Storage tanks (Crude Oil/Oil water/Brackish water) in Kuwait oil Company are lined with fiberglass lining over the bottom plate for internal corrosion protection and to minimize the problem of exterior corrosion by providing enough strength to bridge small perforations. Storage tanks undergo major survey &maintenance activities on regular intervals and during maintenance period the fiberglass lining on tank bottom plate need to be removed to inspect and assess the condition of bottom plate. The removal of lining used to be carried out by manual method in which contract personnel enter the tank and remove the lining by continuous hammering, using hammer and chisel. Manual removal method has the difficulties like the activity takes longer duration (2-4 months), high number of workers (15-25) working inside the tank, health and safety issues like working in a difficult posture like crouch down low and doing hammering leading to fatigue, exposure to hammering noise, grit blasting dust and fibre glass dust affecting the health of the workers, probability of injury due to hammer blows and flying fibre glass chips. In addition, after the manual removal of lining we have to carry out grit blasting of the surface for inspection and many times the tank bottom surface was found having mechanical damages due to the hammer and chisel blows. Hydro jetting technology was introduced recently to remove the finer glass lining and found having many benefits like duration reduced to one third, reduced number of workers (3-4 personnel) required during execution (leading to considerable reduction in man hours), elimination of all the health/safety hazards as that of manual method, the tank surface was ready for inspection after the hydro jetting (unlike manual method where grit blasting was required after the lining removal) and no damages observed on tank bottom surface.

CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad. In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells. This paper describes the approach adopted in selecting the materials for Missan fields’ water injection system.

Internal corrosion is a leading cause of failure of pipelines that transport crude oil. The small amounts of saline water present in crude oil separates over a period due to any stagnancy or low flow conditions. The separated water causes water wetting of the pipe surface and creates corrosive condition along with the presence of carbon dioxide and hydrogen sulfide and bacteria, especially the sulfate reducing bacteria (SRB) and acid producing general anaerobic bacteria (GAnB) that thrive under the anaerobic conditions existing in pipelines. This is the major reason for pitting and leakages of pipelines. The On-line Corrosion Monitoring (OCM) using corrosion coupons provide early indication of internal corrosion taking place on the pipe wall. The chemical analysis of deposits removed from cleaning pigging provide qualitative information of general corrosion and its possible mechanism, while the microbiological analysis can indicate the involvement of bacteria in the internal corrosion. In-line Inspection (ILI) conducted on a cleaned pipeline measure pit depth on the internal pipe wall. This paper analyzes the data collected by each of these internal corrosion monitoring techniques and suggests a means for ranking the internal corrosion severity of crude pipelines of the Oil Field Operating Company, based on interpretation of the data. This ranking can help in optimizing the ILI activities by changing to a need-based program from the current schedule-based program.

The ever more challenging environments in which new wells are to be drilled, the uncertainties of the current market, and the availability of effective secondary and tertiary enhanced recovery (EOR) technologies, make the extension of existing wells' life more advisable than drilling new wells. To properly and proactively manage the degradation of Well Barrier Elements (WBEs) over time, thus ensuring the extension of wells life, a specific methodology and software have been developed. The concept of "Wells Life Extension" not only requires to get an adequate knowledge of the current wells integrity status, but also to predict future critical WBE(s) in order to put in place ad-hoc preventive measures. The methodology described in this paper includes three main phases: Well Integrity Assessment, which evaluates today's well integrity status through a risk-based approach. Estimation of Wells Ageing, which estimates the residual well life based on the understanding of WBEs ageing mechanisms. Definition of Intervention Plan Options, in which wells are classified on the basis of specific parameters, and then prioritized for future interventions through a cost-benefit analysis. The implementation of such methodology has allowed Customers to find out the most appropriate actions to be carried out on their ageing wells, with the objective of keeping production performances and safely operating the wells in line with the planned targets. Moreover, it has enabled to properly plan such actions over time, on the basis of the risk levels associated to the failure modes of each WBE, thus preventing and mitigating the need of potentially expensive interventions and protracted downtimes. Furthermore, emergency situations that would even increase costs and/or failures impacts, have been prevented, mitigated, and proper monitoring and maintenance programs have been executed in order to manage risks over time. In summary, the overall benefit of the presented methodology and software consists in anticipating well integrity issues and extending wells life through a proactive and cost-effective approach, that can enhance assets reliability, improve safety levels and minimize both downtimes and costs associated to WBEs failures.

Iron sulfide (FeS) deposition is a ubiquitous phenomenon in sour oil and gas wells, especially for these producing from high temperature and high pressure reservoirs. Hydrogen sulfide (H 2 S) gas is highly soluble in water and readily reacts with carbon steel and dissolved iron once in contact, which leads to the formation of FeS scale. The surface deposition or bulk precipitation of FeS scale is detrimental to flow assurance, such as flow restriction, pitting corrosion and stabilized emulsion. Compared to the conventional carbonate and sulphate scales, the mitigation of iron sulfide deposition is notoriously difficult. It is essential to understand its root causes in order to develop a suitable strategy to manage the problem effectively. By combining laboratorial tests and model simulations, new progresses have been made on the FeS root cause analysis for high temperature high H 2 S gas wells. The iron sources were determined over different stages of well life from drilling, completion, acidizing to production. Results from this study demonstrate that the iron contributed by the sour reservoir connate water is limited and is not the major cause to FeS deposition on downhole tubular in sour gas wells. Carbon steel corrosion during production stage is one source of FeS deposition. However, the rate of iron sulfide deposition during production is minor and far less than the deposit observed in the field. Other sources of iron sulfide deposition should be further investigated. Another major source is the iron released from tubing due to acid corrosion during acidizing stimulation, which potentially leads to severe formation damage and associated deposition problems in the production tubing and equipment. In addition, the iron contamination in the drilling fluid could contribute to FeS scaling problem. This paper presents a fundamental study to understand the sources of iron for FeS deposition in high H 2 S sour wells producing from carbonate reservoirs. Appropriate mitigation strategies are recommended accordingly.

The optimum development of the Deep Carbonate reservoirs in North Kuwait is key to achieve KOC's gas production targets. To optimize (future) production and accessibility of the various Flow Zones within the Target MT formation, KOC has selected a 4.5" mono-bore design to complete the North Kuwait Gas wells. To further improve understanding of production contribution from different flow zones and to enable selective stimulation and effective testing of flow zones, a trial was conducted in a new well to install a 4.5" 15K rated open-hole Multistage Completion (MSC). The well trajectory was designed with all directional work done before the reservoir section. The deviated reservoir section was drilled successfully to the planned TD. A three stage MSC with a long tail string (for future access to deeper reservoirs) was successfully installed. The bottom and middle stages were successfully stimulated and production tested. Stimulation and testing of the upper stage is planned for the future. To build on the success of this first trial another candidate well has been identified and a second 15K MSC system is expected to be installed in the second half of 2017. This paper describes the best practices and the learning in planning and installation of a first successful open-hole MSC in a High Pressure gas well in Kuwait, as well as recommendations for future MSC installations in deep high pressure gas wells with large variations in reservoir caracteristics.

The KS reservoir is a naturally fractured, deep, tight gas sandstone reservoir under high tectonic stress. Because the reservoir matrix is very tight, the natural fracture system is the main pathway for gas production. Meanwhile, stimulation is still required for most production wells to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Large depletion (and related stress change) was expected during the course of the production of the field. The dynamic response of the reservoir and related risks, such as reduction of fracture conductivity, fault reactivation, casing failure etc., would compromise the long-term productivity of the reservoir. To quantify the dynamic response of the reservoir and related risks, a 4D reservoir geomechanics simulation was conducted for KS reservoir by following an integrated workflow. The work started from systematical laboratory fracture conductivity tests performed with fractured cores to measure conductivity versus confining stress for both natural fractures and hydraulic fractures (with proppant placed in the fractures of the core samples). Natural fracture modeling was conducted to generate a discrete fracture network to delineate spacious distribution of the natural fracture system. In addition, hydraulic fracture modeling was conducted to delineate the geometry of hydraulic fracture system for the stimulated wells. Then, a 3D geomechanical model was constructed through integrating geological, petrophysical and geomechanical data, and both the discrete fracture network (DFN) and hydraulic fracture system were incorporated into the 3D geomechanical model. A 4D reservoir geomechanics simulation was conducted through coupling with a reservoir simulator to predict variation of stress and strain of rock matrix as well as natural fractures and hydraulic fractures during the field production. At each study well location, a near- wellbore model was extracted from the full-field model and casing and cement were installed to evaluate well integrity during production. The 4D reservoir geomechanics simulation revealed that there would be large reduction of conductivity for both natural fractures and hydraulic fractures, and some fractures with certain dip/dip azimuth will be reactivated during the course of the field production. The induced stress change will also compromise wellintegrity for those poorly cemented wellbores. The field development plan must consider all these risks to ensure sustainable long-term production. The paper presents a 4D coupled geomechanics simulation study applied to an HP/HT naturally fractured reservoir, which has rarely been published previously. The study adapted several new techniques to quantify the mechanical response of both natural fractures and hydraulic fractures, such as to use laboratory tests to measure stress sensitivity of natural fractures, integrating DFN and hydraulic fracture system into 4D geomechanics simulation, and evaluating well integrity on both the reservoir scale and the near-wellbore scale.

Developments in OCTG connections defining well integrity and mechanical performance of oilfield tubulars are not something newas a continuous feedback between field challenges and theinnovative nature of the Industry is something derivated into newer, more intensive Full Scale Testing procedures and novel analytic tools for connection performance evaluation in the last decades. The relationship between all those factors has been condensed in the present paper which gives shape to a comprehensive "technical history" for Premium Connections, hidden and scattered so far in issued patents, manufacturer manuals, brochures and selected field cases generated between 1935 and 2017. Design schools can be well defined by manufacturer and region;apart from this, theadvancements in testing and manufacturing made possible to adjust the connection to the technical constraints put fromthe field, namely a high need for gas tightness and enhanced torque capabilities. Last but not least, it was discovered that, among all oilfield equipment used during upstream operations, it was (next to advancements inSSSV's)the constant evolution of tubular connectiontechnologieswhat contributed to "crystallize" the modern concept of Well Integrity, especially after the big offshoredevelopments seen from 1971 on. As a corollary, the impact of current standardization protocols ISO 13679 / API 5C5 on well integrity in terms of metallic seal integrity will be assessed in the light of the tribological and mechanical evolution of the MTM seal during testing and validation.

A novel openhole packer system was developed and successfully field deployed following an extensive development and testing program. A gap within the industry was identified by two operators who determined that assured zonal isolation was a key requirement for future field developments. A design study was undertaken to determine possible sealing solutions. The intial concepts were adaptations of cased-hole technology that were confirmed to be inappropriate. A cup seal element system actuated by an innovative deployment system capable of handling variances in hole size and hole irregularities without excessively stressing the near well bore region was found to offer a robust sealing solution. A qualification program was developed and the packer has been field deployed successfully in a number of geographic locations.

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.

This paper endeavours to demystify, simplify and explain the reality of designing and applying compliant composite pipe repairs by presenting application case histories and field experience. The paper discusses the background in the development and the challenge faced by operators in applying the ISO standard to damaged pipework in the field and reviews the options for the pipeline engineer to overcome these difficulties through additional composite repair technologies. Composite pipe repair technology has been applied in the offshore oil and gas industry for many decades, the introduction of the ISO TS 24817 standard in 2006 offered pipeline engineers the possibility to prescribe pipe repairs using composite wrap systems compliant to the requirements of the ISO standard. The engineered composite repairs, qualified, designed and installed in accordance with ISO TS 24817, provide both external corrosion protection and structural strength to the pipework/pipeline. The paper will present the data by; discussing common misconceptions regarding composite pipe repairs and offering solutions to overcome the challenges on-site to meet the requirement for the application of compliant systems. Investigating the range and type of defects that are encountered, both through internal and external corrosive attack and reviewing the possible repair methodologies in cases where, due to the severe metal loss that has occurred and the degradation process, without additional repair techniques a compliant system could not be applied. In addition, commenting on different pipe geometries and configurations and their suitability for composite repairs. Further comment/discussion on the use of composite wrap systems for structural repairs on equipment other than pressure vessels will also be included.

Managing the anticipated internal erosion and corrosion in process vessels is a challenging task for the equipment designer and operator. This paper discusses a number of alternative solutions and focuses on the use of organic lining technologies, reviewing material acceptance and performance criteria, application techniques and control and addresses issues commonly faced by the designers, applicators and ultimately the asset owner.

Black Powder has identified as a significant problem in all areas of hydrocarbon production facilities and transit or export lines. The phrase ‘Black Powder’ in the oil industry used to describe a contaminant found from wellhead, Gathering Centers and gas export lines. The constituents of black powder are known to adversely affect the efficiency, integrity and reliability of oil and gas production, refining and transportation. Its combines of corrosion material such as Iron sulfide, Iron oxide, Wax, Asphaltene, silt and sands. Its vary from one location to another within the process of the oil and gas production. Its presence in all areas of upstream, midstream and downstream oil and gas production. It's affecting the flow assurance and quality of performance of the facilities from compressors, vessels, tanks, sensors and pipelines and finally impacting the refinery efficiency. Its major problem start to be present recently in oil industry which many different operators have different misunderstanding to overcome these phenomena of the black powder. The paper will be to look at best strategy and solution success to mitigate the problem of the black powder in Kuwait Oil Company from west Kuwait operation facilities to Refinery. It will highlight also roots cause, Impact and prevention plan. It will show how it help reduce gas flaring, minimization facility shutdown, reduce Flowlines leaks, and optimize chemicals consumption in operation facilities which lead to cost optimization.

Corrosion is defined as the gradual degradation of materials as a result of reaction with their environment, and corrosion inhibition is the systematic procedure of preventing or treating the effects of corrosion on metals. Due to the continued growth in hydrocarbon demand, operators in the oil and gas industry are always looking to drill deeper wells in order to access previously unattainable hydrocarbons. High-Pressure High-Temperature (HPHT) wells are now broadly present in places like the Gulf of Mexico, the North Sea, and the Middle East. These extreme conditions bring new challenges for corrosion inhibition. This paper is a review of corrosion encountered in the oil and gas industry, its cost and impact, the mechanisms/types of corrosion faced, and the current methods used to minimize, control, and monitor corrosion.

Systematic internal corrosion monitoring, fluid analysis and on-stream inspection of process vessels and associated piping in operating plants at appropriate locations can provide valuable insight into the corrosion status and fitness level of the equipment and components. At the Kuwait Oil Company (KOC), Internal Corrosion Monitoring activities and on stream inspection activities are carried out in all their facilities which consists of 22 Crude Processing Plants (or Gathering Centers), 4 Gas Processing Plants (or Booster Stations); 2 Effluent Water Disposal Plants, Seawater Treatment and Injection Plant, a vast network of pipelines carrying different products, as well as Early Production Facilities. Internal corrosion monitoring is conducted with online monitoring equipment that include corrosion coupons, corrosion probes, bio probes, hydrogen patch probes etc. installed at key locations. Fluid analyses activities are also carried out for different processes to determine various key parameters such as pH, conductivity, total dissolved solids (TDS), total hardness, dissolved oxygen content, hydrogen sulfide (H2S) and carbon dioxide (CO2) concentrations, corrosion and scale inhibitor residuals, Iron (Fe) content (total and dissolved), bacterial activity, etc.Corrosion data and fluid characteristics are analyzed for trends and appropriate recommendations issued to asset owners for corrective, preventive measures to mitigate corrosion and also to advise Inspection requirements based on findings. On stream inspection activities include visual inspection and non-destructive testing (NDT) inspections using ultrasonic scanning by Automated Ultra-sonic Test (AUT) method and thickness verification of susceptible portions of piping circuits, equipment and related components in the system. This paper highlights the significance of integrating the on line corrosion monitoring data and on stream inspection data resulting in proactive inspection intervention, repair and replacement of related piping and piping components in effluent water (EFW) system in one of the crude processing plant. Unscheduled plant shutdown and safety incidents were avoided due to proactive action. Further, it helped the company to initiate MOC process to implement proactive measures in similar piping systems at other facilities also.

Acid fracturing or matrix acidizing are often required for increased hydrocarbon production and long-term well deliverability from the massive gas Khuff carbonate reservoir in Saudi Arabia. Openhole multistage stimulation (OHMSS) technologies have demonstrated superior performance in maximizing reservoir contact and productivity through better distribution of acid across the formation matrix, full interval matrix contribution and efficient propagation of fracture networks to bypass formation damage and optimize near wellbore (NWB) conductivity. The Khuff structure is a late Permian age heterogeneous carbonate sequence that underlies the massive Ghawar field in Eastern Province of Saudi Arabia. The Khuff reservoir is subdivided into four separate intervals (A through D), with production coming mainly from the B and C intervals. Since its initial appraisal in the late 1970s, the majority of Khuff development activities have been focused in the relatively more prolific Khuff-C formation, where Coiled Tubing acid wash and single stage acid treatments were releatedly performed and evaluated. Multistage acid fracturing have been implemented in Saudi Arabia Khuff-C development in the last five years and results were carefully evaluated for each trial, based on which it is now the predominant Khuff-C stimulation technique. Up until the middle of 2011, the vast majority of Saudi Arabia's horizontal Khuff carbonate gas wells were drilled along the direction of maximum horizontal in situ stress (σ max ). This was primarily to enhance wellbore stability and achieve best possible penetration rates. Early multistage fracture treatments in the Khuff generated mostly longitudinal fractures propagating parallel to the wellbore, in the direction of σ max . Since then, a holistic approach toward the application of OHMSS technology for tight reservoir development was adopted. The complex workflow of this approach called, among other requirements, for changing the lateral section placement strategy and planning the horizontal section to be drilled along the minimum horizontal in situ stress direction (σ min ) as opposed to the previous mode of planning along the σ max . Accordingly, understanding the reservoir stress profile, orientation of the horizontal wellbore with respect to the dominant horizontal stress component and calibrating the stress profiles against actual openhole (OH) logs became the most important highlights of the new workflow. Radical improvement of stage integrity, multiple fracture signatures and enhanced well productivity were among the most important results achieved. Still, an innovative approach was required to address the more prolific Khuff-C formation where efficient matrix acidizing was sought as an alternative to acid fracturing in wells that could only be drilled in σ max direction. Therefore, a purpose-built OHMSS technology system that was developed around the idea of distributed limited entry for placement of matrix acidizing treatments was identified and carefully evaluated. This paper will present the details of the successful application of this new limited entry, multiple injection technology for optimized matrix acidizing of carbonate horizontal wells, including candidate selection, system design, functionality, operation and ultimate production profiling.

Well integrity is one of the critical concern during the life cycle of wells and impose an enormous challenge to the oil & gas industry. External and/or Internal corrosion of tubing & casing is one of the main reasons of leaks in the wells causing fluid movement from one annulus to other annulus. Complete understanding of the source of pressure communication between different annuli is of prime importance for designing an effective remedial action. Most leaks can worsen with time and therefore, locating and repairing a leak in its early stages is essential otherwise it may sometimes lead to abandonment of the well. Knowing the precise location of a leak prior to executing repair jobs will lead to better planning thus reducing downtime and repair costs. The problem becomes more complicated when the leak diagnosis has to be done using conventional logging techniques without pulling out the tubing string. Presence of competent barriers is a fundamental imperative of well integrity. Imperfect barriers introduce risks that need assessment and management. Few wells go through their operating life cycle without undergoing material degradation and component failures resulting in imperfect barriers. Therefore, use of contingent barriers is necessary to minimize the likelihood of such failures and the resultant impact. This paper describes different types of through tubing logging techniques used by Kuwait Oil Company for identifying tubing-casing leak in an oil well and discusses the interpretation of the results. The paper also discusses the probable reasons for occurrence of the leak, remedial actions taken to arrest the leak and future completion philosophy to avoid such failures in the new wells.

The control of microbiological fouling in industrial cooling water for ‘open-recirculating’ and ‘once-through’ systems is important for reducing corrosion as well as increasing process efficiency and equipment longevity. Microbial biofilms insulate well and cause significant loss of heat transfer efficiency. In addition, they promote ‘under-deposit corrosion’ by multiple microbial induced corrosion (MIC) mechanisms. Furthermore, in ‘once-through’ seawater-cooled water systems where there is potential for colonization by various species, mussels create additional problems. Historically, microbiological growth is controlled through a continuous chlorine feed, either as gaseous chlorine or sodium hypochlorite form. Gaseous chlorine has been largely eliminated because of safety concerns involving handling. Sodium hypochlorite is frequently used, but has significant problems involving storage, onsite generation and its usage in high concentrations leading to corrosion. In addition, recent environmental regulations limit the amount of these oxidants and their reaction by-products, such as tri-halomethanes, which can be discharged into waterways. Chlorine dioxide an alternative that is a highly effective and safe microbiological control program. It is superior in offers a performance to all other chemistries with none of the environmental disadvantages. It is capable of maintaining excellent control of microbiological growth in cooling water systems and hence removing potential for MIC. This paper discusses how chlorine dioxide is generated, highlights its effectiveness against microbiological bacteria and presents the results of applications under various operating conditions, including those encountered in the Middle East. The author recognizes SPE copyright