bluuebunny/crossref_metadata_2025 huggingface dataset:
Architecture and Implementation of an Optimization Decision Support System
Authors: Gobel Derek , Briers Jan , Chin Yee Men
Published: March 2015

This paper describes the implementation of an optimization advisory system by Sarawak Shell Bhd. on the integrated gas production system in Sarawak, to help monitor and optimize in real-time the more than 100 wells on 30+ facilities of the system, governed by different Production Sharing Contracts. We highlight how multiple disciplines are part of the solution, how the solution has been embedded to provide real-time advisory to planners and operators, and the challenges faced. The technology described in this paper provides real-time advisory on flow rates for individual wells and platforms to network coordination operators to achieve a gas supply that meets overall gas demand for the onshore LNG plants, maximizes revenue from condensates production and CO2 blending, and transparently shows the business value impact of giving preference to short- or long-term optimization objectives. It takes into account existing commercial and contractual constraints, as well as financial and economical elements. The optimization approach is data-driven and features multiple, mutually dependent objectives and constraints. The data-driven approach has proven significantly faster and more practicable than prior physical model-based approaches. Field trials have proven a condensate production increase of up to 7,000bbl/d while at the same time improving Ultimate Recovery of the sweet and sour gas blend of the production system by up to 2 months per 'year of applied optimizer advise'. At the same time, gas nominations are met as they were, and commercial and quality constraints are adhered to. The Return On Investment of this solution has been less than a month. This is one of the first successful attempts to implement truly-real-time optimization in a production environment of this size and complexity, including a complicated set of commercial and contractual constraints. The approach opens the door to application to a wide variety of real, complex, mixed-integer non-linear optimization problems, and their organizational application, such as emissions management and decision support systems for integrated IOR/EOR systems.
Evaluation of True Formation Resistivity Derived from the Dual Laterolog-Rxo and the Induction-Spherically Focused Log
Authors: Mohammed Akram F.
Published: March 2015

The problem of determining whether a Laterolog or an Induction is better suited to measure true formation resistivity (Rt) according to prevalent conditions is reviewed. The question of which deep resistivity device (Laterolog or Induction) should be run in a given well is investigated. To aid with this decision, examples are shown that cover a wide range of cases in both oil-bearing and water-bearing zones.

True resistivity values derived separately from the Dual Laterolog-Rxo (DLL-Rxo) tool2 and from the Induction-Spherically Focused (ISF) Log3 are compared. The comparison helps determine the accuracy of the measurements made by each tool with respect to Rt. This also provides the capability to correct the resistivity values for the invasion to obtain Rt,leading to a more accurate evaluation of water saturation.

Practical applications of both tool types, recorded over a limestone formation in three Middle East wells, are shown for a variety of situations in both fresh and salt saturated mud systems. The responses of the basic deep resistivity devices, deep Laterolog (LLd) and deep Induction log (6FF40), are shown for cases of shallow invasion, moderate invasion, deep invasion, and very deep invasion.

Introduction

Rt (resistivity of the non-invaded formation) is the basic parameter that allows the determination of water saturation (Sw) and formation-water resistivity (Rw). Various types of Laterologs and Induction logs are currently in use to measure the value of Rt. No single logging tool has yet been able to measure Rt under all logging conditions. The deep Laterolog and deep Induction log are both affected in different ways by borehole fluids and the invaded zone. A comprehensive understanding of tool responses is therefore needed prior to processing logs for automatic computation of Rt.
Characterization of Coalbed Methane Reservoirs: A Unified Geoscience and Engineering Approach
Authors: Le Turdu C. , Laver R. , Koley M.
Published: March 2015

Once considered a dangerous nuisance in the mining industry, coal seam gas (CSG), or coalbed methane, is now seen as an abundant clean energy supply that will help replace other diminishing hydrocarbon reserves. The nature of the coal-bearing sequences, however, makes them difficult to drill and produce profitably. Major challenges include multiple thin-bedded zones, strong variations in quality of coals, and large volumes of formation water that must be removed before the gas can flow to the surface.

This paper describes a new technology- and knowledge-driven approach to address these challenges in the exploration and development stages of a CSG field. During exploration, combining multiple data types in a single model reduces dramatically the uncertainty around coal seam distribution and gas-in-place estimation. In field development planning, the unification integrates static and dynamic data to enable a better understanding of the field's producibility.

The exploitation of CSG requires analyses of many scenarios and uncertainties. In addition, it requires hundreds of wells to be drilled in a short period of time. Consideration of the high levels of uncertainty and the integration of large volumes of newly acquired data can be achieved efficiently only in a unified software environment that is associated with a strong knowledge management system. In fact, one of the key benefits of this new unified approach includes the ability to update models and test multiple scenarios at any stage of the field life cycle, and track the processes with a strong audit trail.

Data used for demonstration in this paper are from the Surat basin in Central Queensland, Australia.
Qatar LNG Terminal Flare Gas Reduction Project - JBOG
Authors: Mirza Bashir
Published: March 2015

Qatar produces 77 million tonnes of LNG per annum, and is the largest provider of this clean energy in the world. The world's largest man made harbor in Ras Laffan City, located 80km north of Doha, has six LNG loading berths. During loading of the liquefied natural gas in the special LNG ships, a portion of the minus 160oC liquid boils off as it comes in contact with the warmer ship tank. This boiled off gas is currently being flared at the berth because there is no outlet for this low pressure gas. The average flow rate of the boil-off gas is 100 mmscfd, which has the potential to produce around 750MW of power.

In line with Qatar's National Vision to produce and supply clean energy to the world, Qatar Petroleum and the Ministry of Environment decided to recover the flared gas at the LNG berths to the maximum extent practical. This intent gave birth to the Jetty Boil-off Gas Recovery Project in 2007. A Pre-FEED design had been done by RasGas, and the project was handed over to Qatargas in June 2007.

The JBOG Project when fully implemented will save the emission of 1.6 million tonnes of carbon dioxide into the atmosphere. One trillion cubic feet of gas will be saved for the State of Qatar over a period of 30 years.

The design of this project encountered many challenges.

The gas is discharged from the ships at a pressure of less than 1 Bar Gauge Pressure (BarG).The volume of the gas to be recovered is several times higher than at any other similar facility in the world.Gas is discharged at -100oC, making all facilities cryogenic.No provision had been made for space allocation at the harbor for Boil-off Gas Recovery facilitiesCheck valves and buckling pin valves' design and operating experience was not available for the large flow rates, low pressures and cryogenic temperatures.No space was available at the berths to locate the compressors, as designed in the Pre FEEDLimited space available inside the port for JBOG main facilities.Most of the facilities were going to be in brownfield areas, in close vicinity of live hydrocarbon-n carrying lines.Lack of accurate and up to date as -built drawings for brownfield facilities.

The Qatargas JBOG Project Management Team (PMT) brought in experts from the shareholders and addressed each of these challenges through innovation, extrapolation and a strong determination to succeed.

The Front End Engineering Design (FEED) was awarded to Fluor Daniel in Houston, USA in late 2007. The FEED teams from Qatargas and Fluor produced a basic design package by Q3 2008. In the days of $150 per barrel oil prices, the cost estimate ballooned. Qatar Petroleum took a wise decision, and delayed the final investment decision by a year to let the markets cool down.
A Novel Technique to Utilise Surface Data for Transient Analysis in Wet Gas Producers
Authors: Al-Kharaz H. , Farooqui M. Z. , Ansari A. M. , Thakur Kapil
Published: March 2015

Petroleum engineers rely on periodic acquisition of bottom-hole data to monitor changes in well and reservoir inflow characteristics, and to quantify well and reservoir parameters using Pressure Transient Analysis (PTA). However, the acquisition of this data, especially in an offshore high pressure and sour gas environment, presents many logistical challenges and operational risks, and can negatively affect expenditure and downtime performance. On the other hand, surface data is routinely available, sometimes with sufficient frequency and precision to carry out PTA. Surface data is affected by wellbore transients that must be taken into consideration for converting the surface data to bottom hole conditions with the accuracy required for proper analysis.

This paper describes a novel technique to properly account for wellbore transient effects and convert surface data to downhole conditions to enable conventional PTA without the need for well intervention.

The technique combines the transient wellbore modelling with a novel approach of defining coefficients in a modified bottom hole pressure equation which is described in the paper. Coefficients are calibrated using concurrent surface and downhole data sets and then utilised to convert future surface data to downhole conditions.

The paper describes the findings and conclusions from a five-well pilot, which involved wells with a range of reservoir characteristics, single and multi-layer production, and with/without cross-flow. The pilot work compared PTA results utilising this technique and surface data with results generated using downhole data.

Introduction

RasGas and SPT Group (Schlumberger) have conducted a joint evaluation of transient modelling capabilities to accurately predict bottom hole pressure using wellhead pressure data as an input for offshore gas producers. The primary objective of the trial was to enable conventional transient well test analysis using the surface data converted to downhole conditions. This would reduce the need for recording downhole pressure buildup data to obtain wellbore skin and kh during routine production logging operations and hence reduce the operational risk associated with well intervention. The technique will also enable more frequent acquisition of pressure buildup data whenever the well is shut-in for any reason since the wellhead operating parameters are continuously recorded by the Real Time Information System (RTIS) on all RasGas wells.
Barzan Completions Success Through Innovative Stimulation and Testing Technologies
Authors: Clancey Byron , Aly Maher , Bugti Mehboob , Shuchart Chris , Sau Rajes , Grubert Marcel , Farah Ali
Published: March 2015

The North Field Barzan Development was executed with focus on identifying and implementing effective completion solutions that addressed new technical challenges and operational constraints presented by the wells of this project. The primary challenges were in areas of matrix stimulation, spent acid clean-up, and production testing. Stimulation issues included implementing designs for a wide range of permeability contrasts, addressing stimulation vessel pump rate and acid capacity limitations, managing live acid corrosion due to sour environment, and assessing effectiveness without production logs. Spent acid clean-up operations required protecting downhole safety valves and achieving fluids composition criteria required for production into carbon steel pipelines. Production testing challenges included fluids modelling and equipment solutions that decreased Safety, Health and Environment (SHE) risk and operational complexity, while allowing accurate measurement of gas and liquids flow rates and obtaining required fluid samples.

The solutions included improvements to the acid stimulation system chemical diverter and corrosion inhibition package, custom design and manufacture of a subsurface safety valve protection sleeve, adoption of well clean-up criteria tailored to pipeline and facilities requirements, evaluation of multi-phase flow meter and real time fluids analysis technologies, and development of a simplified multi-phase flow rate calculation algorithm based on choke manifold and fluids composition data.

Implementation of differentiating technologies enabled cost savings and SHE benefits due to reduced flaring, execution of single stage stimulations, smaller test equipment layout, and innovative flow rate calculation techniques. Stimulation designs were demonstrated as successful based on interpreted changes in zonal flow contributions derived from minimum surface fluid compositional data. Wells were completed and ready for handover, meeting all requirements for the surface production facilities.

Introduction

Demand for energy in Qatar will grow over the next decade as major initiatives are completed in the transport, health and education sectors, and as new facilities are built for the FIFA World Cup in 2022. The Barzan Development is planned to meet the increased gas demand and is one of the most significant projects undertaken by the State of Qatar.

Several offshore development wells were drilled and completed with a design life of at least 25 years and capacity to produce in excess of 1.0 billion standard cubic feet per day to supply two gas treatment trains. The wells are located on three unmanned wellhead platforms in the North Field, about 80 kilometres offshore Qatar (Figure 1), and are completed in Khuff Zones 1–3 carbonate reservoirs. One well at each platform is designated a 'data well' and was extensively tested to evaluate reservoir and fluids properties.
Multi-agent Collaborative Decision Making for Upstream Asset Management
Authors: Xu Peng , Subrahmanya Niranjan , El-Bakry Amr , Reynolds Carmon
Published: March 2015

Extended Abstract

Upstream assets are very challenging to manage because the components and processes involved are numerous, dynamic, and interdependent. Managing such assets requires execution of multiple technical tasks such as analyzing data, forecasting behavior and optimizing performance. While software tools are available to help engineers perform individual tasks, the goal of integrating cross-functional asset management tasks to achieve a greater level of automation, or even autonomy, remains elusive. As a result, most technical tasks are run and monitored by engineers; and interdependent tasks and cross-functional workflows are integrated through high-level human interaction.

Many of these tasks and the integration can be and should be conducted automatically with computer programs so that humans can focus on more challenging tasks. To achieve this goal, we study how to develop computer systems that can model complex assets and can autonomously execute asset management tasks.

Before we describe how the autonomous systems work, let us first describe how humans conduct asset management tasks from the decision making prospective. A typical first step is to obtain essential data and convert data and low level information into high level information such as trends and patterns. The second step is to reason upon the high-level information. The reasoning outcomes (e.g., equipment condition, reservoir behavior) provide solid information for decision making. The third step is to evaluate multiple decision options, determine which one will lead to the asset management goal and also satisfy various constraints. Based on these and potentially other metrics, one decision option is selected. The last step is action, through which the selected option is executed.

Note that the aforementioned steps are for one decision making process. There are numerous decision making processes for asset management. While some of the processes run independently, many of them are interdependent. For example, the outcome of one process may be fed into another process. It is through the interaction of these processes, numerous physical entities, software programs, workflows, and operators are integrated to accomplish asset management.

To achieve the lofty goal of an autonomous asset management system, multiple modeling and design steps are needed. One is to model the asset management problem. More specifically, we need to decouple the complex workflows into simpler ones that can be managed by computer entities as decision making processes. The second one is to develop each computer entity to conduct individual decision making tasks. And finally we need to develop an interaction mechanism between those computer entities in such a way to achieve asset management objectives. There are core technical challenges to achieve this vision. In this paper we attempt to address one such challenge by investigating existing interaction mechanisms from multi-agent system technology.
Successful Implementation of Real Time Down-Hole Pressure-Temperature monitoring using Fiber Optic Technology in Deep HT-HP Well in North Kuwait
Authors: Kabir Mir Rezaul , AIi AfzaI , Pradhan S.  P. , Dashti Qasem , AI-Jasmi A. K. , Abid Ridha
Published: March 2015

The scope of the pilot project was to test fiber optic sensor technology in deep High Temperature (HT-HP) reservoirs and evaluate the best available sensors in the market for real time monitoring of down-hole pressure and temperature (P-T) in such an adverse environment. The task team had selected the optical P-T sensors conveyed on fiber optic cable from a qualified vendor after a thorough evaluation, considering the harsh environment of these reservoirs. After selecting the vendor, the fiber optic system was custom designed and installed down-hole in a selected deep HT-HP well in the Raudhatain field of North Kuwait. The system was installed and commissioned in mid February 2011 and has been successfully working to date, providing real-time pressure and temperature data from the reservoir section.

In this project the P-T signals captured by the optical down-hole sensors are transmitted through the fiber optic cable to the Reservoir Monitoring System (RMS) unit at the surface that is connected to the SCADA system. The SCADA system sends the data through Wi-Max to the Digital Data Gathering Centre in the Field Development Gas (FDG) office. The sensors are continuously providing reservoir data at a time interval as frequent as 60 data points per minute. The technology provided by the vendor for this pilot is found to be robust and reliable. The pressure and temperature sensors employed in this pilot have shown impressive resolution and dynamic response capabilities. Based on the results it is concluded that the pilot is successful and the system is recommended for future implementation in deep HT-HP wells of North Kuwait fields.

The project involved manufacturing, shipping and procuring the material from the Far-East and the USA. It also involved modification of well head to accept fiber optic cable entry into the well bore and use of specially designed low solid content packer fluid. The pilot was considered successfully completed after monitoring for 180 days in the month of August -2011.

In Kuwait Oil Company (KOC) this first fiber optic sensor technology pilot was conducted by Research and Technology (R&T) and Field Development Gas (FDG) with the coordination of Deep Drilling and other groups, in a deep HT-HP well with the primary objective to monitor two key reservoir parameters; temperature and pressure. The reservoirs in North Kuwait are complex soil bodies that have a high potential for condensate and gas. The continuous, real time understanding of these reservoirs is vital in order to optimize their exploitation; hence KOC adopted a strategy of deploying fiber optic monitoring systems.
Qatargas Process Safety Program
Authors: Shenbagarajan Saravanan
Published: March 2015

Qatargas Process SAFETY Program

We know our limits and we operate within those limits all the time

The Qatargas Process safety Program is one of the business initiatives within Qatargas to achieve the Qatargas Vision 2015. It is a basic, standardized, operational work process that ensures operation within well-defined, well-understood limits. Operation within these limits is continuously achieved through a defined and well- followed set of operational and organizational Behaviors & Procedures at all levels.
High-Resolution Distribution of Organic Matter in Carbonate-rich Oil Shales controlled by climatic cycles and depositional environments
Authors: Caline B. , Dessort D. , Billeaud I. , Cantaloube S. , Allix P. , Krafft J. M. , Le Van Loi R. , Duclerc D.
Published: March 2015

The objective of this joint sedimentological and organic matter study was to document and understand the vertical heterogeneity of organic matter distribution of an oil shale interval which belongs to the lower Muwaqqar Fm in Jordan.

The high resolution logging of organic carbon using new pyrolysis instrument reveals the cm-scale rhythmic bedding of the oil shale deposits. Cyclostratigraphy based on recognition of Milankovitch cycles appears to control the alternation of rich and lean organic layers within this carbonate interval.

Introduction

The objective of this joint sedimentological and organic matter study was to document and understand the vertical heterogeneity of organic matter distribution of an oil shale interval which belongs to the lower Muwaqqar Fm in Jordan (fig. 1 and 2).

Because organic carbon content may show significant variation (e.g. at the mm or cm scale), a new instrument was used for recording high resolution logging of organic carbon on cores: the LIPS (Laser Induced Pyrolysis System).

Study program

Detailed investigation of one cored well (around 130 m long) has included high-resolution sedimentological logging (1:50 scale) and organic matter measurements (1 data point / 2 cm using LIPS on cores. Low resolution Rock-Eval data were acquired in order to calibrate the LIPS signal for calculating high resolution TOC and petroleum potential, regarding the different sedimentological facies.

LIPS: a new instrument for high resolution logging of organic carbon

Methods usually applied to quantity the carbon content or the hydrocarbon potential of sediment samples (Rock-Eval, Fisher Assay, Leco, analysis of thin sections, Iatroscan…) are expensive, provide low resolution data (typically, one sample every 30 cm to 2 m) and are time and sample consuming. Processing of geophysical well logs provides low-resolution logs (about 30 - 50 cm of mobile average data).
Emerging Technologies and the Future of Hydraulic Fracturing Design in Unconventional Gas and Tight Oil
Authors: Fonseca Ernesto
Published: March 2015

As industry leaders seek solutions to the myriad of challenges facing unconventional projects, research and development efforts continue in the area of multistage fracturing design. These research activities are focused on the identification of novel approaches to hydraulic fracturing (HF) design that can lead to more effective design practices in the future.

This paper describes emerging technologies within the building blocks of HF design for multi-stage horizontal wells, and proposes how application of these technologies can lay a foundation for the development and evolution of future industry practices. The industry debate on HF design commonly revolves around a perceived need for more powerful software tools that can capture complex fracture geometries. This perspective or position within the broader industry is due in large part to the cloud of microseismic induced events that is oftentimes observed to envelop a treatment area. Some interpret that these events arise from very complex fracture geometry, and therefore modeling tools with increased specialization are needed.

Rather than focusing only on the ability of the software to replicate complex fracture geometries, a higher-level and integrated view of HF design is recommended. As shown in Fig. 1, this integrated approach considers the progressive analysis and application of subsurface diagnostics and modeling capabilities, and how they can influence meaningful decisions in the area of HF design. In reality, the capability for HF design is as strong as the weakest of these three components and need not rely solely on modeling capability.
Results from the Introduction of a New 3-d Radial Probe for Wireline Formation Testing in Western Siberia
Authors: Charupa M , Weinheber P , Tsiklakov A , Latypov A , Goitia VH , Caraballo J R , Pashinsky A
Published: March 2015

The exploration and appraisal focus in Western Siberia has shifted to more complex and challenging reservoirs. As a result, tools and techniques that may have worked in more benign environments need to be adapted to the more challenging realities. A case in point is the wireline formation tester. The many sizes and shapes that are available have delivered valuable information with respect to rock and fluid characteristics using two basic configurations: either a single probe device or an inflatable straddle packer device. Aside from other nuances, the choice of configuration is essentially a tradeoff between the easy-to-deploy small-area single probe and the difficult-to-deploy but very large-area straddle packer. Into this mix is introduced a new type of probe. This 3-d radial probe attempts to combine the larger flow area of the inflatable dual packer with the easy deployment of a single probe tool. Examples from Western Siberia where all three tools were used are presented to allow us to compare and contrast the performance of each.

Introduction

Modern formation testers are capable of extracting a wide variety of reservoir characteristics including mobility, fluid type, fluid contacts and etc. There are a variety of methods by which the tools interface with the open hole formation but they broadly break down into two types: probes and inflatable dual packers. Probes enjoy the benefit of relatively fast deployment but are limited in the area of formation they can contact - typically on the order of a few square centimeters. Straddle packers isolate nominally 1 m of open hole which can be extended up to 5 m and in certain configurations can reach 12 m or more (Harfoushian, 2013). However they are typically more difficult to deploy than a single probe. To understand the effect of flow area will have on formation tester performance we can review the factors that drive the rate and drawdown characteristics of fluid flow into formation testers. This work is based on equations developed in the very early days of formation testing (Moran, 1962). The rigorous treatment of the modern implementation of this work (Dussan, 2011) allows for application to conditions beyond the circular probe originally considered. Additional work for the straddle packers is also considered. (Onur, 2004).
Operational Excellence in Qatar
Authors: Das Prashun Kumar
Published: March 2015

Qatargas North Field wells are typically 7 inch monobore medium to high deviation wells and are designed to handle high pressure sour gas containing of H2S and CO2. An extensive rigless well intervention program is carried out with 0.23 inch electric line and with 0.125 inch slickline for data acquisition, and for other downhole wireline jobs.

During a rigless PLT operation with 0.23 inch e-line, an accidental closure of the TRSCSSV resulted in cutting of the e-line. This necessitated a rigless heavy duty wireline intervention resulting in a successful, safe and a cost effective fishing operation in recovering 11,414 ft of 0.23 inch braided e-line.

This paper describes the approach and the technique applied in the fishing operation considering the limitations of a rigless operation. It also outlines the extensive workshop trials carried out during the preparatory phase for developing an acceptable double block and bleed barrier arrangement on the PCE for a safe well intervention. It also describes the planning considerations, the procedures developed, the high level Risk Assessment carried out, and the elaborate Load Assessment Study for working with a 90 ft mast and 0.23 inch braided line on a remote un-manned offshore platform.

Introduction:

Qatargas North Field is located offshore, northeast of Qatar in the Arabian Gulf and is the world's largest non-associated gas field. The sour, slightly over-pressured natural gas is contained in the Khuff carbonate formation. Majority of the offshore wells are 7 inch monobore design completed with 7 inch CRA tubing and liner sections. Wells deviations range from vertical to about 70 degrees.

An extensive rigless e-line program is carried out for data acquisition. This comprises of baseline logging program carried out just after PST, followed by a surveillance logging program carried out at a specified interval to study the changes in the reservoir, production and well parameters. The logging program generally comprises of production logging & pressure build-up (PLT-PBU), reservoir saturation survey (RST), and electromagnetic imaging survey (EMIT) and PS Platform Multifinger Imaging Survey (PMIT). The surveys are conducted in shut-in condition as well as in flowing condition at different rates. A drift run is generally conducted prior to any of these intervention jobs to ensure there is no obstruction inside the tubing or casing.

A 70 ft mast is used to rig up the required lengths of lubricators and the Pressure Control equipment. The wells are vertically equipped with a manual Swab Valve (SV), a hydraulically controlled Upper Master Valve (UMV), and a manual Lower Master Valve (LMV). A big bore tubing retrievable surface controlled sub-surface safety valve (TRSCSSV) is a part of the completion. During the well intervention jobs, the hydraulic controls for TRSCSSV and UMV are switched over to a Wireline Panel. This Panel has two remote Emergency Shut Down (ESD) system located at two strategic places to close TRSCSSV and UMV in case of exigency, when approach to the Wireline Panel is not possible.
Well Structure Integrity Threat Due To Near Surface Corrosion of Outer Casing at Offshore Wells
Authors: Pandey Shri Kant , Rana Shahzad Amin , Fakhro Ahmed  Jassim
Published: March 2015

QP Offshore operates in shallow water at Arabian Gulf. The wells are drilled and completed at surface on multi slot wellhead jackets.

We encountered well subsidence with some offshore wells. The well subsidence caused stresses to flowlines, gas lift hook up and jacket members.

As a result, the flowlines and gas lift hook up were under threat with subsided wells. This meant high risk potential of uncontrolled release of hydrocarbon to atmosphere, with significant potential of asset damage and environmental pollution.

The Offshore wellhead jacket structure and conductor casings are protected against corrosion by cathodic protection. These were primarily installed to protect wellhead jacket structure against sea water and its corrosion protection to wells is not known to us.

The well subsidence occurred due to structural failure of outer casing caused by the atmospheric corrosion. The corrosion occurred due to outer casing being in contact with sea water and atmospheric air near splash zone.

We looked at options of isolating the air and seawater contact from outer casing to prevent further corrosion.

It was possible to achieve this by placing bio degradable oil into Conductor. The oil being lighter than water shall stay above the water, thereby isolating air in the oxygen from sea water. We dropped this option as high ambient temperature in summer months shall cause bacterial growth and degrade oil. The degraded oil could result in accelerated corrosion instead of preventing it.

The other option considered was to install sealing type cover at the top and replace trapped air inside annular space with nitrogen. This too could not find favor due to lack of assurance in isolating the air inside the Conductor.

QP selected to top up the conductor with cement. It shall cut off air between conductor and outer casing. The other major advantage was well structure strengthening by joining the conductor with outer casing to support wells with weakened outer casing.

The paper shall illustrate on the findings of corrosion analysis with outer casing recovered during well workover operations for subsided wells.
A Joint Shell / Adco development Of A Shared Earth Model (sem) To Support Further Development Of A Giant Field, onshore UAE
Authors: Meyer B.  D. , Nieuwenhuijs R. A. , Bennett R. , Brint J.  F. , Vizamora A.
Published: March 2015

The field is located onshore Abu Dhabi and has been in production for more than 50 years. It covers an area of approximately 1500 square kilometers and has 20 reservoirs with producible hydrocarbons comprising a series of stacked oil and gas reservoirs with differing drive mechanisms and development maturity, including in-field exploration targets. This paper describes the work undertaken to build a full field Shared Earth Model (SEM) to support future drilling to maximize the field recovery and extend the field lifetime.

The key business deliverable for the SEM was to allow more effective assurance of planned well trajectories in a highly congested surface/subsurface environment, thus increasing the safety of such operations. As a consequence, the SEM had to extend from ground level to the deepest penetrated reservoirs. The reservoir model is constrained by more than 70 seismic horizons and by more than 40,000 well markers of various vintages; this alone represented a significant modeling challenge. Automated QC & QA workflows were used heavily to analyse the input data and the model during each of the model construction iterations.

The reservoir units are faulted but these faults do not extend to the surface. Due to limitations in the representation of such faults in pillar grids and a lack of continuity of fault interpretations from one reservoir to the next, it was decided to represent faults as properties and not as fault planes. This not only allowed adjustment per reservoir, without requiring a rebuild of the whole structural model, but also identified clearly a zone of uncertainty around the predicted faults, assisting well planning efforts.

A major focus of the project was to provide an evergreen model which could be kept up to date with ADCO's substantial drilling program. Therefore considerable effort was made to hand over not just a model, but also training in the key workflow's and work practices which would ensure that ADCO staff have the skills in house to update and maintain the model. This was achieved through extensive use of Petrel workflows, which enabled quick & structured model updates and through several training sessions in Abu Dhabi, run over 3–4 days. This proved to be an effective mechanism to hand over the model and workflows to ADCO staff.
Process Safety Management - a prerequisite for sustainable gas production
Authors: den Bakker Kees
Published: March 2015

1. Introduction

The LNG industry enjoys a commendable track record in reliability and safety. There is however no reason to be complacent, as we can learn from various major hazard accidents across the energy industry (e.g. Piper Alpha, Texas City, Macondo), which regretfully resulted in fatalities, asset damage and had environmental impact. LNG operations may be similarly vulnerable to major incidents if hazards are not properly managed.

Root causes for major accidents are often complex in nature. They are related to a series of interlinked failures in mechanical, human judgment, engineering design, operational implementation and team interfaces.

To avoid such incidents, we must translate learning into effective barriers, aimed at reducing risk to acceptable levels. This article will share some insights on how this is done in Shell.
Core Flood Analysis Of Acid Stimulation In Carbonates: Towards Effective Diversion And Water Production Mitigation.
Authors: Gharbi Oussama , Goedeke Stefan , Al-Sammaraie Mohammed , Al-Shahwani Saqer , Cheneviere Pascal , Al-Mohannadi Nasser , Julien Philippe
Published: March 2015

Extended Abstract

Introduction:

It is well established that acid stimulation in carbonates can enhance the productivity of oil and gas wells. As carbonate porous media are highly reactive in contact with acidic solutions, when acid is injected into carbonate reservoirs, the near wellbore region is subject to chemical dissolution. This is a reactive transport phenomenon, as acid is flowing and transported through a porous media. Coupled changes of the fluid and rock properties are taking place. Changes in chemical concentrations of the in situ fluids, the surface area, the permeability and porosity are also occurring. In this context, many studies have experimentally and numerically investigated carbonate acidizing. It has been shown that different dissolution regimes can be observed based on two main parameters, basically, the injection flow rate and the acid content. Wormholing i.e. a non uniform dissolution which is characterized by the creation of a conductive pathway along the porous media, is therefore observed for relatively high flow rates and low pH (high acid content). It also has been shown that for a certain pore structure, optimum injection rates, where the minimum acid volume leads to the highest permeability increase, (optimum wormholing) exist. Therefore, in field applications during acid stimulation jobs, the acid is injected at relatively high pumping rates in order to achieve an efficient zonal coverage and sweeping efficiency. Today, acid stimulation is widely used for newly drilled wells or wells that are experienced in production decline.

Context:

It has been observed that acid stimulation of carbonate oil and gas wells, especially in mature carbonate fields, can be inefficient and might sometimes lead to negative outcomes. Targeted low permeability regions can be kept untreated and water production might arise after the acid injection. These negative results are often explained by the presence of a high permeability matrix contrast or the presence of active fracture networks in the reservoir. In such configurations, the acid enters the highest permeability matrix regions or flows through the fracture networks and might connect to a new water pathway. A large number of investigations have considered chemical or mechanical diversion techniques that allow the acid to stimulate a low permeability zone in the presence of a permeability contrast. In addition, a series of studies have considered reducing water production through water shutoff chemical products. Although efforts have been made towards fluid formulations, only a few studies have considered the experimental validation of diversion and water mitigation in heteregenous carbonates. In this paper, we experimentally revisit improved acid stimulation techniques in the presence of watered and permeability-contrasted carbonates.
Technological Evolution In Natural Gas Plant Automation
Authors: Dey Nilangshu
Published: March 2015

Natural Gas Liquid (NGL) Plants in Qatar have undergone major operational transformation during the last decade. The large step change in operational strategy, efficiency and maintenance optimization has occurred due to automation evolution taken place in monitoring & control, protection and asset management of all NGL Plants of Qatar Petroleum at Mesaieed.

The paper will focus how such technological evolution has made flexibility in gas plant's operation and in deriving key business decisions for operation and maintenance optimization using foundation field bus technology, integration of the plant controls to the business enterprise etc. The paper presents following three major areas of technical transformation contributed significantly towards NGL Plants upgrade indicating the problem faced, application of new technology, the challenges faced while implementation and benefits achieved in terms of operability and maintainability.Utilization of Foundation Fieldbus technology for control and monitoring application in NGL storage & loading plantsIntegration of all NGL plant control systems with business enterprise using Real Time Process Information Management system for achieving Alarm management, Control system performance, On line reporting and calculation of KPIs relating to Production and Maintenance for deriving on line various business decisionsIntroducing integrated hardware and software platform for large gas turbine and compressor controls of propane refrigeration and lean gas booster compressors in various NGL plants

The paper provides the multifold benefits achieved in above three major areas of automation transformation in various NGL Plants along with its cost benefits analysis.

Introduction

NGL-1 & 2 plants receives raw NGL feed (4100 T/D capacity of each plant) from Dukhan oil field and produce C1, C2, C3, C4 and C5 + hydrocarbons. NGL-2 plant also receives Rich Associated Gas (RAG) from offshore wells and in turn it produces raw NGL which are being processed either in NGL-1 or 2 plant to produce various hydrocarbons.

NGL-3 plant receives raw gas feed (1024 MMSCFD capacity) from offshore (North field alpha) and produce raw NGL, fuel gas C1, stabilized condensate and acid gas. This raw NGL from NGL-3 are processed in NGL-4 plant having capacity of 12000 T/D and produce C2, C3, C4 and C5 + hydrocarbons. Propane (C3) and Butane (C4) are stored in refrigerated storage tanks (4 nos. of propane storage tanks of total capacity 356,000 m3 and 4 nos. of butane storage tanks of total capacity 192,000 m3) and Gasoline (C5+) are stored in floating roof tank (2 nos. of tank capacity 120,000 m3). C1 (fuel gas) and C2 (ethane) are supplied to the various power stations and other neighboring companies thru gas distribution stations.
Achieving Maintenance Excellence in Maersk Oil Qatar
Authors: Smart Kenny , Blakey Kevin
Published: March 2015

Maintenance Excellence for Maersk Oil Qatar is about a development and a change journey aimed at positively influencing behaviours including system and process transparency and scalability.

This journey questions ways of working and current practices through review of maintenance strategies, policies, CMMS (SAP) functionality and people. In collaboration with our knowledge base, off and onshore personnel and systems, MOQ is seeking to improve why, how and when we maintain our assets, to achieve Maintenance Excellence.

Maintenance Excellence is simply a framework for working more efficiently and effectively. Ensuring that we maintain 'In-service integrity' at all times by "fixing forever, instead of forever fixing". This is achieved by treating the root cause of a problem and not just the symptom.

Understanding the current position and why change is required. It is essential to make a step change from Reactive to Proactive maintenance, thus achieving compliance within the framework of MOQ policies, standards and strategies.

Through developing the Strategy; Populating the Plan; Scheduling Activities; Executing Work; Analysing the Data; Managing Performance - making perfection the goal, Maintenance Excellence will follow.

MOQ Policy; Defines the aspirations to achieve Maintenance Excellence. Drive the development of safe systems of work and the overall assurance of integrity and reliability for plant, systems and equipment. Based on the Standard PAS55 or ISO055000; this clearly states the approach and principal methods for managing assets and asset systems.

Maintenance Strategies; These are developed through a risk based approach whereby high criticality equipment and packages are subject to detailed analysis e.g. FMECA. Followed on by the Structure of how we manage work; introducing commonality across our assets connecting our people to our technology, sharing best practice and removing waste.

The introduction of new Technologies also includes; the CMMS (SAP), Dashboards, (BO) and Document control (EDMS) enabling people to gauge process effectiveness and business performance. Ensuring the right people possess the correct competencies, behaviours, attitude and experience to deliver excellence in their role. Through development and communication, preparing, training and coaching our people, enabling competence and empowerment. This collaboration and adherence to the plan will deliver a seamless implementation.

Through continuous assessment we will remain on track, not losing focus of the end goal; only through The 3 P's - Patience, Perseverance and Persistence will our efforts deliver a successful journey. A journey that is continuous, achieving Maintenance excellence is a living entity, constantly evolving to the many demands made by the business, giving more flexibility in how we espouse continuous improvement. Delivering vision to why, where, when and what we maintain and at what cost. Maintenance Excellence is a lifecycle approach for Continuous Improvement.
Safe Execution of a World Class EGR Facility in Abu Dhabi - The Elixier Mirfa Project
Authors: Al Attas Salem
Published: March 2015

Abu Dhabi is experiencing a clear increase in the demand profile for gas needed for pressure maintenance in oil reservoirs as well as for gas cycling in condensate reservoirs. On top of the requirements from the oil and gas fields, the Emirate is also witnessing a significant increase in the natural gas demand for power. Pressure on gas fields is usually maintained through water and hydrocarbon gas injection. Habshan is one of the first sites using an alternative through the injection of 600mmscfd of Nitrogen into the Thamama F reservoir. Nitrogen injection improves gas recovery from the reservoir with only a very limited reduction on condensate recovery as opposed to the pure Hydrocarbon gas injection case. After two years of successful operations, the paper presents the benefits achieved, the execution performance as well as quality and HSE track record. By bringing these Nitrogen production, distribution and injection facilities into the country, the project is also supporting an intensive local knowledge development of cutting edge cryogenic technologies and its uses. For this plant built in Mirfa, a staff of about 50 people has been trained to the highest technical, operational and SHEQ standards available on the market. From an HSE perspective it is worth to mention that the project execution closed without any reportable LTI (Lost Time Injuries) notwithstanding the over 15 Million man-hours cumulated until start-up.