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Well tie-in is an activity that requires careful measurement and fabrication methods. One of the most critical spools in onshore well tie-in is the riser connecting the wing valve in the X-mas tree to the choke valve. This piping section is regularly constructed of carbon steel and rated for high temperatures and high pressures, making it expensive and difficult to manufacture. The process of measurement and fabrication can only be initiated after the rig installs the X-mas tree in order to obtain as-built measurements. In order to optimize well tie-in, Saudi Aramco installed its first two non-metallic flexible onshore risers in two oil producers.
The non-metallic flexible onshore riser is a thermoplastic composite pipe (TCP) manufactured from carbon fiber and Polyether Ether Ketone (PEEK). This construction enables it to be lightweight, strong, and able to accommodate high levels of bending strain (flexible). This TCP can be manufactured to sustain pressures of up to 15,000 psi, temperatures of up to 248 °F, and corrosion resistance to seawater, H2S and CO2. This paper describes in detail the TPC onshore riser technology design, installation and performance evaluation process.
TCP can mitigate elevation/orientation changes of wing valves and consequently accelerate tie-in procedures. The installations of these non-metallic risers were performed in under five hours each. This optimization allows for cost and time savings, as well as releasing locked potential.
This paper provides a case study of the first installations of non-metallic flexible onshore risers for well tiein in Saudi Arabia. By comparing the conventional method of installing carbon steel sections with TCP, the reader will be able to benefit from the technology benefits analysis, lessons learned, and future applications of this technology.
A conventional tie-in procedure for an onshore well producer is completed with a carbon steel gooseneck. Typically, the activities regarding the gooseneck are measuring (which can only be done after installation of the wellhead - once the rig leaves the drillsite), fabrication, coating, and installation, which can be a prolonged process. Also, during workover or well intervention, the wellhead may be re-installed at a different angle or height, which will deem the existing rigid spool unusable.
In production operations, a lot of effort has been devoted to monitoring well head and flow line parameters. Connecting sensors to monitoring systems, collating, and transmitting the data off site for manual or automated review requires infrastructure build out and processes developing to analyze and action the data, consuming additional resources. The concept of edge computing, moving the analysis and decision closer to the well is a challenging problem which requires the addition of controlling elements. The objective is not just to monitor the conditions, but also to take action based upon the observations without unnecessary intervention.
This paper introduces a new method of closed loop production control, integrating production tree master valve, emergency shut down system and choke management into a single automated, autonomous system. By implementing microprocessor control at the wellsite, basic management functions can be automated with sequencing to mitigate risk of procedural errors, improve well integrity, and minimize downtime. The key elements of such a system comprise of master valve actuation, wing valve actuation and production choke actuation linked by a single co-dependent system that can perform condition based monitoring and self-diagnose system issues.
A discussion of the design and function of the method, with due regard to limitations, best practices and workflows will be demonstrated, providing an examination of the results of design experiments. The potential for further implementation is examined as well as highlighting operational differences vs current technology that deliver value to producers and operators.
Expanding the capability of wellsite autonomous control to address operational concerns and reduce operational costs is within the reach of technology that is integrated into monitoring systems, moving the decision point closer to the well. With a proven ability to monitor and action analyses, communicating the results of the action for operational status updates substantially reduces the need for large bandwidth infrastructure and in the right applications, increased well and equipment uptime without risk of costly integrity issues. This enables autonomous systems to be deployed in more remote areas, allowing the same level of assurance in control afforded to more infrastructure rich environments.
It is inevitable that during a wells life cycle there will be failures or degradation that introduce risk. By applying process safety principles, there are three questions that an operator should ask themselves: Do we understand what could go wrong? What systems remain to prevent this happening? Are we getting the right information to assure us that these systems are working effectively?
Do we understand what could go wrong?
What systems remain to prevent this happening?
Are we getting the right information to assure us that these systems are working effectively?
In terms of well integrity management, questions one and two are dealt with in major accident hazard reviews, leading to well designs that ensure there are adequate barriers between the hazards in the well and the environment.
Question three is managed by the verification and assurance of the identified barriers and systems that are aligned with corporate or industry performance standards.
This paper suggests a fourth question:
4. Is risk communicated to the relevant people to ensure effective decisions are made, and that the risk is understood and mitigated?
Traditionally, a well failure model approach can be used to optimise the risk assessment process with recommended response times to repair specific failures. However, it does not account for the whole asset and the overall level of risk is posed to the installation. Further, the scoring methodology needs to be understood by a specialist and aligned with the corporate risk matrix used by asset managers.
This paper describes how software systems can be leveraged to provide effective communication in the organisations "language of risk" and helps to visualise the accumulation of risk from wells that are aligned with the corporate matrix. This small step change vastly improves the understanding and communication of well integrity risk throughout the organisation enabling installation management early challenge, better resource utilisation and the monitoring of creeping accumulative change.
Scale precipitation is a common phenomenon that can be seen in a large number of oil fields worldwide. The presence of scaling is due to many reasons,including: temperature change, pressure drop, release of CO2 or the mixture of incompatible waters. Usually, scaling comes in a mixture of different scales, such as calcium carbonate (CaCO3), barium sulfate (BaSO4), and calcium sulfate (CaSO4). Scaling has a great impact on the production regimes where it sometimes ultimately decreases the well productivity to less than half of its potential. The presence of scaling can cause blockages in perforations, restrict/block flowlines or sometimes the failure of safety and choke valves.
Precipitation of calcium carbonate on surface or subsurface equipment creates operational problems and acts as a blockage agent. In this case study, water incompatibility caused the first scale formation in the flowlines where a pressure maintenance mechanismvia peripheral injection in this field is being utilized. It was predicted from the well performance data as it showed more than 50% of the production loss. The lab results revealed that the major element was calcium with minor amounts of strontium and barium.
This paper presents the results of both experimental and field work performed to identify scale formation. In addition, well performance data was used to predict future scale formation in parallel with the water geochemical analysis. The method used to remove scale precipitation is to use inhibited HCl acid mixture and it is required to be used either though squeeze treatments or by continuous treatments at the wellhead. Based on the lab and field studies, this paper will show new workflow for potential scale prediction and remedy actions prior to laboratory and well performance analyses.
Electrical submersible Pumps (ESPs) have been employed for decades in accelerating oil production and creating pressure head needed to produce sub hydrostatic wells. ESPs are installed downhole and comprise stages of impellers driven by electrical motors that are automatically cooled by the passing fluid.
A major disadvantage of ESPs is blocking access to well re-entry for surveillance and through-tubing intervention. One of such cases is during acid stimulation. In Petroleum Development Oman (PDO), acid jobs have been carried out as part of workovers to retrieve the pumps first. The cost implication can be tremendous ranging from $250,000 to $400,000.
Two deployment techniques were adopted in PDO recently by bullheading acid through ESP and Coiled Tubing (CT) into the reservoir and by so doing, saved 80-93% of comparative cost. The techniques involved the use of abrasive resistant ESP for vertical wells and ESP bypass (Y-Tool) for CT deployment in horizontal wells. The challenges of using these techniques include damaging the ESP with acid or mistakenly circulating acid via the tubing-casing annulus. We have been able to apply these techniques successfully in acidizing a sub hydrostatic carbonate reservoir. In one example, new vertical well was stimulated to enhance matrix withdrawal from 20m3/d (120bbl/d) to 128/d (790bbl/d) dry oil and in another example, a new horizontal well which was severely damaged by high viscous pill was stimulated via CT. These have opened new opportunity for matrix well withdrawal in this reservoir.
This paper presents examples of candidate selection, cost justification, pump selection and acid recipe. It also illustrates the innovative deployment techniques used to prevent pump & tubular damage as well as achieving proper acid placement into the reservoir. These examples can be treated as best practice worth replicating in all ESP applications worldwide.
For more than 30 years, AL-Khafji Joint Operations (KJO) has used experience, Knowledge and commitment to produce and process oil in safe manner. Today we continue the commitment in the ongoing wellhead safety system improvements.
Although, the oil well wellheads are secured and protected from any possibility of fire or accident, KJO intends to adopt further safety applications to meet up and fulfill the latest wellhead safety standards in oil industry.
Therefore, KJO has made an intensive development program to comply with API standards and give more protection on wellhead safety system, which can be achieved by:
Replacing the old type of SSSV with new hydraulic tubing retrievable one.
Replacing the old pneumatic SSV with new compact hydraulic type and control panel and re-locating the SSV from its current position down-stream the wing valve into the X-tree and up-stream the master valve.
Integrating the SSV with the SSSV using control panel.
Converting annular fluid flow to tubing fluid flow.
Meeting the wellhead safety standards and more, is the KJO objective and operation drive.
This paper discusses the development and operational experience of the Snorre Through Flow Line (TFL) system. Included is a review of the TFL system development, installation, qualification and commissioning. Practical experiences, TFL operation and the development of a TFL logging tool are also discussed. Continuity and enthusiasm of personnel have resulted in a high quality, well qualified TFL system, enabling a wide range of operations to be performed.