bluuebunny/crossref_metadata_2025 huggingface dataset:
Smart Automated Designs for better HSE Performance
Authors: Akhtar Muhammad Adnan
Published: November 2017

The ADGAS plant facilities include three LNG trains (Trains-1 & 2 commissioned in 1977 and Train-3 commissioned in 1994), Offshore Associated Gas (OAG) and Integrated Gas Development (IGD) facilities along with utilities and other associated facilities such as storage tankage, jetties for export of the products, etc. The gas feedstock comes from various offshore oil and gas fields surrounding Das Island. The feed gas, delivered to the plant at different pressure levels is compressed through different stages and purified before liquefaction. The feed gas contains impurities like CO2 (Carbon Di Oxide) and H2S (Hydrogen Sulphide), which are removed by gas sweetening process. H2S removed by the sweetening process is converted into liquid Sulphur in the Sulphur Recovery Units. After sweetening, the hydrocarbon gas mixture is cooled in stages followed by fractionation and liquefaction to produce different hydrocarbon products ranging from LNG (a mixture of methane and ethane) to Paraffinic Naphtha.

ADGAS commissioned the OAG and IGD facilities in 2010 and 2013 respectively, enabling gas export from Das Island to onshore Habshan facilities through a subsea pipeline. The primary objective of OAG facility is to process additional quantities of LP Gases that has become available at Das Island from ADMA-OPCO, following increase in oil production. The process involves compression of LP Gases, Dehydrate and dispatch 211 mmscfd of Gas & Condensate through marine pipeline to GASCO facility at Habshan. OAG (two processing trains) processes about 200mmscfd gas whereas The IGD was commissioned in the year 2013. This comprises of three Trains capable of delivering 900 mmscfd of dry compressed HP Gas at 155 Bara through marine pipeline to GASCO facility at Habshan.
Using Casedhole Formation Evaluation to Bridge the Gap when Openhole Logging is Not Feasible
Authors: Ramamoorthy Raghu , Al Aryani Fatima Mohamed , Mavromatidis Angelos
Published: November 2017

During drilling, openhole logs provide valuable data to identify the location of hydrocarbon resources, characterize the host formation, and quantify the asset in terms of size and producibility. Such data acquisition during field appraisal plays a critical part in the preparation of the field development plan. However, openhole logs may not be available or may not be possible due to various constraints. In some cases, data that is essential for petrophysical evaluation has been overlooked during the planning of the openhole log acquisition. In other cases, wellbore conditions while drilling may preclude openhole logging in favor of securing the well. This latter scenario can often occur in appraisal wells when knowledge of the pressure regimes in the different formations in the field is still incomplete.

Several logging services are available for acquiring formation information through casing. This capability can provide an excellent option to acquire the necessary formation evaluation data through casing, thereby completing the input to the decision-making process.

We present three separate examples in which casedhole formation evaluation was used to augment data acquired in the open hole for an improved formation evaluation. The applications range from providing reliable density and sonic data for seismic tie-in to providing more accurate estimates of porosity and saturation for selection of test intervals or for input to the static geological model. The examples demonstrate the use of various through-casing formation evaluation technologies including density, neutron, resistivity, acoustic compressional and shear slowness, and pulsed neutron capture and inelastic spectroscopy logs. We show that through a judicious combination of logs the primary evaluation objectives can be fulfilled.

We discuss the challenges in data acquisition, the steps for quality assessment of the data acquired through casing, and interpretation procedures to integrate all the data in an answer product. The substantial benefit of such an option to the operator is also discussed.
Building a Common Narrative on Employee Performance
Authors: Ramachandran Karthik Nataraj , Al Hosaini Khalil , Al Hammadi Ayesha
Published: November 2017

The objective of this paper is to study the impact of building a common narrative in the performance appraisal system for a large Middle East based corporation in its drive to build a performance driven culture. This study assumes even more significance when taking into account the countries nationalistic culture, which has a high power distance index and high uncertainty avoidance index as per the Hofstede Cultural Dimensions Index. Change management initiative is expensive in nature more so, in a pluralistic environment with multiple cultures as the case of the organization under study. The challenge becomes even more difficult if the change is targeted at the existing cultures in the organization. As the authors were part of the change management initiative, the various stages adopted in moving the organization culture from entitlement to performance are analyzed in detail. The use of common narratives and unified performance appraisal methodology, leadership engagement and Normalization process lead to a demonstrated change in the performance appraisal rating for the targeted group of employees. The impact of the common narratives, lead to a decrease in the rating of exceeding and above categories for managers and above by almost 50 %.What it effectively highlights is that the journey to build a performance driven culture is ongoing and it’s through the common narratives and understanding that the desired outcomes can be achieved. Such a large scale study on the impact of building a new performance culture has not been done in the Middle East before. The learnings would be of immense value to organizations wanting to incorporate such changes in the future. In addition, limited papers have adopted the action research method to observe culture creation phenomena in spite of it offering clear insights due to the involvement of the authors in the culture creation.
Upscaling Chemical Looping Combustion for Enhanced Oil Recovery
Authors: Snijkers F. M. , Jacobs M. , Albertsen K. , Moldenhauer P. , Mattisson T.
Published: November 2017

Chemical looping combustion (CLC) is an innovative technology for heat production with inherent capture of carbon dioxide at minimal energy penalty. Its development is highly relevant since it addresses CO2 capture needed for closing the carbon loop as a contribution to mitigating climate change, one of the big challenges of today's society.

In CLC, oxygen is transferred from an air reactor to a fuel reactor by means of a solid oxygen carrier. Thus avoiding direct contact between air and fuel, and after condensation of water, an undiluted CO2 exhaust stream is obtained. CO2 is more and more considered as a valuable chemical substance for enhanced oil/gas recovery projects as well as for the production of chemicals, polymers or building materials. It can potentially be an option for several types EOR namely were miscible gases for injection are needed, for steam EOR and for CO2 EOR.

Strategic to CLC technology is the oxygen carrier that is in the heart of the process. Parameters such as particle size and distribution, density, porosity, strength, attrition resistance, reactivity, environmental aspects and cost, define the performance of the oxygen carrier. The first generation oxygen carriers were Ni-based. However, due to cost of nickel and toxicity, a search for Ni-free oxygen carriers was conducted with similar or superior performance in CLC. This has lead to the development of Mn-based oxygen carriers, that demonstrate the beneficial oxygen uncoupling effect, with complete fuel conversion as a result. In the EC 7FP project SUCCESS, a promising oxygen carrier based on perovskite calcium- manganite with good fluidisability, high sphericity and high attrition resistance, was upscaled to the industrial scale. In this contribution results are presented obtained with oxygen carriers that have been produced by the versatile and industrial scalable spray-drying technique. Results are discussed that have for the first time been obtained with an upscaled process. The oxygen carriers were fabricated with the industrial spray drying process for multi-tonne scale production in order to accommodate for chemical looping plants of 10 MW and larger.
Advanced Model-Based Optimization of a Natural Gas Liquid Recovery Unit
Authors: Leyland S. , Georgis D. , Marriott J. , Andrade A. , Dara S. , Berrouk A. S. , Al Wahedi Y. , Geuzebroek F. , El Nasr A. S. , Ghanayem N. , Turner A. , Khan M I.
Published: November 2017

Natural gas liquids (NGLs) are the main contributor to the profitability of natural gas processing plants. During the recent period of relatively low natural gas prices, NGLs spot prices have experienced a slower drop remaining relatively steady. Therefore, switching the operation of existing facilities towards a higher NGL production can lead to a more profitable position. In this work, we develop and implement model-based optimization solutions on a selection of NGL plants in order to improve the profitability of the facility.

Such analysis is meaningful only when high-fidelity validated first-principles models are employed within an equation oriented environment using rigorous mathematically formulated optimization algorithms which guarantee that the optimal solution satisfies all safety and operational constraints. In this work, an equation oriented commercial process simulator is utilized which offers unique optimization capabilities of very large and complex process flowsheets.

In this paper we demonstrate the practical benefits of Advanced Model-based Optimization through a case study of an NGL Plant in Abu Dhabi. The workflow is discussed starting from model formulation and validation, to optimization and assessment of the optimal operational strategy. We also discuss how the deployment of such model-based optimization activities can be used to develop operating guidelines that allow operators to drive the plant towards optimal operation and address a range of operational situations; giving them the ability to respond to changes in the plant or economic conditions quicker and with more confidence than previously possible.
How ISO Principles can Simplify Process Plant Desgin, Construction and Maintenance to Deliver Cost and Production Efficiences
Authors: Subahani Ashik , Steven Iain
Published: November 2017

The design of offshore production process plant is a time-consuming and costly activity where in many instances the design of each new plant begins from the ground up. Where suitable designs already exist, their re-use is often prevented due to ownership of Intellectual Property and copyright.

A new methodology, based upon the principles of ISO Modularisation, is offered with the expectation that this methodology can deliver cost savings, production efficiencies and weight savings.

The authors examined existing literature in the fields of both process plant design and modularisation relative to manufacturing. By combining their hands-on experience, the authors are a marine engineer and naval architect, with the findings of the literature review the authors believe a standardisation modularised approach to process plant and design can benefit the offshore industry.

The authors conclude that such an approach could deliver: ○A reduction in design and construction time;○A reduction in design and construction costs;○Introduction of standardised design principles○Introduction of standardisation in pricing for design, construction and assembly;○Ease of maintenance and upgrading;○Advantage during transportation○Safer approach○Reduction in loss of production time via a quicker change of components during overhauls;○Reduction in the cost and constraints of supporting offshore maintenance and○Facilitation of reuse at end-of-life.

The new information presented will reveal a patent pending ISO Modularisation concept with standard x, y and z interface points. This approach, offered as an alternative to the current industry practise of designing process plant from scratch, will deliver a cost-effective method of process plant design, construction and maintenance with financial and efficiency savings.
Evaluation of Miscible Water Alternating Gas WAG Injection by Comparing with Lesson Learnt from an Immiscible Gas Injection Pilot
Authors: Kohata Akihiro , Willingham Thomas , Chen Peng , Al Sowaidi Alunood
Published: November 2017

To sustain the long term production from a giant offshore reservoir, a simulation study evaluating and comparing miscible hydrocarbon (HC) Water-Alternating-Gas (WAG) with a prior pilot test implemented in the field evaluating immiscible HC Simultaneous Water-And-Gas (SWAG) has been carried out. This paper describes the evaluation of recovery uplift for the miscible HC WAG by comparing study findings with actual field results for the immiscible HC SWAG pilot.

In order to evaluate miscible HC WAG potential, sector model simulation studies were carried out and it was concluded that a 11% recovery uplift over base water injection could be achieved by miscible HC WAG. On the other hand, an analysis of the immiscible HC SWAG pilot test including history matching simulation was conducted and it was concluded that immiscible HC SWAG had little impact on recovery uplift. In order to evaluate the differences between the planned miscible HC WAG implementation and the immiscible field pilot test results, the comparative investigation was conducted using sector model.

The area where the immiscible SWAG pilot was conducted was geologically similar to the target area for the miscible WAG. To confirm the geological similarity of the two areas, simulations for immiscible injection using a 5-spot configuration consistent with the immiscible SWAG pilot were carried out for each area. Results indicated gas distribution was similar in the two areas and was in agreement with actual pilot results; hence, it was confirmed that the impact of geologic differences of the two areas was limited. The other differences between the planned miscible HC WAG and the immiscible SWAG pilot were (i) injection scheme (WAG or SWAG), (ii) well configuration (line drive or 5-spot pattern), (iii) well spacing (500 m or 1 km) and (iv) injectant (miscible HC gas or immiscible HC gas). Simulation models capturing each scheme were developed. Through the injection scheme sensitivity simulation studies, it was concluded that (i) WAG, (ii) line drive, (iii) 500 m spacing and (iv) miscible HC gas were preferential to (i) SWAG, (ii) 5-spot pattern, (iii) 1km spacing and (iv) immiscible HC gas, respectively. The combination of these factors resulted in a 21% recovery uplift beyond the prior immiscible HC pilot. Hence, through this work we demonstrate that a reliable evaluation for recovery uplift with miscible HC WAG was achieved through the comparative investigation of the immiscible HC SWAG field pilot test results and the planned miscible HC WAG implementation, including the analysis of the impact of geology, injection scheme and well configurations.
Validating Automated Real-Time Produced Water Composition Measurement Device with Field Produced Water Samples: A Pathway to Field Trial
Authors: Ghorbani N. , Yan C. , Guraieb P. , Tomson R. C. , Abdallah D. , Ben Aouda A. , Odeh N. M. , Al Daghar T. A.
Published: November 2017

Mineral scale formation in the oil and gas industry can be detrimental to production and injection wells, and facilities yielding production losses and integrity issues. In order to manage scaling risk during operation, knowledge of production rates, GOR, WCT%, and hydrocarbon and produced water compositions along with reservoir pressure and temperature are required. Scale management relies on accurately monitoring produced water composition. In addition, the timing of changes in water composition is critical to proactively protect the production system from scaling. Preventing scale formation results in significantly reduced production loss, optimized chemical dosage, and fewer well interventions, consequently lowering OPEX and mitigating HSE risks. This paper documents advancements made since the last year publication by the authors on the real-time produced water composition measurement device. The device can automatically collect a discrete production fluid sample at the wellhead while keeping the pressure and temperature of sample constant, separating produced water from the bulk phase and measuring multiple properties: pH, alkalinity, strontium, barium, calcium, sulfate, total hardness, and total dissolve solids (TDS) at the pressure and the temperature of sampling point without degassing. It also reports the pressure and temperature of sampling point. This paper illustrates calcium automated measurement properties developed and a validation of the laboratory prototype by testing the device with four produced water samples from different formations: i) Permian Basin, ii) Bakken, iii) Eagle Ford; and iv) synthetic produced water from an oil field in Abu Dhabi. Results show excelent performance of the device for calcium measurement. For example, the mean of the device measured value for calcium based on internal calibration, was 42.84 mg/l with a standard deviation of 0. 084 compared with the laboratory reference method ICP-OES measurement of 42.63 mg/l, which shows very accurate measurement of calcium. This paper presents the reliability and repeatability of the device in addition to the results accuracy compared with ICP-OES and traditional laboratory analysis methods. The results obtained from production fluids were promising. Laboratory validation is the last step before field testing the device. The success of the laboratory validation stage is crucial as the device progresses through final design changes ahead of field trials. Measuring produced waters with different salinities promote the device reliability and fills the gap between synthetic water composition measurement in laboratory and the field trial. The device was developed to enhance reliability of water properties measurements, provide real-time measurements, and reduce downtime and costs associated with workovers, interventions, and sampling.
Strength and Deformation Capacity of Lined Pipelines using Advanced FE Modelling
Authors: Bartolini Lorenzo M. , Bruschi Roberto , Marchionni Lorenzo , Parrella Antonio , Vitali Luiinog
Published: November 2017

DNV GL has recently carried out a JIP to propose rational design criteria for clad and lined pipes. Attention has been paid to pressure containment, local bucking/wrinkle, fracture and fatigue limit states. In DNV GL JIP design guideline, a strain criterion for the liner wrinkle limit state is proposed. The criterion is based on experimental test results and it does not include any safety factor. Advanced FE Model, purposely calibrated through dedicated experimental tests, can be developed to quantify the strength and deformation capacity of lined pipes considering installation and operational loads, pipeline geometry and fabrication technology and tolerances.

The FEM analyses well reproduced the behavior of clad/lined pipelines subject to combined loads. The presence of liner contributes to the overall pipeline strength and deformation capacity, although introduces an issue due to the risk of wrinkling and detachment from the baking steel. For lined pipes with no or low internal pressure, the liner will normally separate, i.e. wrinkle, from the backing steel prior to reaching the local buckling capacity of the backing steel alone.

Advanced FEM analysis approach can be very helpful for lined pipe strength and deformation capacity assessment, aiding engineer during the design process. The accurate reproduction of failure modes under combined loads can drive engineers through a proper design of clad/lined pipe in offshore extreme environment/loading conditions.
New Shear Thickening Dilatancy Dispersion Based on Nano-Silica Beads for Oilfield Applications
Authors: Al-Olayan Abeer M. , Alexander-Katz Alfredo
Published: November 2017

A new innovative shear thickening (STF) has been developed based on silica nano particles. The new material has the ability to form highly viscous gel in high shear / high temperature conditions. This innovation has been inspired by the medical industry that simulates the dynamics of biological polymers in a chain of blood clotting. The concept is based on the introduction of short and long polymers grafted randomly on silica particles. Rheological properties of the new STF were tested by Anton Parr Rheometer at different particle concentrations, polymer molecular weight ratios and temperature. The data shows that shear thickening has a good behavior in high temperature and provides a significant increase in fluid viscosity. This is a highly potential material for different oilfield applications.
RFID Enabled Safe Load Indicator Data Logging System Enhances Higher HSE Standards in Offshore Crane Operations
Authors: Chandran Dileep , Alila Morched , Al Owaid Hatim , Hantoosh Abdulla , Alawi Sami , Sajjad Yasir , Singh Kuljinder
Published: November 2017

Objective

To record the operational data through the crane Safe Load Indicators to Identify the risk in the Behavior of crane operators, to improve Safety standards and the need for (individual) basic training in offshore crane operation.

Process

The Data Logger system link with the Radio frequency identification (RFID) tags, which enable the Datalogger to record operation parameters in relation with the crane operator. The data is downloaded to an internal SD card or can be transferred to a Laptop computer for analysis using special software. The data is presented in the form of graphical charts based on the operator's ID.

The collected data shows the actual lifting performance and highlight the violation for each alarm under Operator ID. It will help in identifying the weak crane operator’s weaknesses and the points required training to improve his behavior. The system will assist supervisor’s in controlling risk takers behaivior.
Natural Gas Plant Debottlenecking Thanks to Hybrid Solvent
Authors: Cloarec Eric , Cadours Renaud , Weiss Claire
Published: November 2017

For the last decades, continuous global trend towards more stringent safety, commercial and environmental specifications kept processing sour natural gas containing acid gas such as H2S and/or CO2 a growing challenge. If mercaptans are present in the sour natural gas, the limited mercaptans absorption capacity of the well known alkanolamine solvents can be a major problem. The operating companies have to upgrade their production units to comply with these specification and environmental constraints evolutions. Additional treatment steps are often required to achieve the total sulfur specification in the sales gas, adding process complexity and further increasing cost.

An efficient solution to solve the problem would be to replace the usual alkanolamine aqueous solvent by a hybrid formulation allowing simultaneous removal on mercaptans and acid gases. This approach has been rarely considered because of the side effects of traditional hybrid solvents: hydrocarbon co-absorption, negative impact on the downstream sulfur recovery units. It may be necessary also to replace the internals of the absorber column in the Acid gas Removal Units.

To address this issue, TOTAL is now using a new dedicated hybrid formulation since 2007. This new solvent has been developed by TOTAL by taking advantage of its intensive know-how and experience in gas processing. The hybrid solvent is obtained by addition of a physical component into a generic alkanolamine-water solvent. The final solvent composition is determined to optimize mercaptans removal and minimize hydrocarbon coabsorption, without affecting acid gas removal capabilities.

Without any plant modification, this hybrid solvent can be implemented in existing unit to remove mercaptans with the acid gases, with no detrimental impact on downstream SRU. It allows operating cost reduction of the existing downstream units. Last but not least, the energy consumption of the acid gas removal units can be lowered by 10- 15%.

This paper presents several applications cases where the benefit of using the hybrid solvent is demonstrated.
Challenges with the Development of the Yamal Peninsula
Authors: Akimova Irina
Published: November 2017

The Yamal mega project – new evolving area, that combines production and infrastructure facilities and will have to replace the Nadym-Pur-Taz area – major gas production area in Russia since 1970s, that’s became legend by suppling almost all soviet and than Russian export contracts and securing domestic consumption at the same time. But currently Nadym-Pur-Taz is in its decreasing production phase and thus the need to provide substitution for this area is shaping the impotrtance of Yamal mega project for the Russian and international gas market development and security. The Yamal Peninsula and adjacent offshore areas have an enormous potential: the explored gas reserves with estimated and prospective resources total are 26.5 trillion cubic meters, 1,6 billion tonnes of gas condernsate and 300 million tons of oil and represented by 32 fields in total. [State commission on natural reserves. 2012]. Such significant resource base wil make it possible to produce here up to 360 billion cubic meters of gas per year by 2030. [Ministry of natural resources of the Russian Federation. 2012]
Research and Application of Ultra-Short Radius Flexible Sealed Coring Technology in Re-Development of Matured Fields
Authors: Liu He , Zhang Shaolin , Sun Qiang , Li Tao , Ming Eryang , Huang Shouzhi , Han Weiye , Chen Qiang , Li Yiliang , Pei Xiaohan
Published: November 2017

After long-term water-flooding, many of the matured fields in China have experienced changes in the physical properties of reservoirs. Moreover, the inefficient cycle of water flooding in the reservoirs is serious, and the heterogeneity of reservoirs causes difficulty to determine the distribution of remaining oil. It is impossible to reflect the real situation of the stratum only by simulation analysis with the numerical simulation software. To core in a specific location through coring technology and analyze the core can not only re-conduct a more accurate evaluation of the stratum, but also can modify relevant data of existing models to improve the simulation accuracy. But the current technology can’t conduct coring operations near wellbore and in deep parts.

Therefore, based on the ultra-short radius sidetracking technology, this paper aims to develop ultra-short radius flexible sealed coring technology to achieve coring outside the casing. Compared with the ultra-short radius sidetracking technology, the ultra-short radius flexible sealed coring technology has, in addition to the windowing, deflecting, and horizontal drilling tools, the core tools of this technology, that is, the flexible sealed coring tool. The tool is mainly composed of a flexible outer cylinder and a highly elastic titanium alloy inner cylinder. The flexible outer cylinder is connected by a multi-section of flexible units that can be bent up to 5°. And a special coring bit is connected to the front of the tool. The maximum length of the core taken in a single coring process is 1.1 meters; the core diameter is up to 40mm. By using this technology, the minimum horizontal distance of the core position and the borehole wall is 0.8 meter, and the maximum horizontal distance can be up to 100 meters.

At present, the technology has been successfully applied to more than 10 wells, and the average core recovery rate has reached 90%, which provides valuable data for the geological departments and is of great significance for re-developing matured fields.

This technology can obtain the core from outside of the casing and near wellbore, and offers a more accurate evaluation on changes of physical properties of the reservoirs, providing the basis for adjusting the subsequent water flooding development plans.
Case Study: Safe Thru-Tubing ESP Installation in Pressurized Well through Novel Killing Techniques
Authors: Abdelaziz Mohannad , Roth Brian A. , Xiao J. J.
Published: November 2017

Cable Deployed ESPs (CD-ESPs) are foreseen as the future of ESP installations as they eliminate the need for full-fledge rig on location to perform ESP change out. One of the main challenges of performing ESP installation riglessly is the lack of mud circulation system which is used to monitor increase in fluid loss rate, indicate possible well kick and bring the well back to control in case of such emergencies. With the lack of this line of defense, there is a need to develop alternative method to ensure safe rigless ESP installation particularly when ESP components are being made-up and lowered down the well.

The first high H2S vertical well CD-ESP worldwide was trial tested in a pressurized onshore well in Saudi Arabia. The candidate well had a shut-in pressure of 390psi, H2S concentration of 1.12% and fluid loss rate of 18-24 bbl per hour (bph) for 71 pound per cubic foot (pcf) kill fluid.

Kill fluid has to be continuously supplied at a rate equivalent to the varying loss rate of the well. For this, the surface well testing equipment (required for well flow-back after ESP installation) was modified to monitor and store excess kill fluid return. The new modification allows pumping of kill fluid to continue while Blow-Out Preventer (BOP) equipment are open on top of the Christmas tree. The density of the kill fluid was monitored and maintained during the whole operation.

The operation started by bullheading with one and a half wellbore volume. The well performance was monitored and then kill fluid rate was increased gradually to measure the loss rate of the well. Pumping of kill fluid was highly coordinated during the main installation phases of the CD-ESP: surface make-up of ESP assembly in sections, run in hole with cable to target depth and the final make-up of the cable hanger.

The returns of any excess kill fluid could be measured by the modified surface testing package. Pumping rate of kill fluid was highly correlated with Tubing Casing Annulus (TCA) pressure since the volume of fluid in the annulus changed (due to the small contraction/expansion of the seal bore assembly).

While the pump was inside the well, pumping kill fluid caused significant increase of weight reading. The pump (5.62") acted like a piston inside the (6.275") ID of the 7" tubing causing high weight values.

At one point during the operation, the loss rate of the well increased dramatically. This caused negative readings on pressure gauges of the wellhead (loss rate was higher than maximum pump supply).

The paper presents a novel comprehensive well killing measures for rig-less CD-ESP installation. To assure the safe conduct of future operations, the paper also shows lessons learnt and contingency measures for unexpected events during the operation.
Improving the Efficiency of H2S Mitigation in Middle East Oil and Gas Fields
Authors: Hofmann A. , van Strien W. , Malekzadeh R.
Published: November 2017

More than 60% of gas reserves in the Middle East region are regarded as sour. The development of sour oil and sour gas fields or originally sweet oil fields, which undergo a souring process during production live, impose significant investments for the H2S treatment and increase significantly the field operation costs. In order to evaluate the origin and development of the H2S in a production system multiple locations covering all process stations such as down hole, well head, separators, gathering stations, pipelines have to be sampled an analysed. The in-field measurements of the H2S concentrations and various laboratory analyses like S34 / S32 isotope ratio, CSIA, DNA sequencing, MPN and Bacterial growth tests could be performed in order to provide a conclusive picture of the H2S contamination.

The most promising and cost efficient technology is the analysis of the bacterial activity using DNA analysis and bacterial growth tests. The integration and interpretation of all above mentioned analysis types is key for the evaluation of the origin and development of the field souring process and provides a robust analytical basis for remediation, scavenging and mitigation operations. In combination with modern dynamic reservoir modeling tools, which allow the history match and forecast of the field souring process, the efficiency of mitigation or scavenging operations in the subsurface and at the surface can be simulated and optimized.

In context with the envisaged production enhancement, the application of EOR technologies and the souring of several reservoirs due to injection, the monitoring and handling of additional H2S production become an important environmental and economic factor.
Field Trial Results for 3rd Barrier Evaluation Using Technology of Individual Electromagnetic Metal Loss Logging Validated by Actual Excavations
Authors: Yugay A. , Daghmouni H. B. , Ali A. B. , Volkov M. , Sparke S. J.
Published: November 2017

Shallow casing corrosion in onshore wells is a well-known phenomenon throughout the Arabian Peninsula. It happens when the carbon steel is exposed to corrosive environment (including moisture and oxygen) due to insufficient barrier protection and isolation. The issue requires periodical casing excavation and inspection which are time-consuming operations with different teams involved. This document describes successful field validation of the alternative cost-efficient method of casing inspection using corrosion logging technology.

The method of individual electromagnetic metal loss logging for 3 barriers became recently available. It is electromagnetic-based technology which was modified to be able to provide multiple barrier evaluation. 3 wells were selected for trial logging and later were excavated to compare the logging results with actual findings (physical check). Results of the trial test confirmed applicability of this costefficient technology for Company Surface Casing Inspection. The new method allows extending casing inspection to unlimited depth with less time required and less risks associated. The opportunity to evaluate conditions of all three barriers without retrieving the tubing gives a lot of benefits for the entire Well Integrity Management process; it may include actual corrosion rate measurements of all effective barriers, SAP (Sustained Annulus Pressure) investigations, and risk assessments. Field validation of this technology had a positive impact on Operator's Well Integrity process, giving more options for proactive Well Integrity Management and resulting in total cost reduction and improved HSE (Health, Safety and Environment) performance. Additionally, it helped to identify a serious gap in the existing conventional process of Surface Casing Inspection.

This document presents the results of technology validation performed in the third barrier of a producing well in real field conditions. Additionally, it contains specific recommendations for other areas of application of this technology for maximum benefits, like three-barrier evaluation prior to workover and multiple barrier time lapse corrosion monitoring.
A Novel Method for Predicting 3D Pore Pressure in Over-Pressured Carbonates
Authors: Hamid Osman , Al-Qahtani Adel , Albahrani Hussain , Pamukcu Yusuf
Published: November 2017

Prediction of pore pressure in carbonate formations is a major challenge. When this challenge is combined with the possibility of abnormal pressure occurrence, accurate pore pressure prediction becomes a necessity. The over pore pressure intervals in those formations narrows the size of the drilling window to ~10 pcf (1.33 ppg) which requires high accuracy of pore pressure prediction. Inaccurate pore pressure data can lead to well-control incidents, poor casing designs, and inefficient reservoir modelling among other things. Therefore, a new model was developed to predict pore pressure in over pressured carbonate formation.

By employing acoustic logging data, a correlation between the effective vertical stress and Poisson’s ratio was developed to be used in combination with formation bulk density measurements in order to predict the pore pressure in 3D space relying on the Poro-elasticity theory. Comparing the results of the prediction process with the available Modular formation Dynamics Tester (MDT) yielded a significant fit. Through this correlation, the abnormal variations in the high pressure carbonate are detected to a significant level of accuracy.

Based on the produced correlation, the results of the pore pressure prediction process showed that the pressure gradient increases from 0.48 psi/ft to 0.52 psi/ft in adjacent carbonates. This gradient reached an abnormally high value at 0.95 psi/ft at the base of dolomitic formation, which then decreases at lower formation. Based on the true vertical depth of these high pressure sequences, this abnormal pressure gradient equates to around 140 pcf (18.7 ppg) mud weight. Having knowledge of this value is substantial for minimizing the number of kicks encountered in these zones.
Real Time Intelligent Alarm and Surveillance System in Heavy Oil Project- North Kuwait Illustrated Through Case Examples
Authors: Abdul-Aziz Bassam , Ghazi Albesairi , Ali Alrashoud , Abduallah Alajmi , Mubarak Al-Metlea , Fernando Ledesma , Assem Mohamed , Kareem Heshmat
Published: November 2017

Instrumentation of sucker-rod pumping systems in a large scale thermal pilot was an essential requirement for steam-injection projects. The manuscript focuses on the setup of a real-time smart alarming suite, and the benefits realized in terms of identifying surface and downhole equipment issues and wells requiring critical actions.

Two levels of alarms have been set after reviewing well performance with well-surveillance and field-development teams using real time data gathered through a SCADA system for each parameter for each well individually. The capability in the real-time smart alarming system to set both warning and critical alarm criteria for minimum and maximum values allowed deeper supervision of abnormal conditions, highlighting assets in need of preventive actions. The pre-configured controller alarms have been integrated with software smart alarms to be available in one screen in real time, to immediately take the necessary actions.

The alarm system identified wells with: Surface equipment problems related to load cell and position sensor issuesDown hole equipment issues related to standing and travelling leaksSurface network issues related to flow line pressure increases due to back pressure

The presence of such an alarm system prevented major issues that sucker rod pump systems typically experience in terms of high load exerted on the gearbox, high stress applied on rods/sinker bars, and forces applied on surface unit structure. The implementation of such a preventive approach reduced the amount of well trips and downtime, avoiding unwanted incidents, reducing the response action time and unnecessary workover costs

Setting limits for essential parameters that are being reviewed in a fixed period helped in identifying wells far from critical zones to be addressed as candidates for further investigation for production/asset optimization. The real-time intelligent alarming and smart notification system is considered the backbone for production optimization and asset management in the oil and gas industry.

Achieving such a level of effective surveillance/alarming allowed better asset management, prevented equipment failures, prolonged equipment life time, and reduced unnecessary costs. Successful deployment of the smart field approach in the North Large Scale Thermal Pilot for sucker rod lifted pumps helped in utilizing the performance of the equipment, increased oil production and assured smooth operational activities.
Formation Damage Assessment of High pH and Salinity Completion Fluids in Gas Wells
Authors: Al Moajil Abdullah , Khaldi Mohammed , Hamzaoui Bilel , Al-Rustum Abdullah , Al-Badairy Hameed
Published: November 2017

High pH saturated brine can cause formation damage to sandstone formation following well completion operations. Hence, it becomes vital to evaluate the potential effectiveness of completion fluids prior to the actual cost and risk of implementation. Permeability reduction of 12-31 % was observed after injection of high pH completion fluid on Berea sandstone core plug. The magnitude of damage depended on the fluid/rock properties. Scaling tendency of calcium sulfate and salt self-precipitation occured when it was mixed with formation water. Elemental concentrations of effluent samples indicated that ions exchange process occurred during coreflood testing. High pH completion fluid and the incompatability with formation water were the main cause of core damage. The damage was found to be reversible when the completion fluid's pH value reduced to 7 and at 300°F.
Experimental Investigation of Electrokinetic Assisted Hybrid Smartwater EOR in Carbonate Reservoirs
Authors: Yim Y. , Haroun M. R. , Al Kobaisi M. , Sarma H. K. , Gomes J. S. , Rahman M. M.
Published: November 2017

Smartwater flooding is a promising oil recovery technique, demonstrating positive results in many laboratory and field tests, by altering salinity and ionic composition of injection water. Injection of smartwater in carbonate reservoirs has gained interest due to its potential feasible application, taking advantage of improved oil recovery. Electrokinetic enhanced oil recovery (EK-EOR) is another rising technology that involves passing low D.C. current through the reservoir between a subsurface anode and cathode in the producing well. It has demonstrated a number of advantages including fluid viscosity reduction, permeability enhancement and reduced water cut. Our formulation aimed at advancing their combined mechanisms through a novel hybrid EOR. This study is the first attempt to present the experimental work on Smartwater Flooding integrated with the application of Electrokinetics (EK).

The effects of total salinity, reducing monovalent ions (Na+ and Cl-) and spiking of multivalent anions (SO42-) on the crude oil/brine/rock interaction were studied. Zeta potential tests were integrated with core flooding experiments systematically designed to identify the optimum ionic concentration and current density. Optimization of current density was essential for controlling both Cl2 gas generation and formation damage. EK showed positive effects with our designed Smartwater, when optimum currentdensity was induced, allowing earlier production and incremental displacement efficiency of 2.4-6%.
First Implementation of a Resilient and Self-Sealing Cementing System in the UAE: A Case History of Overcoming Engineering Challenges
Authors: Saeed Y. , Bottiglieri A. , Brandl A. , Han J. , Elatrache B.
Published: November 2017

Sustainable well integrity, for the life time of the well and long after abandonment, has always been a target for operators. However, unplanned stresses on the set-cement can cause severe damages to the cement sheath and may ultimately result in its failure. For that reason, a new generation of cementing system with optimized mechanical properties and self-sealing capabilities were designed.

The improved elastic constants and tensile strength value of the system make it more resistant to downhole stresses while the self-sealing feature provides an additional layer of assurance for long-term zonal isolation. The cement sheath’s ability to sustain stresses was confirmed using analytical and Finite Element Analysis (FEA) simulators. The mechanical properties and the expansion ratio were tested over several days, and the sealing ability was verified using a novel HPHT multi-function test cell simulating the well’s downhole conditions.

The system was successfully deployed in cementing a challenging gas-injector well with a dual hole size in the UAE. Novel fluid displacement software was used to assess effective laminar flow as the industry-recommended turbulent fluid flow was not achievable. The injector well is expected to be under an alternating pressure of 5,500 psi with two sets of perforations set 47 ft. apart. The cement placement operation was carried out successfully and a Cement Bond Log (CBL) run was conducted after 48 hours verifying good zonal isolation over the entire interval. An injectivity test was performed on the two perforated zones. No fluid communication was observed, eliminating the need for any cement remediation.

The successful implementation of the fit-for-purpose self-sealing resilient cement system from the slurry design and lab testing through the cement placement is described. Modelling simulation of the stress analysis, ECD and fluid displacement will be also shared. The review of this case history will provide useful lessons learned for successful cementing of critical wells.
IEC61850 Based Contingency Managed Load Shedding Solution at Gasco Ruwais
Authors: Sekar Shiva
Published: November 2017

This paper illustrates IEC61850 based contingency managed load shedding application implemented at Gasco Ruwais.

The load shedding system is enabled with Primary load shedding for the loads under 132kV switchgear and Overload Shedding based on the 33kV transformer feeder availability. For the primary load shedding the system monitors five digital inputs from generation plant. When any of the five digital inputs received, based on the priorities assigned to each digital input the loads will be shed. Each DI is considered for 20MW load to be shed. When the LS application receives the first digital input, the amount of load to be shed will be 20 MW based on the shed priority assigned. The sheddable load data namely the active power consumption, breaker feeder position and the breaker truck position are communicated to the LS application through IEC61850 and as hardwired from the respective IED. The over load shedding come in to play when one out of the three transformers is running in substation-11A and the overload LS application triggers the fast load shedding action further.

Each sheddable load will collect the respective input data of Power consumption, Feeder position and Shed priority into an array software structure. This structure is called Load Priority Table. Each Load will communicate the Load Priority Table to the master load shed controller, which will summate an Accumulated Load Priority Table from all loads in the plant. The LS will use the Accumulated Load Priority Table as a basis to evaluate the amount of load assigned to each priority and decide the required magnitude of shedding.