVT analysis from the appraisal well showed significant wax content in some of the reservoirs to be produced. The critical wax deposition temperature is higher than the surface temperature and therefore wax is expected to be deposited inside the tubing. The DTS provided temperature trends that showed temperature decline in a section of the tubing string; caused by the additional layer of wax between the crude oil and the gas filled annulus. The paraffin layer has its own heat transfer coefficient therefore thickness can be estimated from temperature data for unchanged flow rate and fluid composition.Using the temperature trends, the Well and Reservoir Management (WRM) team was able to determine the exact depths where the wax accumulated. This information avoided slick line interventions to determine hold-up depths and also allowed the required volume of solvents to be calculated, prior to for coiled tubing clean out. The Coiled Tubing activity enabled production to be maintained before the wax build-up could significantly impact the well flowrate. This technique has been extended to other wells and is now part of the standard WRM monitoring parameters for this field.
Brownfield Project Interface with Operating Facilities without Impacting Schedule & HSE Compliance
Authors: Zayene Hassan , Desai Hitesh K. 
Published: May 2012

Abstract
Brownfield Projects (i.e Projects involving Execution within or associated with Operational Process Plants) provide unique challenges for compliance to Health, Safety and Environmental (HSE) Regulations everywhere in the world.
While HSE Compliance is essential and mandatory, the associated procedures are often tedious and time consuming; even overwhelming the Operations personnel and adversely impacting project schedules. One such project is the Gas Sweetening Facilities (GSF) Project, consisting of one Acid Gas Recovery Unit (AGRU) inside the ARAB-D Plant at DUKHAN and one Sulfur Recovery Unit (SRU) inside the NGL Facilities at MESAIEED. This Paper highlights the measures taken at the AGRU to meet the apparently conflicting requirements of HSE Compliance and SCHEDULE Compliance.
Deal With Start-Up and Commissioning Threats and Challeges at an Early Stage of the Project for a Sucessful Handover and Project Completion
Authors: Al-Bidaiwi M.. , Beg M. S. , Sivakumar K. V. 
Published: May 2012

Abstract
The normal practice in the oil & gas industry is to implement major projects through Project Management Team by engaging external contractors. The operations team is involved only for specific activities and mostly during commissioning and start-up. Qatar Petroleum involved Operations team from the early stages in two of its major projects implemented in Dukhan fields and experienced successful implementation of the projects by meeting the project schedule and cost, smooth handover of the facility and achieved the intended objectives with adequate safety and operational flexibility.
QP-Dukhan's Operations team played a major role in providing clarity and coherence of project objectives among various divisions and geographically diverse contractors. Operations contributed immensely in many aspects such as provided site specific data to tailor the design to suit site conditions, identification and mitigation of operations risks at design stage, reviewed the design to achieve targeted production, product quality, adequacy of safety systems, met environmental regulations, ensured operational flexibility, dealt with interface issues, ensured operation and maintenance philosophy to suit Dukhan conditions, utilized synergy with exiting facilities, incorporated past experiences in design and provided site coordination.
Involving Operations early helped us to capture many issues in the early stages of the project. These were successfully incorporated in the design. This resulted in minimal re-design and re-engineering and helped us to firm up the scope of EPIC contractor and avoid project delay and cost over-run. Moreover, commissioning and hand-over was very smooth and plant reached its design throughput without major startup problems and delays. The projects met their design objectives with adequate safety, integrity and operational flexibility and integrated very well with other facilities in Dukhan. This successful experience led QP to create a new division within the Dukhan Operations, dedicated to coordinating continuously all other projects.
Moving Towards Intelligent Oilfields
Authors: Al-Sulaiti A. S. , Al-Baker H.. , Beg M. S. 
Published: May 2012

Abstract
Qatar Petroleum (QP) is implementing intelligent oil field (IOF) concept in its operated field. This paper traces the development of projects which are completed as well as which are in progress. The paper also presents a case of how Dukhan oil field is well positioned to move towards a fully integrated intelligent oil field.
Successful IOF implementation can yield increased operational performance and extend field life through collaboration, optimized work processes and advanced technology.
Dukhan field present status was assessed using the maturity model and a roadmap for implementation was suggested. For the last ten years, Dukhan operations have moved steadily towards real time monitoring, control and infrastructure capabilities.
Development and Implementation of a Health Safety And Environmental Management System In The Qatar Petroleum Drilling Department
Authors: Balogun Tokunbo Gbolagade , Andaila Ali Moshin 
Published: May 2012

Abstract
Onshore and offshore oil and gas exploration and drilling activities present complex challenges with regards to Health Safety and Environmental (HSE) management. With growing energy demands worldwide, the need to optimize production potentials is pushing the industry to new frontiers for untapped reserve, thereby increasing HSE exposure and challenges. In addition, the scale and magnitude of both economic and reputational impact of past and recent incidents in the industry suggests that a business continuity model without a proper HSE management in place will be inadequate.Qatar Petroleum (QP) drilling department recognized the importance of an effective HSE management system to deliver on the business objectives with minimal HSE related impact. To achieve this, we adopted the templates presented by ISO14001:2004 for Environmental Management System (EMS) and OHSAS 18001:2007 for Occupational Health and Safety Management (OH SMS).This paper outlines how HSE management system can be developed and effectively implemented with minimal cost and within a limited timeframe using QP drilling department experience as a reference.
Operator Performance Enhancement by Alarm Management
Authors: Mahajan Sachin Ashokrao , Surve Vikram Genuji 
Published: May 2012

Abstract
The Gas Recycling plant of Qatar Petroleum, Dukhan had a tough time in dealing with huge alarms generation. Gas recycling is a big integrated process plant and has one central control room where all the unit operations are controlled. Because of the nature of the process lot of alarms are generated and most of them are for operator information purpose and do not require any operator intervention.
There were 27,000 alarms configured. And there were three common problems with alarms, Standing alarms, Background alarms or bad actors and alarm floods. There was no alarm philosophy, alarms were constantly added and rarely deleted. Alarm limits were rarely revisited. The panel operators approach was reactive to alarms as constantly alarms were generating. To deal with alarms problems, the alarm management project was implemented.
This paper will describe in detail the ongoing alarm management project in the Gas Recycling plant, QP Dukhan and aims to provide all the details of project design stage, alarm philosophy, implementation techniques and the initial benefits achieved.
The roadmap used for alarm management project includes developing the alarm philosophy, alarm rationalization, implementing the alarm changes in the DCS configuration and benefit retention. The alarm philosophy designed based on the EEMUA guidelines. The benchmark values set by the EEMUA are chosen as the project KPI targets.
The implementation of the Alarm management project require lot of involvement by the process engineer, system engineer, instrumentation engineer and experienced control room operators for rationalizing the alarms. The initial results after ongoing implementation of the alarm management projects shows that the average alarm rate per 10 minutes has improved drastically from 6.5/10 min to 1-2 alarms/10 min which is very close to the EEMUA set benchmark values. The benefits achieved due to reduction in the alarms are more productive and positive workforce and improved safety.
The overall conclusion that can be drawn from the data collected is that the steady state alarm rate has been reduced to a manageable level and the EEMUA target of less than 10 alarms per 10 min period during flood is a challenge with today's technology and practices.
Utilization of Excess Flared Gas from Gas Lift System as a Gas Injection -An Innovative Method to Reduce Emissions and to Save Energy
Authors: Janitra E. S. , Saputra R. R. , Rohman A. F. 
Published: May 2012

Abstract
Kaji-Semoga fields in South Sumatra, Indonesia, are oil fields with a gas lift population of almost 50%. Since there is no gas source available in Kaji-Semoga fields, both the gas lift and fuel system are dependent on produced gas from oil producing wells. Based on an overall review of the gas lift system, the flare is inefficient. Pressure Control Valve (PCV), which controls the flare, is opened when the gas lift pressure reaches 815 psig, yet only 800 psig is needed for a normal operation. The gas lift pressure usually exceeds 815 psig, hence gas is flared. On the other hand, compressor suction often drops below the safety level. To overcome this problem, KS-X (Telisa gas cap) is produced around 1-2 MMSCFD. The production of Telisa gas cap has a very negative impact on this formation, causing a decrease in reservoir pressure of 60% in just 4 years.
Since Telisa reservoir pressure has depleted from 900 psig to 400 psig, it is easy to inject excess gas from the flaring system. PCV is added to the gas lift system and is set at 805 psig to open. The current gas lift line at KS-X has also been modified to be able to inject the excess gas to the well via the installed gas lift valve. Based on the daily record, the injection system is able to save flared gas and reduce produced gas from Telisa Kaji by up to 1 MMSCFD. Both gas lift system and compressor suction pressure are also relatively more stable after injection.
It is concluded that the recycle-injection system is a proven and practical method to use in mature fields where there is no gas reservoir available as a fuel source. The system is able to save up to 1 MMSCFD of flared gas worth $8,000 per day (based on the local market gas price).
ESP Retrievable Technology: A Solution to Enhance ESP Production While Minimizing Costs
Authors: Szemat Vielma W. E. , Drablier D.. , Petry M. L. 
Published: May 2012

Abstract
The easy oil production is gone and current field developments require new approaches to produce oil and gas reserves in the most effective, economic and safe ways. Around the world, more than half of the wells are assisted by an Artificial Lift (AL) system. The use of these AL methods opens a range of opportunities to produce from low pressure reservoirs, low GOR, high water cuts and many others constrains that operation & production engineers are facing nowadays. Electro Submersible Pumps (ESPs) are widely used around the world as one of the most common solution for the current field development conditions.
However, ESPs represents a challenge itself in terms of production management, intervention cost and run life cycle. Eventually, all ESPs will fail and the need of a workover will be present repeated times during the well life; and many causes of failure are beyond the control of either manufacturer or operator.
To solve this issue, several types of ESPs deployment systems were designed and are currently in use around the globe (e.g.: standard tubing deployed, thru tubing conveyed, CTU deployed), but each one of them has its own limitations.
In order to enhance ESPs installation conditions, capabilities and run life management, a new approach resulted on the design of an ESP Retrievable system that will complement current major ESP providers' equipment portfolio. This technology gives the operator the opportunity to retrieve and rerun the ESP without a rig intervention by only using WL, sucker rods or CTU equipment.
The technology can be used either onshore or offshore to manage and optimize oil production by taking aside the rig need to change the ESP. This improves the oil recovery, minimizes environmental impact and increases the field safety management while reducing the overall well cost.
This paper will explore the technology design, capability and constrain, cost analysis and will conclude with installation experiences and results.
Impedance Analysis as a Tool for Hydraulic Fracture Diagnostics in Unconventional Reservoirs
Authors: Rahmani Amir Reza , Shirdel Mahdy 
Published: May 2012

AbstractProduction from unconventional reservoirs plays a key role in supplying hydrocarbon to the world's increasing energy demand. Hydraulic fracturing is one of the most advancing technologies in producing hydrocarbon from low-permeability reservoirs, especially in tight and shale formations. The geometric properties of a hydraulic fracture affect significantly the production rate from these stimulated reservoirs. Therefore, it is of utmost importance to characterize the geometric features of hydraulically-inducedfractures during stimulation processes.The geometric properties of a hydraulic fracture change with fracture evolution due to stress propagation along the cracks. We have modeled such a system based on the analogy between fluidic and electric circuits. The model takes into account the dynamic alteration of hydrodynamic impedance of the fracture. The hydrodynamic impedance controls the relation between the fracture fluid flow rate and pressure drop during stimulation process. The proposed model incorporates the effects of both hydrodynamic capacitance and resistance of the fracture and the wellbore to compute the fracture impedance.Downhole measurements of pressure and flow rate can explicitly determine the hydrodynamic impedance of the fracture. Fracture impedance can also be implicitly inferred from wellhead pressure and flow rate measurements. The pulsatile nature of hydraulic fracturing treatment makes it sensible to utilize the wellhead data for the purpose of impedance monitoring based on the electromagnetic transmission line theory.We have performed extensive sensitivity analyses on the most important parameters of a single hydraulic fracture for assessing fracture impedance. These parameters include fracture thickness, fracture radial extent, and fracture shape. Through sensitivity analyses results and real-time measurement of fracture impedance, we infer the basic geometric properties of a hydraulic fracture.This research has led to an analytical approach for evaluating hydraulic fractures geometric characteristics. The approach builds an intuition toward better understanding how to design hydraulic fractures in a more efficient fashion.
Saudi Arabia's Artificial Island Wells: Smart Thinking, Huge Rewards for Smokeless Flowback Option
Authors: Dhufairi Mubarak , Arukhe James , Al Ghamdi Saleh 
Published: May 2012

Abstract
One of the current largest oil increments in the world in Saudi Arabia is undergoing field development. The southern part of the field traverses the Arabian Gulf Sea. The Production Engineering team crossed major hurdles in the development of this field with Causeways construction on artificial islands over drill sites to assess well sites.
Flowback options on wells in these drill sites to unload drilling fluids presented key challenges. The flowback objectives included well cleanup, stimulation, production logging, and extended well tests for reservoir characterization requirements. Flowback would also allow conducting electric submersible pumps (ESP) spin tests prior to ESPs installation.
A smokeless flaring option considered the heavy crude's characteristics with relatively high H2S content, possible emulsions from intermixing with completion fluids, interwell spacing limitations, and the sensitive nature of the nearby challenging marine environment. The choices were between using a conventional flare system and modifying the proposed layout to optimize the project's objectives while respecting the constraints imposed by a sensitive aquatic environment, highly sour crude, space limitations, and work conditions or implementing pre-existing conventional practices with the attendant risks of compromising health, safety, and environment.
The authors examine the processes leading to the implementation of a smokeless and an environmentally friendly flowback option. The discussion includes the modifications made to the burner system, and H2S removal from the gas and oil phases. Also a new methodology is presented that fully controlled oil and gas flow to the burner to mitigate the risk of burner flameout for the highest burning efficiency, minimizing spills, and enhancing safe operation. The authors examine the pros and cons of other welltest options such as to re-inject produced fluids into the same reservoir, different reservoirs, or injection into water injectors.
Key significant technical contributions include the presentation of several practical measures to avoid oil spills, and to guarantee ambient air quality. The welltest layout included several automation systems or the elimination of human interventionto deliver safely the project's objectives.
The Agbami Intelligent Well: Examples of Active Reservoir Management
Authors: Collins J. R. , Neubauer E. B. 
Published: May 2012

AbstractAgbami is a deepwater oil field located offshore Nigeria in the Gulf of Guinea. The field has been online since July 2008 and has produced over 275 MMBO to date. The Turbidite depositional setting has lead to a complex stratigraphic architecture with reservoirs being broken into distinct subunits. Although initially in thermodynamic equilibrium they posed dynamic challenges of conformance control and differential depletion. For this reason, Intelligent Well Completions (IWC) were installed throughout the field in both injectors and producers. The field development currently consists of 39 completions across 21 wellbores which are individually isolated and controlled via Interval Control Valves (ICV). Combined with multiple downhole pressure/temperature sensors and inline flowmeters the Agbami IWC provides the real time surveillance and control necessary for optimization of field performance and recovery.During development planning, identifying the potential value from the installation of IWCs and deciding on or recognizing their possible applications is often not a trivial one. The value can be hard to quantify where the information impacts multiple decisions, there is limited in-house experience or where robust forecasts are difficult to generate. The objective of this paper is to bridge some of these gaps through providing an overview of the application of the IWC within Agbami from the workstation of the Production Engineer. Although often overlooked at the early stages of field development, IWCs can provide significant value to the Production Engineer who focuses on the short to midterm field performance and long-term completion reliability.The paper will cover specific examples of value added in relation to production performance over the last three years of field history. IWCs are used actively by the production engineering team with the objective of prudent reservoir management through integration of their capabilities into surveillance plans, production management practices and production optimization efforts.The expanding employment of IWCs for existing or new field developments warrants further literature which shares detailed examples of IWC practices and benefits. The intention of this paper being to focus on the production engineering aspects and values of the IWC as it has been utilized within Agbami at the operations level to improve reservoir management.
Integrated Production Optimization and Surface Facilities Management through Advanced Optimization Techniques
Authors: Giorgio Viadana , Danilo Albani , Marco Distaso , Almatasem Sharon 
Published: May 2012

Abstract
The Production Optimization is one of the most complex and multi-disciplinary task in the oil&gas industry from an operational point of view: it involves the surface asset during all its production life and requires a continuous improvement process. In the gathering facilities and process plant engineering design, the optimization is driven by inputs that are subjected, during the asset life, to changes; this fact, coupled to improvements and modifications in surface facilities, creates the necessity to manage and optimize production scenarios with a more frequent time-frame. Technology improvements have enabled a widespread use of integrated simulation models for a better asset management to be fully combined with measured field data. In this paper we present a dedicated workflow for surface facilities – gathering system and process plant – production enhancement and management coupled with an advanced optimization technique based on a powerful algorithm. The main feature of this algorithm – and consequently of the proposed workflow – is the ability to control many variables simultaneously according to the system constraints even with complex, conflicting and non-direct interconnections between them and the objective to be reached. It has been proven that this algorithm has a robust practice that detects the global optimum of the feasible area avoiding a premature stop in a local optimum region, a situation quite common in highly-constrained and non-linear optimization problems in oil&gas industry. The technical contributions of the work are the abilities to support operations in: definition of field potential, production optimization and de-bottlenecking activities. In the paper a case study, based on a highly-constrained field with gas treating limitations, is reported and the proposed workflow's results are compared with another integrated optimization available from other software, showing an improved ability to detect global optimum combining well management to the plant capabilities.