bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Decade of Self-Sealing Cement Technology Application to Ensure Long-term Well Integrity
Authors: Shadravan Arash , Amani Mahmood 
Published: October 2015

Abstract
Recent studies have shown that more than 50% of wells that are 15 years old or older have at least one casing string with sustained casing pressure. Cement sheath failure will result in sustained casing pressure, cross flow, lost production, collapsed casing, contaminated water zones and increased workover costs. Today, US federal regulation do not allow wells with sustained annular pressure to be plugged and abandoned. Remediation in these cases is both difficult and expensive. Therefore, utilizing a cement formulation which repairs itself in case of any failure under downhole conditions would be ideal for ensuring long-term well integrity and preventing the occurrence of sustained casing pressure. The objective of this paper is to review the self-sealing cement technology presented in the literature. This study manifests the latest novel laboratory equipment which allowed the cement to cure, get cracked and then seal under downhole conditions. The hydrophilic essence of this material provides a durable cement sheath to help ensure well integrity and zonal isolation for the life of the well. Mechanical properties testing could demonstrat the improved tensile to compressive strength ratio, lower Young's modules and higher Poisson's ratio. In addition, self sealing cement could self seal multiple times and therefore deliver a durable cement sheath in a wide variety of field cases.
Behavior Based Safety Efforts in KOC and its Relevance to Oil & Gas Industry
Authors: Ramakrishnan G. K. 
Published: October 2015

Abstract
The paper begins with highlighting the limitations of traditional safety management efforts and importance of addressing human factors. Paper will then focus on human factors that lead workers to behave unsafely and then explain the psychology and rationale behind the BBS Approach and how it helps addressing human factors. It will highlight merits of BBS Approach to Safety (Proactive vs. reactive), which uses top down leadership and bottom up engagement to close the ‘behavior gap’.
Then, the paper will start with a brief overview of BBS Efforts in KOC in Phase 1 and 2 with DuPont (Preparatory) and Phase 3 "On the Job" BBS implementation through Coaching & Mentoring with Quality Safety Edge. Then, it will explain the (a) Rational behind Phase 3 BBS Implementation Approach and give (b) An Overview of BBS Implementation Process (Observations & feedback on critical behaviors-Area team data review & action planning-Steering Committee review & action planning-Recognition & celebrations). It will also highlight the Role played by BBS/HSE Videos in success of BBS Implementation.
Facility-Specific Observation Check List developed based on at-risk behaviors that caused incidents will be presented, followed by presenting of Safety Survey Questionnaire developed for Safety Surveys and Observation Check Lists developed for measuring the level of compliance with select HSE Procedures (Permit to Work, Job Safety Analysis, Emergency Response and Driving) and explain how HSE Behavioral Indicators are calculated.
Then the paper will highlight the improvements achieved in KOC Facilities through BBS implementation by contrasting Post-BBS Implementation Statistics vis-a-vis Pre-BBS Implementation Statistics in respect of Safety Survey Findings, Level of compliance with select HSE Procedures (PTW, JSA, ER and Driving) and HSE Behavioral Indicators on KOC Overall basis.
Changing behaviors is a long drawn process requiring consistent efforts. Yet KOC has achieved significant improvements as Post-BBS Implementation surveys & statistics reveal.
KOC has gained immense firsthand experience in implementing BBS in Middle Eastern Culture, highly resistant to change. The paper shares KOC's experience, not only what all we did right, but also what/where all we could have done better.. As human behavior is a persistent common issue, such sharing will be of immense practical value to Oil & Gas companies, operating in Middle East or any other part of the world.
Exceptional Management and Optimization for Intelligently Controlled Wells using Smart Surveillance and Diagnostics in Joint Operations - Wafra Field
Authors: Babahani B.. , Spain John , Bhat M. S. , Heshmat K.. , Assem A.. , Mohammed Z.. 
Published: October 2015

Abstract
Instrumentation on around 900 artificial-lift system (ALS) wells in the Wafra field allowed remote monitoring, control, and analysis for exceptional management. Having software capable of controlling wells, gathering real-time data, and integration with any database, created another level of effective surveillance. Using real-time optimization simulation software, helped in identifying opportunities, selecting candidates, tracking well behavior, reducing action response duration, reducing number of failures, and saving power cost. This manuscript focuses on the optimization implementation and results verification.
The field development team is divided by reservoir type wherein each engineer is responsible for a set of wells. The wells are artificially lifted using different types of pumps including sucker rod pumps' (SRP), electrical submersible pumps (ESP) and progressive cavity pumps (PCP). The manual process of collecting data is progressively becoming replaced by high tech well instrumentation, which is connected to a private network cloud reaching engineer's desktops. This process has created a collaborative environment consisting of different teams such as asset management and operations engaged in production optimization utilizing the smart software modules. The changes to the well are tracked and diagnosed instantly.
Deploying the digital oil field allowed engineers to instantly access well data which has improved the management process of identifying well issues based on pre-configured and intelligent alarms. It has created short- and long-term plans for production optimization taking into consideration the health and performance of wells and equipment installed in the field. The aim has been to reach and maintain the optimal rate for each well.
Case studies conducted include: – Candidate wells for chemical injection based on measuring the difference in flow line pressure from temperature change – Unbalanced rod pump wells identified based on the comparison between the measured and calculated counter balance torque – Wells with gas interference were highlighted based on continuous dynacard collection – Wells with motor overload were diagnosed based on real-time data comparison between the nominal and actual output current – Production increase opportunities were identified based on the diagnostics report and analysis report created from the software optimization module
Smart field optimization has been implemented for the first time in the instrumented artificially lifted wells in a partitioned neutral zone between Kuwait and Saudi Arabia, whereby the data is being accessed from admin camp, which is an office area outside the field. It has enhanced the collaborative environment between the different teams working in a joint venture allowing engineers to be focused on solving well problems instead of data collection and validation procedures.
Flare Gas Recovery Using Innovative Unconventional Technology, Avoiding the use of Compressors
Authors: Peeran Syed M , Beg N.. 
Published: October 2015

Abstract
Legislation, the environment, economic and corporate social responsibility are some of the key factors that are governing the recovery of flared gas worldwide. There is growing awareness of the issues associated with flaring and efforts are being made globally by operators and governments to minimise it. There are several technologies for reducing flaring at source or in a processing plant. The choice of technology depends on the economics of the project, frequency of flaring, infrastructure available and location of the producing facility. This paper covers innovative Flare Gas Recovery Systems using Surface jet Pumps and avoiding the use of compressors.
Conventional Flare gas Recovery systems usually comprise of one or more compressors, which compress the collected flare gas and route it for further processing. The compressor design is critical and determines the system's capacity and turndown capability. However compressor based solutions can be quite large, complex and have high capital and operating costs. They are also very sensitive to changes in gas composition and MW.
Surface jet pumps (SJPs) are simple, low cost passive devices that can also be used to recover flare gas. They use a high pressure (HP) fluid as the motive force to boost the pressure of the LP or LLP flare gas and deliver it for processing. The high pressure fluid that is needed as the source of energy or motive flow is usually gas taken from the discharge of a compressor or from the export gas line. However HP liquids, such as oil or injection water can also be used. Advantages of using SJPs include low cost, no moving parts, zero maintenance, zero power or fuel gas usage, small footprint and varying layout configurations. SJPs are well suited to liquid ingestion and to changes in process conditions (without affecting performance).
This paper discusses the use of Surface Jet Pumps as an alternative to compressors for flare gas recovery and cites several case studies of where this technology has been successfully utilised. The design and operational criteria of SJPs, as well as the economics is also highlighted.
Increase in Sand Production Used as an Indication for the Next Steam Injection Period in Heavy Oil Wells
Authors: Quttainah R , Al Besari Ghazi , Mehmood F , Hossam Mesbah , Dange A 
Published: October 2015

Abstract
In rod pump applications around the world heavy oil and sand production is believed to be a dangerous combination. This paper highlights a case study of a heavy oil well in the North Kuwait field where sand production was monitored closely to avoid flow line choke and down hole failures. This case study was used as a pilot for the neighboring wells producing from the same reservoir. In case of wells producing heavy oil with considerable sand production and that undergo cyclic steam stimulation the challenge is often at the end of the production cycle. While the oil is thin and has good viscosity the sand settles itself at the bottom. However, with time as the oil gets colder and thereby heavier, it carries the sand along with it to the surface causing plug in the flow line. This is due to the high viscosity of the oil. This is believed to be the end of production period beyond which it would have been impossible to produce any further even after sand cleanup. Certain operational procedures were established to ensure the integrity of the down-hole equipment and to avoid the failures. It has been observed that by effective sand monitoring it was possible to determine the next injection cycle with more precision. This standardized the injection and production cycle. The flow line choke up problems were completely eliminated as the production period would cease as soon as some sand would begin to appear at the surface. It was possible to establish API gravity cutoff for oil production thus avoiding rod and pump failures. This implementation has been undertaken for the entire field and has shown significant operational efficiency. A pilot was conducted to justify the use of sand production as an indication for the next production cycle for heavy oil well under cyclic steam stimulation.
Field Scale Gas Injection Efficiency Optimization Based On Combined Analysis of Finite Difference and Streamline Simulation
Authors: Algdamsi Hossein Ali , Amtereg A. A. , Agnia A.. 
Published: October 2015

Abstract
Within the framework of reservoir management streamline simulation finds one of its typical applications as one of the effective tool to improve gasflood and pressure maintance performance. Streamlines provide an instantaneous visualization of flow patterns as a function of reservoir heterogeneity. Additionally they also provide an estimation of the well allocation factors (WAFs) between injection and producing wells. Such information is a default outcome from streamline models but not from finite difference simulation and it is particularly useful in optimizing and balancing well patterns and field scale injection rates. However finite difference simulation has the advantage of implicitly taking into account all the details of an existing simulation model, especially advanced well management strategy. In this paper we demonstrate a straightforward workflow for optimizing injection rate based on a comprehensive analysis of two key parameters: injector efficiency (IE) metric and WAFs. The optimization approach consists of a three step procedure starting with streamline analysis using commercial software which combines the power of finite difference simulators and streamline technology to derive streamlines from the flux field generated by the finite difference simulation that represent a snapshot of the flow pattern within the reservoir, well drainage region information and fluid allocation changes with the flood progression. Second using a simple analytical calculation to compute weighting factors for injection/production rate targets from a derived ranking of the wells (IE). Finally reallocation of injected fluid volumes from low-efficiency to high-efficiency injectors improves volumetric displacement and sweep efficiency in the less swept areas of the reservoir. The application of this workflow is demonstrated with a real-field example of an onshore tight sandstone reservoir where the pattern balancing has led to incremental production of 3.5 % over the 5 year forecast in which the IE average of the field is the benchmark for whether more or less injection volumes were required while obeying facility constraints.
Successful First Application of Flow-Channel Hydraulic Fracturing Technology in Kuwait Accelerates Development of Marginal Reservoirs
Authors: Anthony E.. , Al-mosaileekh S. R. , Al-Othman M.. , Alhouti N. B. , Abdel-Basset M.. , Mokhtar A.. , Sheikh B.. 
Published: October 2015

AbstractIn a high-perm/strong-aquifer environment, comparatively low-perm/heavy-oil/solution-gas-drive reservoirs inevitably get sidelined. Flow-Channel Hydraulic Fracturing, however, with infinite conductive channels for fluid flow rather than intra-granular flow, as in conventional fracturing techniques, offers a tangible solution for increased productivity. The channels in the proppant pack are created through a patented technique that combines special pumping protocol, perforation scheme, fracturing fluid design and fiber technology. These conductive channels accelerate fracture cleanup, and achieve longer effective fracture half-lengths, thereby enhancing productivity, injectivity& recovery.In North Kuwait, 90% of wells drilled are vertical, penetrating a wide range of reservoir types consisting of high and low permeability sandstones and carbonates, with varying crude types from medium heavy to condensate. Flow-Channel Hydraulic Fracturing technology, with its infinite conductive flow-channels and reduced risk of premature screen-outs, was selected as the optimum stimulation technology for the most challenging low-permeability/low API gravity candidates where conventional stimulation techniques are not providing the aimed results. Conventional propped hydro-frac treatments were attempted previously with marginal benefit and operational failures. This was the first application of this technology in Kuwait.Multi-disciplinary candidate screening and selection for the initial pilot wells, followed by pre-job logistics and operational planning with the service provider, resulted in a flawless execution with text-book results.Post-job production results showed a stabilized flow rates with more than 85% production gain compared to the flow rates expected from conventional completion techniques. Incremental production paid out stimulation expenses in 35 days.This very successful introduction for Flow-Channel Fracturing application opened up opportunities in low API reservoirs where even the flow through the proppant pack from conventional fracture stimulations is limited. Injectors associated with IOR & EOR projects, and Carbonate completions traditionally responding to repeated periodic acid fracture stimulation, may require only single channel proppant fracture during their life cycle.
PCP Redesign and Analysis Involving Pump Watcher System
Authors: Quttainah R. B. , Mahmood F.. , Bhat M.. , Mantilla O.. , Imbrea R.. 
Published: October 2015

Abstract
Progressive cavity pumps (PCP) were introduced in Kuwait Oil Company (KOC) fields for the first time in year 2012 whereby 100 wells were to be awarded for a period of 5 years. Over a 3 year period over 50 pump installations were carried out. Due to the growth of the project the operations strategy focused on implementation of certain tools to aid in analysis and optimization of the wells thus improving the run life. Pump Watcher system is a part of a lease contract that involves PCP rental developed by KOC. The contract warrants remote surveillance and control of the pump including but not limited to start/stop and speed change. Although the PCP rental began in the year 2012, real-time monitoring and control was accomplished only in 2014 as the infrastructure related to radio communication was not in place. There has been a paradigm shift in data availability and quality before and after the installation of pumps, variable speed drives (VSDs), and remote monitoring and survey. This manuscript focuses on the benefits achieved ever since downhole gauge data and related pump information was made available on a real-time basis. The manuscript focuses on the following with case studies and examples:
Improved run life Wells working under recommended operational conditions Preventative actions due to real-time data (RTD)
Selection of Suitable Viscosity Reducer to Facilitate Test Production of Heavy Oil and Deep Reservoir
Authors: Ghloum Ebtisam , Rashed Abeer , Al-Jasmi Ahmad , Al-Ali Abdulmuhsen , Mali Prasanna , Sanyal Arunava 
Published: October 2015

AbstractExploitation of heavy oil from deep reservoir is often dictated by appropriate selection of viscosity reducer and artificial lift. For the proposed pilot in this study, it is necessary to identify suitable viscosity reducer to produce heavy oil from deep reservoirs, with down-hole electrical submersible pump (ESP). Broad field data of this reservoir are depth of 9300 feet, crude API gravity of 10 and crude viscosity of 10000 centipoise, at 4500 psi of SBHP and at 190 °F of BHT.The main objective of this study is to evaluate different viscosity reducer chemicals (VRC) for their efficiency in reducing the viscosity under severe reservoir conditionsSARA analysis was carried out on flashed crude oil sample to check the asphaltene stability of samples. Series of viscosity tests were conducted using an electro-magnetic viscometer in order to test performance of different viscosity reducers at diverse temperatures and pressures conditions.Experimental studies showed that as pressure decreases, viscosity of oil sample decreases with reduction in temperature. However, when the effect of different viscosity reducers on representative oil sample was studied, at 5000 psi and at reservoir temperature of 190 °F, it was noticed that reduction in viscosity of oil sample from 16,230 centipoise to less than 850 centipoise could be achieved.It is concluded from lab studies that reduction of viscosity of given heavy oil sample can be achieved with the help of suitable viscosity reducer to an extent, wherein, it is possible to operate downhole ESP and produce heavy oil from deep reservoir. Studies can also have practical application as an alternative planned production strategy to exploit such reservoirs. Study results definitely have far reaching influence to decide optimum dosage of viscosity reducer during execution. These studies can be seen as a representative model for performance comparison to test different viscosity reducers under diverse conditions. Studies also emphasized the need for carrying out meaningful lab studies for appropriate selection of viscosity reducers; while planning exploitation of heavy oil and deep reservoirs.
CCS: Experiences in Project Development
Authors: Gray Lily , Maas Wilfried 
Published: October 2015

Abstract
The development of a CO2 value chain for CCS poses a number of decisions relating to the capture technology, storage selection and transportation of CO2. In addition, an appropriate approach to the non-technical aspects and risks needs to be incorporated. This paper will provide an overview of the different options available to projects and discuss the selections that Shell has made in its own CCS project development.
Shell has developed a global portfolio of CCS demonstration projects driven by the recognition that carbon capture and storage is currently the only technology available to mitigate emissions from large scale fossil fuel use. Shell’s projects cover a wide range of technologies and consist of targeted applications that are of relevance to the wider oil and gas industry. The Shell portfolio includes Peterhead, Quest, Technology Centre Mongstad and Gorgon. The development of these projects has demonstrated that there are multiple drivers in the development of a CO2 value chain and these can be very project specific.
In the development of CCS for power plants, one of the key considerations is the ability of power plants to be able to respond flexibly to the normal fluctuating demands of the power market. Therefore, a key driver in technology selection is to limit the impact that the addition of a CCS plant could have on this flexibility. On the other hand, availability may not be the most important factor, because power plants usually use an "end of pipe" CO2 solution, and therefore the unavailability of a post-combustion CCS plant will have minimal technical impact on the power export.
However, for a hydrogen plant where hydrogen demand can be relatively stable e.g. in a refinery, then the capture technology selected will not usually need to follow a varying demand but, because the capture technology could be part of the wider process, it may need to offer high reliability and availability.
Similar considerations need to be made about the dehydration technology and the CO2 compression technology selected. For example, re-use of existing facilities can result in more stringent requirements on CO2 purity and possible pressure limitations that could be designed out in a new facility.
In conclusion, Shell';s experience has shown that development of CCS projects poses some new challenges but through good integration of technology and a structured approach to technical and non-technical risks, these can be overcome for successful project delivery.