bluuebunny/crossref_metadata_2025 huggingface dataset:
KPI's for Advanced Process Controller at ADGAS
Authors: Alsereidi Rabeiah
Published: November 2016

It has been noticed that the nature of the gas liquefaction plant is highly interactive and sensitive to small changes which can propagate in a way ending to alter production rates if not attended properly and in timely manner. For example, slight changes in parameters of Multiple Component Refrigerator (MCR) Compressor could eventually affect Main Cryogenic Heat Exchanger (MCHE) leading to reduced production rate or unstable plant operations. It even gets harder to stabilize when another variable or more gets disturbed in the same time. ADGAS implemented Advanced Process Control Solution (APC) for LNG Plant with intent to increase throughput while respecting all the constraints required for ensuring integrity and reliability of its assets. It is also helping to improve efficiency, reduce emissions and also to reduce operator stress by substantially reducing operator interventions required.

Model based predictive control is used in implementation of APC. Overall structure of controller includes 5 controllers. This type of implementation is not so uncommon in industry today, however, at ADGAS we had some challenges which were eventually overcome using innovative solutions: MR Composition ControlMR OptimizationNeed for Robust Inferential structureTackle impact of gas drier change over on upstream and downstream plant

A base case data was considered to compare pre and post APC implementation. Overall benefit of APC project appears initially when the PID control loops are tuned and later when APC controllers are commissioned. Hence the benefits from the improvement of PID control loops also need to be considered on the overall benefit estimation of APC. On ADGAS Train 3 LNG unit, the tangible economic benefit of APC is quantified in terms of increase in LNG, C3 and C4 LPG production & energy reduction. Intangible benefit includes increased naphtha production, plant stability and less load to panel operator.
The Cost and Sustainability Benefits with Integrated Process and Power Automation Architectures in Electro-Intensive Oil and Gas Plants
Authors: Smith Christopher J.
Published: November 2016

Objectives/Scope

The oil and gas plant industry is looking for increased cost and energy savings, particularly with the recent changes in global macroeconomic conditions. In response to this plant automation suppliers have been looking at simpler more collaborative automation architectures. This paper outlines the case for an integrated architecture which enables benefits throughout the entire plant definition, construction, and operative lifecycle, preserving the relevant engineering autonomy for three distinct automation domains, Process Control, Process Safety and Electrical Network Management.

Methods, Procedures, Process

Describes the automation landscape and briefly defines the various automation domains, subsystems involved and description of the common interface techniques used on generic system in the upstream oil and gas industry. Describes the emergence of the Electrical Management and Control System based on IEC61850. Reviews newer smarter electrical technology used for efficiency and energy availability gains and its consequent impact on the automation systems designs. Contrasts the techniques used in the shift between static and dynamic load shedding and its relevance to the architecture.

Results, Observations, Conclusions

A preferred integrated architecture is described with an outline of practical constraints and objectives. A first order model estimate of engineering effort savings in integration is determined. The evolution of more efficient Electric Power technology and the emergence of a networked EMCS electrical design information model and architecture coupled with a VFD usage provides an increased rationale for the incorporation of dual-language supervision of ICSS and EMCS. The paper concludes that engineering, capex and plant energy efficiency improvements in mechanical and electrical designs can be improved through adoption of the preferred automation architecture.

Novel/Additive Information

The paper develops a model based comparison of automation effort on multiple segmented autonomous systems using different networking information models.
Lean Optimization on Well Placement: Directional Drilling Operations in South of Oman Wells: A Case Study
Authors: Kindi Nasser Al , Shehhi Qasim Al , Al Adwani Abdullah , Al Habsi Saud , Emanuel Roy
Published: November 2016

Drilling operations within the oil and gas industry can be very complex and expensive; and while directional drilling and well placement are critical in the well delivery, additional complexities and time consuming processes must be followed to drill and deliver the wells, as desired, following the trajectory.

It is desirable to evaluate the implementation of best practices to improve well delivery efficiencies, minimize nonproductive time and transfer lessons learnt from one well to another.

Lean thinking has existed for many years; it was first developed within the automotive industry in the 20th century, and then began to be applied within other industries. The lean concept is based on eliminating waste by more closely examining processes to identify and eliminate waste in every stage of a process, thus improving efficiency and lowering production costs.

Lean thinking has become popular amongst senior level management within the oil industry, and has become part of core strategies for many companies, with dedicated resources to systematic lean implementation in many areas of business with clear goals and objectives.

An operating company began lean implementation in different areas. An opportunity to lean and standardize the development drilling process was recognized in the south of Oman, with improvements to be replicated in the other fields, as applicable.

This paper describes the implementation and outcome of a lean philosophy for directional drilling. By adopting and engaging in simple lean thinking, improvements can be achieved in many areas. The value of lean implementation and workflow is presented. Also discussed are results obtained that led to significant savings in the survey time, contributing to faster well delivery and improved efficiencies.
High Integrity Pressure Protection as an Economic Alternative to Flare System Upgrade in Brown Field Project
Authors: Al-Hosni Ali Khaleel , Hafez Mohamed , Gawari Rajendra , Raval Prayag
Published: November 2016

In a brown field modification, increasing the capacity of a compressor station from 200 MMSCFD to 350 MMSCFD mandates replacement PSVs at the compressors discharge which in turns leads to excessive flare load and large capital investment. As per the production profile the production rate will sustain at this level for 1.5 to 2 years and then will sharply decrease to a turndown rate of 125 MMSCFD. Considering the short term utilization and the large capital investment to upgrade existing flare network an alternative solution was sought of by introducing a non-conventional design of HIPPS. Introducing this solution, reduction in shutdown duration up to 50% and saving in capital investment by approximately 30 to 40% of project cost the target have been achieved
Ensuring Safety through Flexibility Enhancement of Amine Unit Operation
Authors: Ahmed Alya Al , Rafiq Shahid , Narayana Sathyanath , Awadi Ibrahim Al
Published: November 2016

Limitations in Amine storage capacities at one of GASCO's Plants necessitates the use of temporary ISO-Storage containers to store surplus Amine during Plant / Process shutdown. This poses serious risks to equipment and personnel safety which could be categorized as a safety critical issue. This paper addresses the study carried out to resolve the issue, exploring various options and how the proposed solution mitigates the risks and ensures process safety by enhancing operational flexibility of the amine unit.

Optimization of the Plant layout for HSE constraints resulted in location of amine regeneration section farther away from the amine unit, leading to an increase of solvent inventory above design levels. As a result, during shutdown operations, the existing storage capacity was deficient by a significant margin, necessitating use of temporary facilities to overcome the shortfall.

A study was carried out to find solutions to the issue and various options were explored. Limited availability of space in an existing Plant, working within hazardous area and tie-ins with existing processes posed several challenges. The entire study was carried out utilizing GASCO's in-house resources involving full spectrum of discipline engineering expertise.

The selected option involved provision of an additional storage tank and associated facilities. This included identification of the required tank sizing and storage capacity, feasible location of tank and transfer pump, feasibility study of pipe routing and tank bund containment calculations.

The following benefits will be achieved with the proposed solution:

- Safe access for operation/maintenance.

- Proper containment of spillages / leakages within the tank bund.

- Nitrogen blanketing to stop H2S release and reaction of lean amine with oxygen.

- Venting (routed to a safe location).

- New lean amine tank will have fixed firefighting foam system.

- Use of fixed 6 inch line instead of hose for lean amine transfer.

- Shutdown delays will be avoided.

- Process contamination will be avoided.

As the proposed location was within the hazardous area close to live Plant units, tank installation was required to be carried out within the shutdown period. This triggered the development of a novel approach for a modular fabrication of tank, transportation in parts and installation strategy, to maximize pre-shutdown activities and enable optimum use of shutdown duration for the installation. Accordingly, study addressed this concern through extensive interaction with tank fabricator and recommended suitable methods.

Modular fabrication and installation of a new tank within live process units to ensure reliable and safe operations, is a novel approach to addressing the solvent storage issue. This approach will also avoid delays and extended shutdown duration.
The Autonomous Management of Wells with Unplanned Sustained Casing Pressure
Authors: Brodie Alan
Published: November 2016

Unplanned Sustained Annulus Pressure (SAP) in the A Annulus (sometimes referred to as the tubing/casing annulus or TCA), is the most common of all well integrity management challenges. Typically, this is as a result of a failure in a well integrity barrier envelope element / component. Monitoring for this situation is of critical importance because it generally means the ‘double barrier' well integrity policy that most OPCO's follow is breached. Depending on the nature of the SAP, it is often necessary to close in the well pending workover. In other cases, where a workover is not economically viable, the well may be prematurely abandoned. Alternatively, the wells may remain in operation ‘under dispensation'.

In the cases where wells continue to operate ‘under dispensation' increased manpower is required for monitoring and manual bleed down. This is to avoid the SAP exceeding the Maximum Allowable Annulus Surface Pressure (MAASP) and to monitor for any changes in the nature of the SAP. In addition to the obvious increased risks associated with a pressurized annulus, where only a single barrier to flow exists, other significant risks are also, often unknowingly, accepted. This is due to the way annulus pressure is typically measured and recorded. These annulus pressure measurement risks and a field proven solution to mitigate them, are described in this paper.

The paper also describes a field proven solution to the challenge of managing wells with unplanned SAP in the A annulus. It involves retrofitting technologies, which were originally developed for use in gas lifted wells, where the wells are designed to cater for planned SAP in the A annulus.

A leak from the A annulus of a gas lifted well would usually pose a higher risk of an explosion than would be the case from a non gas lifted well with SAP in the A annulus. Consequently, the paper therefore concludes that the approach used to provide a double barrier envelope to prevent a gas release from the A annulus in gas lifted well, can therefore also be applied in non gas lifted wells, where the SAP in the A annulus is unplanned. As a result, the risks of operating wells ‘under dispensation' are reduced. Wells which previously had to be killed or plugged pending workover or abandonment, may also be reclassified as ‘capable of operating under dispensation'.

The paper describes how the system can be automated, to facilitate autonomous annulus pressure monitoring and bleed off without manual intervention. It goes on to discuss how the nature of the SAP can also be tracked and the sampling frequency optimised.

Finally the paper describes how these technologies can be retrofitted to existing wells. This is possible, without the need for workover, annulus depressurization, wireline intervention or significant wellbay piping modifications.
Overcoming the Design Challenges of Brownfield Projects
Authors: Hassan Khurram , Wasnik Rakesh Vasant , Singh Harendra , Kamal Faris Ragheb , Takeiddine Oussama
Published: November 2016

Major investments have been made by the Oil & Gas industry in large-scale Greenfield projects to boost offshore & onshore facilities production. In today's low oil prices scenario, industry's focus is shifting towards Brownfield projects which have relatively low CAPEX and high Return on Investment (ROI). However, Brownfield project execution involves many unique design challenges that are not generally encountered in Greenfield development. The paper presents a variety of such challenges, and strategies for mitigating the same.

Successful execution of Brownfield projects is inherently complex due to constraints and unknowns in existing facilities. Many issues are identified only during execution stage, and thus result in late changes in design and /or scope. Shortfalls become apparent only during execution, resulting in delays to project completion, production loss to Company and possible cost overruns to Contractor. This may lead to erosion of ROI for such projects. It is therefore essential to identify issues early on in design, and ensure alignment of all stakeholders, including the Vendors.

Key design challenges usually faced during Brownfield project execution include:

Limitations in existing design, especially for equipment / systems not adequately addressed in Front End Engineering Design (FEED) such as utility systems, flare systems, layout constraints, safety related design requirements, tie-ins etc. Incompatibility between the existing and new equipment / systems Data / Estimates on health of existing equipment Availability of current asset documentation / as-built data in electronic format Discrepancies between design codes / standards used in existing systems versus latest codes / standards Poor planning due to lack of details and understanding of existing facilities

Design and engineering challenges are required to be addressed early on in the project lifecycle, to avoid project execution issues. For example, in one of the Brownfield Engineering Procurement and Construction (EPC) projects, the scope included replacement of an existing pump with a new pump of similar design. It was later found that the new pump also required modifications in the control system, recycle loops, facility layout, etc. In another case, an existing separator that was considered adequate for receiving well fluid from a new pipeline was later found inadequate based on network simulation results, and thus required major modifications in the implementation phase.

NPCC has been involved in many challenging Brownfield projects. The paper describes strategies to address such design complexities and challenges based on the successful experience in a number of major EPC Brownfield projects.
ERD Lower Completion Deployment: An Iterative, Multi-Disciplinary Approach
Authors: Beaman Daniel , Newton Daniel , Clews Matthew , Alvarez Juan , Allahyarov Rashad , Molster Jon , Al Khatib Osama , Parihar Shardul , Ryan James , Akyabi Khalid , Niznik Michael
Published: November 2016

The long term development from four artificial islands of this giant offshore field in the United Arab Emirates (UAE) is requiring longer and longer ERD wells. This can only be achieved by drilling higher angle, higher departure and increasing lateral lengths. Horizontal departure ratios have increased from 2:1 to 3:1 and will, before the development has finished approach 4:1. Maximum Reservoir Contact (MRC) lateral lengths at the beginning of the development were planned to average 10,000ft but are already being lengthened to 20,000ft, and beyond.

This paper describes the many challenges that have arisen and have been successfully overcome to enable deployment of 6 5/8" horizontal lower completions of lengths up to 20,000ft into wells that are greater than 30,000ft MD.

These challenges have been surmounted through the use of proprietary in-house software, leveraging partner resources and global experience, close collaboration between drilling, completion and field development teams, new technology equipment development and deployment methodologies.

Several case histories will be presented and discussed at length in this paper. These will focus on specific aspects for each of the wells such as the; high strength liner connections, high load liner running tools, reservoir drilling fluid composition, swellpacker design, use of drillpipe or casing swivels, centraliser type and the effect of dog leg severity in the long reservoir lateral.
Best Practices and Challenges for Pipeline Design and Construction in Populated Area
Authors: Nath Nahum Kant , Al Awadhi Ibrahim , Narayanan Sathyanath
Published: November 2016

Pipeline Design and Construction in populated areas to ensure Safety and Integrity of Pipeline System as well as Public Safety in the pipeline vicinity is a major challenge.

GASCO is one of the largest gas processing companies in the world, and it is considered as the major energy and feedstock supplier for the majority of the power, hydrocarbon, and petrochemical industries based in the UAE.

GASCO operates pipelines network having total length of approximately 3,500km, and supplies Sales (fuel) gas to the various consumers such as ADWEA, EMAL, ICAD, UAN Refinery etc. in UAE. GASCO Sales Gas Pipelines pass through populated/industrial/city areas such as Mussafah, Maqta, Yas-Island, Khalifa City, Al Raha and Shahama, etc.

This paper presents the challenges and best practices adopted for Pipeline Design and Construction in GASCO Projects to ensure safety of the people in the vicinity, enhance process safety, improve integrity/reliability of the pipelines, minimize impact on normal operation and maintenance and reduce the risk of business interruption.

Major challenges faced in populated area are the finalization of pipeline route in city area, proper and adequate design to protect the pipeline and subsequently ensuring public safety, minimum impact to the environment, consideration of future developments, construction activities in congested area/ crossings, protection of existing utilities/facilities and third party activities in the vicinity of pipeline.

In GASCO Projects, during pipeline design in populated areas, it is ensured that minimum spacing requirement between pipeline and populated/residential area is as per GASCO Standard Practice, International Standards and QRA recommendations. Selection of Pipeline Location Class/Design Factor, maximum distance requirement between Sectionalizing Valves are complied with Pipeline Codes. Increasing Pipeline cover, Corridor Fencing, Markers and installing slabs for the pipeline protection from third party activities are other measures are taken into an account. The pipeline integrity is enhanced by considering remote operated block valves and pipeline leak detection system, increasing the frequency of Patrolling. Also conducting Pipeline Constructability review to identify the hazards during construction activities is very important. As a proactive approach, future developments in the vicinity of the pipeline is also considered.

GASCO best practices are based on the requirements of Pipeline Codes, International Standards, industry practices, and GASCO Specifications/Standards and experiences from previous pipeline projects.

The Best Practices followed in GASCO projects have ensured the safety of the public and GASCO pipelines for their safe, efficient and reliable operation. Confidence level in assuring integrity of pipelines is boosted. Similar approach will benefit the oil and gas industries for protecting pipelines and ensuring public safety in populated areas.
First Application in Sui Field of Near-Balanced Nitrified Foam Drilling Resulted in Record Drilling Time to Reach TD; in Pakistan – A Case History
Authors: Khalid Ali , Ashraf Qasim , Nusair Mohd. Khair , Luqman Khurram , Shah Rizwan , Ghulam N Agha , Ali Muhammad , Hasan Naveed , Baig Umair A. , Sajjad Muhammad
Published: November 2016

This paper reviews the recently concluded first near balanced nitrified stiff foam drilling application to drill Sui Main Limestone in Sui field Pakistan. The target Sui Main Limestone formation presented numerous drilling challenges in this field. While drilling conventionally total irrecoverable losses were encountered and the resulting loss in head caused the well to kick in. Simultaneously dealing with both these problems resulted in a great amount of NPT, sometimes which extended to a period of months. To address the said problems in an effective and efficient manner, an application of a highly innovative method was considered. Thus a near balanced stiff foam system was designed and found to be highly applicable to drill the Sui Main Limestone formation.

The design of a Near-Balanced Stiff Foam Drilling system (NBD) is first discussed in the paper, which is followed by an overview of the delivered results. While drilling the entire Sui Main Limestone formation no single event of circulation loss was recorded. Also throughout the entire drilling phase "near balanced" conditions were maintained successfully and no influx from the formation was allowed to enter the wellbore. In addition to completing these objectives, another remarkable achievement was that this section was drilled in a record time of 3 days with an average ROP of 14 m/hr while maintaining excellent hole cleaning and no other related drilling problems. In comparison of offset wells where drilling of the same formation would take sometimes up to 3 months, if drilled conventionally.

To sum up, an innovative near balanced stiff foam system was designed to drill the extremely challenging Sui Main Limestone formation. All of the set objectives were delivered to expectations. The operator was able to successfully pass through a cumbersome formation in a record time for this field. This paper elaborates the process used to design a successful near balanced nitrified stiff foam system with applicability for the Sui Main Limestone formation in Sui Field, Baluchistan, Pakistan. The objective of this paper is to highlight all delivered drilling objectives and present lessons learnt while drilling the Sui Main Limestone formation. This will allow for efficient designing of a near balanced stiff foam system for forthcoming wells with similar formations and similar problems.
Estimation of Passive Fire Protection Quantity – A Cost Effective Approach for Offshore Oil & Gas facilities
Authors: Al Ayass Rawad Ghassan , Jha Ajay Nandan , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama
Published: November 2016

Passive Fire Protection (PFP) is a vital component of fire safety strategy for oil and gas installations. Passive fire protection ensures that relevant structures, piping and equipment or its components have adequate fire resistance with regard to the load bearing properties, integrity and insulation properties during a dimensioning fire event to prevent against escalation of consequences. PFP is generally used for protection of the safety critical systems, maintaining integrity of structures, protection of equipment, barrier walls and floors to provide stability as well as to segregate the plant into areas of manageable risk. It thereby helps in limiting the impact of fire on a facility, safeguards lives of personnel, restricts the growth and spread of fire, allows personnel to escape and offers protection to firefighters.

The applicable Codes & Standards for PFP design are not prescriptive; rather performance based evaluation of the design is required to achieve desired fire safety. This approach, however, does not give unequivocal guidance to designers and can lead to ambiguities and overdesign due to interpretation differences.

In the experience of authors, overdesign of PFP in many cases has had significant domino effects on other aspects of the design such as: Increased space requirement and layouts changesIncreased weight which further impacts structural design particularly on off-shore installationsCost impact and schedule delays during the engineering phasesIncreased installation costAdded cost and complexity to plant inspection & maintenance for the entire operational life

In one such case, it was observed that the incorrect selection of acceptable fire duration and heat flux values resulted in more than double the required quantity of PFP. In another case for an offshore installation, higher heat flux, impairment probability and frequency values were applied for the entire facility, including elevated process facilities that were beyond the range of the jet fires. This resulted in an excessive requirement of PFP leading to weight and space increase as well as difficulties in implementation and project delays.

Based on these as well as other experiences, this paper proposes a structured and cost effective way forward for determining extent and reliable design of PFP while meeting current safety standards. The paper also presents some of the challenges the Contractor has encountered by way of actual case studies to demonstrate the effectiveness of the proposed methodologies for PFP estimation and optimization.
Full Field Chemical EOR in a Mature Southern Alberta Water Flooded Reservoir - The Little Bow Case Study
Authors: Ghedan Shawket G. , Doung Khoi , Kumar Anjani , Card Colin , Ha Helen , Thomson Anne
Published: November 2016

Despite the recent focus on unconventional resources such as shale gas and tight oil in North America, large unrecovered volumes of oil remain in conventional reservoirs making them viable candidates for chemical enhanced oil recovery processes. Replacing or following traditional water flooding with aqueous chemicals that use both surfactant & alkali to reduce interfacial tension and polymer to improve sweep efficiency has been successful in recovering incremental oil from these reservoirs. However, designing the chemical injection scheme is complex, and must be tailored to specific reservoir rock and fluid properties. A strategic design methodology can help provide an optimal, well-performing chemical formulation, even for challenging reservoirs.

Currently, there are around ten Canadian chemical injection projects in operation with the latest being the Little Bow Upper Mannville "I" Pool. An ASP EOR project was initiated in this reservoir in March 2014 in a multiphase development plan. When the project was initiated, Little Bow oil (Phase 1&2) production was around 350 bbl/day. Successful implementation of this project is expected to result in incremental recovery of 5.2 million barrels of oil (12% of the OOIP) over the base waterflood. As of January 2016, 6.648 million barrels of ASP solution has been injected in the reservoir and the field is now showing first signs of incremental production.

This paper presents a workflow that integrates laboratory results, geological and geophysical data and production history into an effective forecasting model. Complex geology and a long production history of the partly depleted Little Bow reservoir have presented a challenge for history matching the primary and water-flood production. Through an iterative process, a full field model was built, history matched, then used as a base case to determine an optimal operational design for the full field.

A multidisciplinary team including geologists, exploitation and reservoir engineers collaborated to develop a 3D geological model and achieve the history match using an iterative approach; resulting in an idealized workflow and a superior history matched model. Using this model and an advanced optimization algorithm, a full field ASP operation design was optimized (based on NPV) for slug sizes, chemical concentrations, pattern design for injection/production wells locations, and drilling & workover locations. The optimized ASP injection scheme is implemented and some field results from January till June 2016 are presented in the paper.
Fugitive Emission Monitoring Program at Dolphin Energy Limited Gas Processing Plant Ras Laffan Qatar
Authors: Atiyeh Rola , Kumar Abhay , Moorthy Dhanaraja
Published: November 2016

One of the key sources of Volatile Organic Compound (VOC) emissions in a natural gas plant are leaks from equipment and pipes known as fugitive emissions. These are unintentional losses due to wear and tear on the facility and manufacturing defects or corrosion. Since 2011, Dolphin Energy has implemented an annual Fugitive Emissions Monitoring (FEM) Program to monitor potential leaking sources from equipment at its onshore Gas Processing Plant in Ras Laffan, Qatar. The objective of this paper is to highlight the progress made through implementation of the FEM Program. The first step of the FEM Program was to identify the process streams handling fluids that contain VOC ten percent by weight or more (>10%) and differentiate among streams handling gases/vapors, light liquids and heavy liquids. To perform its Leak Detection and Repair (LDAR) Program, the company reviewed the inventory of potential leak sources to be included in the Program, then carried out source tagging, monitoring with gas detectors to identify leaks greater than 10,000 ppm, performed leak repairs by maintenance personnel, then conducted further monitoring of repaired leaks and reported on VOC emissions before and after repair. In 2015, The FEM Program covered a total of 82,916 potential sources of leaks out of which 64,983 were accessible and measured for fugitive emissions. Stem control valves were the source-type resulting in most of the leaks above the repair threshold and were the equipment to focus on to reduce significant VOC emissions. This FEM Program has led to an average of 44% reduction in fugitive emissions since the Program started in 2011. Successful implementation of the FEM Program enabled Dolphin Energy to increase its revenue by reducing the fugitive losses, reduce the fire and toxic gas leak risks in the plant, check the integrity of plant equipment, and reduce its carbon footprint on the environment.
Enhance ECD Management Using Sub-Based Uninterrupted Circulating System Application
Authors: Dharma Dion S. , Hidayat Andri M. , Irawan Fikri
Published: November 2016

Bottomhole pressure management is essential to address challenging issues in hostile drilling environmentsbecause of wellbore pressure disparity during pump cycles while in circulating or noncirculating modes. This disparity can cause substantial instability on equivalent circulating density (ECD). While drilling in deepwater, HPHT, or any other hostile environment, these conditions may result in costly nonproductive time, may jeopardize operational safety, or may disrupt the well drillability.

One of the most advanced methods to enhance ECD management during drilling and connection is use of a sub-based uninterrupted circulating system. This technology has been proven to improve drilling performance by maintaining continuous circulation during drilling and connection to retain wellbore pressure stability without significant changes to the rig operation system. This system enables operators to improve drilling performance in wells with a slim pressure window, challenging geomechanical instability, extreme temperature (geothermal), high and long tangent section where hole cleaning is very essential, as well as in extended reach. This system also can be easily integrated with managed pressure drilling technology that exists in the present market.

This system uses a small-footprint, sub-based system with an automated flow switching mechanism to eliminate personnel exposure to the high-pressure system. By maintaining steady state circulation throughout the drilling process, the CFS remedies wellbore pressure disparity to retain continuous circulation and ECD management along the entire wellbore. This condition can effectively assist the operator to reduce nonproductive time, to enhance operational safety, and to enable drilling the well to target depth in a timely and safe manner. This paper will describe the equipment design of this uninterrupted circulating system as well as the best practice and constraints during operation. Generic factory testing will also be discussed to provide comprehensive understanding the reliability of the system.
High-Resolution Reservoir Mapping: From Ultradeep Geosteering Tools to Real-Time Updating of Reservoir Models
Authors: Arata F. , Gangemi G. , Mele M. , Tagliamonte R. L. , Tarchiani C. , Chinellato F. , Denichou J. M. , Maggs D.
Published: November 2016

This paper presents a method for integrating information obtained from ultradeep azimuthal electromagnetic (EM) technology, and processed during geosteering activity, to update a 3D reservoir model.

The latest developments in logging-while-drilling (LWD) technology, unimaginable until a few years ago, dramatically improve understanding reservoir structure far away from the wellbore. Ultradeep azimuthal EM technology provided a step change in remote detection capabilities by mapping resistivity contrasts up to tens of meters away from the wellbore. This innovation helps identify unexpected pay zones while drilling, improves subsurface understanding, and leads to well placement optimization in real time. In addition, the multiboundary reservoir mapping, provided by inversion of the ultradeep azimuthal EM measurements, allows for improvement in 3D reservoir model updates when addressing field development optimization.

The method presented integrates field geological knowledge, wellbore-centric LWD data (logs and images), EM reservoir mapping information, and interpreted seismic data to refine a 3D reservoir model in the neighborhood of the well. The ultimate goal is to include the data acquired in horizontal wells in a live reservoir model update across the entire cycle of the well placement workflow. The process includes a feasibility study for technology and strategy selection, real-time geosteering execution and data integration to update the 3D reservoir model in near real time. Collaborative cross-disciplinary teams, composed of both operator and service company specialists, are focusing more and more of their attention on integrating this information into optimal field development strategy.

Nowadays, it is possible for operators to handle multiboundary reservoir mapping data directly within dedicated geological modeling platforms. Advanced software solutions, designed to improve data accessibility, are the base for new integrated workflows for accurate 3D reservoir models using a multiscale dataset.
A Robust Automatic Dip Picking Technique to Improve Geological Interpretation and Post-Drill Formation Evaluation of Azimuthal Wellbore Image Logs
Authors: Ye Shin-Ju
Published: November 2016

Automatic dip picking avoids the disadvantages of hand picking (subjective, time-consuming, and ergonomically unfriendly); in particular, it reduces dip uncertainty for low-resolution borehole images. Many automatic dip picking methods have been developed since the 1950's. Each of these methods is tied to a specific type of tool (e.g., dipmeter tools or partial-wellbore-coverage pad-type imagers), and they are unreliable to process high-angle and horizontal (HAHz) wellbore azimuthal image data.

This article presents a new method to detect dips in HAHz borehole images. Although this method was originally designed for full wellbore azimuthal images, it is applicable to any dipmeter and pad-type image logs. The proposed automatic dip picking method is simple, yet robust. It consists of the following three main steps: first, determine an optimal sinusoidal trend on the image at each depth using a minimum-variance technique; second, compute the contrast at each depth along the optimal sinusoidal line on the gradient (or first-derivative) image; and finally, locate bedding surface boundaries at depths with the highest contrasts.

This method emulates the human pattern recognition process by first observing overall global image sinusoidal trends, and then examining detailed local bed contrasts to locate the bed boundaries. Conventional pattern fitting methods using edge detection and Hough transform (or sinewave fitting) can be unreliable and greatly affected by the noise and artifacts on the image, as these methods focus immediately on detailed and localized image features, and often overlook global image patterns.

Although other correlation techniques have been tested, the minimum-variance method is the preferred approach, for it generates the most consistent sinewaves. It correlates all azimuthal bins simultaneously and is much more reliable than two-curve correlation methods. Since the variances are calculated along sinusoidal lines, there is no need to perform individual sinewave fitting.

The minimum-variance method combines the conventional, complicated, two-step dipmeter processing methodology (first curve correlation, then sinewave fitting) into one single step to determine an optimal local sinewave. With fewer steps, there are fewer scenarios and problems to consider and fewer parameters to adjust. Moreover, at each depth, the minimum-variance method can find the optimal sinewave within a full range of search parameters (sinusoid amplitude and phase). It can identify faults if visible, as well as reversed sinewaves in "bulls-eye" sections where the wellbore axis is almost parallel to the bedding planes.

The proposed method has been applied to many logging-while-drilling density images and dipmeter data from fields worldwide. It has substantially reduced the interpretational time and dip uncertainty in building earth models from image logs for logging tool response modeling in petrophysical evaluation.
Coupling Production and Injection Systems with Multiple Reservoir Models: A Novel Method of Optimizing Development Strategies in a Mature Giant Oilfield
Authors: Su Shi Jonathan , Patacchini Leonardo , Mohmed Farzeen , Farouk Magdy , Ouzzane Djamel , Draoui Elyes , Torrens Richard , Amoudruz Pierre
Published: November 2016

The building of an integrated asset model for a giant carbonate oil field located offshore Abu Dhabi, consisting of two separate subfields with common production and injection networks, is presented with selected use cases.

Coupling is performed periodically at the wellhead, using a reservoir simulator in which the field manager controls the reservoir models by supplying well constraints and controls the network models by supplying well performance curves. Allocation strategies and pressure and flow constraints are imposed by the field manager, for which the different sub-models are black boxes; the models themselves are controlled hydraulically without embedded production or injection constraints.

This explicit approach has been selected for its flexibility. In particular, by expressing rates at the surface-subsurface interface at standard conditions, it is possible for the two reservoir models to have different equations of state and different treatments of injected water salinity, while the surface models use a black-oil fluid description.

This project required ensuring rate continuity at the transition from history to forecast for over 600 active production and injection strings, even when the reservoir and network models are not perfectly history-matched. This was achieved by introducing pressure shifts in each vertical flow performance curve to ensure continuity of the choking margins (i.e., differences between wellhead pressures and backpressures) and by overriding the default guide rate flow allocation method of the field manager to prevent abrupt changes in the production split of wells currently producing below potential.

The use cases described here are based on an eight-year (2015–2023) drilling schedule followed by no further activity. We focus on assessing the impact on production and injection arising from: replacing pipelines or changing network topologies; relaxing the constraint of producing at initial solution gas-oil ratio with and without reduction of separator pressures; and redistributing or increasing the water injection capacity.
The Potential of a New Distillation Process for the Upgrading of Acid Gas
Authors: Pellegrini L. A. , De Guido G. , Langè S. , Moioli S. , Picutti B. , Vergani P. , Franzoni G. , Brignoli F.
Published: November 2016

In this work, the potential of a new low-temperature distillation process for natural gas sweetening has been investigated. The proposed technology consists of a dual pressure distillation scheme, developed to bypass the SLV locus of the system CH4-CO2 in order to avoid the formation of a solid phase in all the parts of the process, while still being able to fulfill the required natural gas purity specifications.

The performances of the new low-temperature distillation process have been assessed for different case studies, considering gas feeds with a CO2 content and with a H2S content in the range 5-65 mol% and 0-15 mol%, respectively. The profitability of the proposed solution has been determined in terms of energy expenses when compared to the more traditional MDEA gas sweetening process. The work has been performed coupling the use of a commercial process simulator (Aspen HYSYS® V7.3) with in-house Fortran routines for the thermodynamic modeling also accounting for the presence of a solid phase.

The new solution has been studied and optimized in terms of energy savings related to the cooling duty consumptions. Results of the analysis have shown that the relative trade-off between the two technologies depends on the contents of the acidic compounds in the natural gas stream and on the geographic area where the gas field is located. The new low-temperature technology has shown higher performances and economic profitability when compared to the more traditional gas sweetening processes (such as absorption with alkanolamine solutions) when the CO2 and/or H2S content in the natural gas feed is high, thus possibly enabling the exploitation of extremely acid and sour gas fields.

The obtained results have been used for the design of both an industrial unit and a pilot plant that is going to be used to test the process on a lab-scale.

The increasing energy demand compels industry to design new solutions for the profitable exploitation of natural gas reservoirs with high CO2 and/or H2S content.

Low-temperature distillation technologies represent a cost-effective alternative when sweetening natural gas containing a high amount of acidic components.

The new process exploits a different and simpler approach from the ones known in the literature, being able to offer the competitive advantages of low-temperature technologies while avoiding CO2 solidification and solvent addition.
Simple and Reliable Innovative Fluid Dynamic Technology Maximizes Oil Recovery in Upper Burgan Reservoir
Authors: Al-Hajeri Nasser , Osamn Yasser , Safar Ahmad Ibrahim , Al-Muttar Bader , El Anany Sayed , Aman Bader , Karode Vijay , Kalyani Tejas , Kumar Ajit
Published: November 2016

Production in the Upper Burgan reservoir began in the Raudhatain and Sabriyah fields in 1959 and 1970, respectively. However, significant quantities of original oil remain in the reservoir; although the Upper Burgan fields have both been in production for more than 56 years, the offtake to date is a relatively small percentage of the potential ultimate recovery.

The sandstone of the Upper Burgan is typically fine grained. Porosities average 25% and can reach 30% in the best quality sands. Horizontal permeability values of 200 to 700 md are common, with variation in vertical permeability caused by changes in the texture and structure of the reservoir. In 1995, the operator initiated a strategy to significantly increase production from these North Kuwait fields by integrating a multidisciplinary team from within the operating company. Waterflooding was part of the Upper Burgan development plan, during which the heterogeneous reservoir was expected to encounter early water breakthrough compared to other North Kuwait reservoirs.

After 20 years of waterflooding in the Upper Burgan, the water cut reached 50%, and water management became crucial with reduced hydrocarbon recovery from the field.

Autonomous inflow control device (AICD) technology with screens was installed in a pilot well in the Upper Burgan reservoir to help reduce the water production and increase the oil recovery from the well. AICD technology uses fluid dynamics technology to differentiate the fluids flowing through the device. When water breaks through, the AICD creates a pressure drop to restrict production flow at that device, favoring the production of the healthy oil-statured zone, thus increasing expected ultimate recovery from the well. The AICD has no moving parts, electronics, or connections to the surface and employs a unique geometry that alters the flow path within the tool upon water and/or gas breakthrough.

This technology has helped improve recovery by reducing water cut from the high water-saturation zones, thereby increasing the overall oil recovery from the well. Forecasted well performance with AICD technology is in line with actual production and water cut.