Pressure build-up in the annuli of oil and gas wells could be an indication of a well integrity problem, in particular if determined to be sustained. In order to implement an effective remediation strategy for sustained annuli pressure, the source(s) of annuli fluids need to be determined so that the root cause of the problem can be identified and effectively mitigated. This paper describes an approach developed to attempt to identify the possible sources of hydrocarbon fluids observed in some annuli of gas condensate wells located in Field A. During the initial phase of the investigation, it was not possible to determine the source of annuli hydrocarbon fluids from routine compositional analysis alone because the outer casing strings of the wells intersect multiple hydrocarbon bearing reservoirs and aquifers whose fluids have non-unique compositions. A multidisciplinary approach was therefore adopted that incorporated all of the available data and non-routine fluid analyses. A detailed fluid sampling and analysis program was also conducted to better understand and characterize the possible sources of the observed hydrocarbons in each well's annuli. In one case study, interpretation of routine fluid compositional data indicated that non-hydrocarbon and hydrocarbon gas composition data alone did not provide a clear indication of the source of intermediate and surface casing fluids. Detailed geochemical analysis was therefore required to gain a better understanding of the annuli fluid source. In another case study, comparing the gas composition of the annuli fluid to the gas composition of a produced fluid allowed for the indication of the source of annuli fluid. In both cases, the compositional signature of the annuli source fluids was found to be sensitive to contamination as a result of changes in the pressure and temperature conditions in the annuli and through mixing with aqueous annuli drilling or completion fluids. However, more comprehensive geochemical screening that included molecular geochemistry and isotope analysis was shown to help in understanding the processes controlling the fluid composition and in reducing the uncertainties associated with the derived interpretation based on routine fluid compositional analysis alone. Conclusions from this work have now been incorporated into the annuli pressure management guidelines and in planning of future drilling and completion activities.

The North Field Barzan Development was executed with focus on identifying and implementing effective completion solutions that addressed new technical challenges and operational constraints presented by the wells of this project. The primary challenges were in areas of matrix stimulation, spent acid clean-up, and production testing. Stimulation issues included implementing designs for a wide range of permeability contrasts, addressing stimulation vessel pump rate and acid capacity limitations, managing live acid corrosion due to sour environment, and assessing effectiveness without production logs. Spent acid clean-up operations required protecting downhole safety valves and achieving fluids composition criteria required for production into carbon steel pipelines. Production testing challenges included fluids modelling and equipment solutions that decreased Safety, Health and Environment (SHE) risk and operational complexity, while allowing accurate measurement of gas and liquids flow rates and obtaining required fluid samples. The solutions included improvements to the acid stimulation system chemical diverter and corrosion inhibition package, custom design and manufacture of a subsurface safety valve protection sleeve, adoption of well clean-up criteria tailored to pipeline and facilities requirements, evaluation of multi-phase flow meter and real time fluids analysis technologies, and development of a simplified multi-phase flow rate calculation algorithm based on choke manifold and fluids composition data. Implementation of differentiating technologies enabled cost savings and SHE benefits due to reduced flaring, execution of single stage stimulations, smaller test equipment layout, and innovative flow rate calculation techniques. Stimulation designs were demonstrated as successful based on interpreted changes in zonal flow contributions derived from minimum surface fluid compositional data. Wells were completed and ready for handover, meeting all requirements for the surface production facilities. Introduction Demand for energy in Qatar will grow over the next decade as major initiatives are completed in the transport, health and education sectors, and as new facilities are built for the FIFA World Cup in 2022. The Barzan Development is planned to meet the increased gas demand and is one of the most significant projects undertaken by the State of Qatar. Several offshore development wells were drilled and completed with a design life of at least 25 years and capacity to produce in excess of 1.0 billion standard cubic feet per day to supply two gas treatment trains. The wells are located on three unmanned wellhead platforms in the North Field, about 80 kilometres offshore Qatar (Figure 1), and are completed in Khuff Zones 1–3 carbonate reservoirs. One well at each platform is designated a 'data well' and was extensively tested to evaluate reservoir and fluids properties.

This paper describes the development and deployment of a customised, on-line well integrity management system that has resulted in a major improvement in the effective and timely identification, diagnosis and remediation of well integrity issues in RasGas operations.The system, which was built in-house on a web portal, is a business-driven, interactive and collaborative solution that integrates well integrity surveillance data (annuli surveys, integrity tests, corrosion log results, etc.) with maintenance schedules, and provides timely reporting of potential or observed integrity problems and harvesting of historical well data. This enables RasGas engineers and operations personnel to make informed and timely decisions on well integrity to ensure continued safe operation and a high level of well reliability and availability.Key features of the system include effective visualisation of safety-critical elements and operating parameters from the field, effective tracking of integrity testing and preventive maintenance activities, use of Љsurveillance-by-exceptionЉ principle under which the system sends out a notification to all key personnel if any integrity-critical parameter on any well falls outside pre-established limits. The paper will illustrate the effectiveness of the system with actual field examples. Planned enhancements such as incorporating well failure models and individual well risk rating system will also be described.While there are a number of packaged well integrity management tools available in the market, the uniqueness of RasGas system lies in its in-house development which has resulted in seamless integration with the existing data telemetry and processing workflows, flexibility in incorporating customised solutions and ease of scalability to accommodate increasing well count. The paper describes the key factors that contributed to the successful development and deployment of the system, including buy-in from all stakeholders, continuous feedback from field personnel and timely familiarisation and training of the end users.

Current technologies for assessing corrosion damage in downhole tubing and casing strings have several limitations. Under certain conditions, mechanical, electromagnetic and ultrasonic tools can be run inside a downhole tubing string to quantify corrosion and wall loss in that string. But these tools, at best, may only be able to qualitatively assess the condition of tubing strings which are in contact or close proximity to the tool. In wells that develop communication between the production/injection tubing and casing and allow ingress of potentially corrosive fluids into the annulus, the ability to effectively assess the condition of the production casing is important. This knowledge can drive critical decisions around well operating limits, surveillance programmes, workovers, or abandonment operations. This paper describes the results of corrosion modelling and testing conducted on carbon steel to understand the extent of internal corrosion damage expected on a production casing string when sour gas enters the tubing-casing annulus through a leak source. A wide range of conditions including various hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) concentrations were modelled using proprietary corrosion modelling software. Laboratory tests on corrosion coupons were also performed and compared to the model results.Key findings around the expected corrosion potential of production casing exposed to sour gas include:• Corrosion rates are generally low over a wide range of H 2 S concentrations. The presence of H 2 S reduces the general corrosion rate by forming a protective iron sulfide (FeS) scale. • Corrosion rates are sensitive to the chemical composition of the water in the annulus. Higher bicarbonates levels significantly reduce corrosion rates. • General corrosion rates in a sweet gas environment with CO 2 can be very high because of the discontinuous nature of iron carbonate scale formed at test conditions. This case study demonstrates how corrosion modelling can be used with laboratory testing to provide reliable insight about the condition of tubulars which cannot be directly measured.

This paper discusses an approach used to assess liquid film erosion/corrosion effects in the tubing strings of sour, high-rate, wet gas producers. This was done as an alternative to API RP 14E, which utilises an empirical erosional velocity factor "C" to estimate maximum velocity limits to minimise the potential for tubing metal loss from erosional effects.Many RasGas wells are completed with a full L-80 carbon steel or a combination L-80/Corrosion Resistant Alloy (CRA) production string. Once on production, a thin iron sulfide scale develops on the tubing wall significantly retarding the rate of metal loss due to internal corrosion. However, shear stresses generated from the condensate/water film flowing along the tubing wall could potentially remove this protective iron sulfide coating and expose fresh metal to much higher corrosion rates. This paper describes the approach adopted to assess the magnitude of shear stress created across a range of flow conditions including well production rates, fluid properties, and completion sizes using transient 1D flow simulation and more detailed 3D computational fluid dynamics modelling. The results will be used to design future laboratory experiments to assess the effect of these stresses on the integrity and effectiveness of the iron sulfide scale in reducing corrosion rates.