ACG technology

bp as operator of the ACG contract, sees itself as a technology-based company. The ACG developments are underpinned by this expertise and while it has been an investment that builds on tradition, it has also been ahead of its time in technology, transferring industry’s cutting-edge innovations transfer to the Caspian region.

Many of bp’s own new technologies have been successfully applied to ACG’s development operations and projects in Azerbaijan, some of them for the first time in the Caspian.

• Extended reach drilling (ERD) enables well targets to be located a considerable distance from the platform thereby increasing recovery. The longest ERD well we have drilled so far is 6.4km from the Chirag platform. We believe that this technology will allow us to maximise recovery from ACG for decades to come.
• High-angle (near horizontal) drilling technology, which provides the opportunity to complete wells with a longer length and lower formation thickness thereby increasing production rates.
• bp Well Advisor ensures safe, reliable and efficient well operations by using real-time information. Its integrated consoles enable to detect early warning indicators of potential well construction issues, enhancing operational decisions with real-time well surveillance, boosting drilling efficiency, reducing non-productive time. bp Well Advisor was introduced to the Caspian in 2012 when its casing running console became fully operational on all three Azeri platforms and Deepwater Gunashli.
• bp leads the way in what is known as 4D seismic acquisition. In January 2024, we launched a new 4-dimensional (4D) high-definition ocean bottom node seismic programme on the ACG field. This is the largest-ever seismic acquisition commitment made by bp globally by all its aspects – area size, cost and programme duration. The new programme, which focuses on ACG’s Balakhany and Fasila reservoirs, covers an area of 740 square kilometres under source and 507 square kilometres under receivers, has a total cost of around $370 million, and a duration of five years (2024-2028). The most up-to-date 4D technology used for this programme will allow us to acquire further in-depth data about the reservoir helping us identify ways to minimize future well surprises and maximize the field recovery in the next decades.
• bp sees Azerbaijan as a major centre of technology expertise in well completions. Completion technology such as open hole gravel packed screens and large diameter tubulars equipped with the fibre-optic allows higher production rates while controlling the amount of sand being produced. Various sand-face completion types like Cased and Perforated (C&P), Stand-alone Screens (SAS), Expandable Sand Screens (ESS), Pre-packed and Open Hole Gravel Packed Screens were installed and piloted at early days of ACG life, before transferring to other bp regions. Today in ACG the standard completion design for producing wells is the Open Hole Gravel Pack (OHGP). This was a real breakthrough in the early 2000s, and we still find it effective today. Historically wells were packed with natural proppant while recently non-radioactive tracer proppant has been used. Over the years the OHGP completion technology has undergone significant enhancements.  bp’s Azerbaijan business has also looked at potential application of gravel pack completion in cased hole during the up-hole recompletion. The Cased Hole Gravel Packed completion was successfully installed in East Azeri D06 producer in 2017.
  

A number of new subsurface technologies deployed at the completion stage changed the way in which the ACG field was developed in the direction of better wells and reservoir performance and lower intervention costs providing invaluable real-time surveillance data across the field.

• Distributed Temperature Sensing (DTS). The first fiber-optical cable was installed in an ACG producer well in 2004. Restricted wellhead access, high rate, and differential depletion of the different reservoir intervals limited conventional production logging possibilities, etc. justified the decision made on installation of permanent DTS fiber-optical cables in wells for monitoring wells and field surveillance. As of today, ACG has a fleet of more than 60 wells with active, continuous monitoring at reservoir section, making it the largest field deployment of permanent monitoring technology not only within bp but globally. Moreover, in 2023, bp successfully installed the first-in-industry Dual Clad fiber optic cable in the ACG field, enabling simultaneous acquisition and monitoring DTS and Distributed Acoustic Sensing (DAS) data.
• Distributed Acoustic Sensing (DAS). Over the past five years the DAS technology has been extensively used for sand and well integrity monitoring, as well as seismic acquisition. This has led to safer and more efficient well operations, ensuring integrity and potentially enhancing the quality of seismic data in areas where conventional seismic quality could be improved, particularly across the crestal area of the field. bp pioneered and continues the studies of many algorithms and tests in ACG, attempting to unlock more value of DAS in well and field-scale deployments.
• In-Well Seismic - vertical resolution of surface seismic data suffers from energy loss due to the distance of travel from the source to the reservoir and then back to the surface deployed recording devices. Placing recording instrumentation within the wellbore to record 'one-way' energy improves this. If a permanent fibre is employed within a well, this activity could happen many times thus providing a high resolution 4D image around the wellbore which could monitor fluid movement on a finer scale than surface seismic or detect minor compaction effects in the reservoir. The fiber-optical cable permanently installed in some of ACG wells will be used for repeat 4D acquisition in the future.
• Downhole Flow Control Valve (DHFC).
  1. The world's first subsea water injectors, completed with the expandable sand screens and downhole flow control valve were put online on Deepwater Gunashli in 2008. These completion technologies 

•  The world's first 3-zone water injector with the DHFC equipped with DTS came online in 2018. This has marked another big milestone for this game-changer technology in ACG to properly manage multi-layer reservoirs and opened for further applications in other bp regions.

bp also focuses on delivering technology solutions to mitigate and manage potential risks identified for each element of the production system. These may be technologies that would allow to avoid (or reduce) sand production into a well, or new tools or remediate hydrates in well facility:

• bp Slug Controller - wellbore slugging in ACG wells is a major risk to production sustainability. High amplitude of slugging and high rates of change in drawdown put wells at potential risk of sand control failure. It also brings risk for serious process plant upsets and efficiency losses. This technology, which helps to control the slug situation, is deployed at all ACG platforms.
•  Drawdown Controller - instability and exceeding the bean up limit when the well is put back on production after shut-down may lead to sand production due to the sand prone nature of ACG wells. The technology allows to maintain the downhole pressure at the depletion target value by applying constant drawdown to the well. It also enables more efficient and smoother bean-up in the well.
• APEX Production Simulation, Monitoring and Optimization tool - enhances well production optimization capability to address base management optimization challenge.
• Pipeline inspection gauge (PIG) is a special tool used to inspect the internal conditions of a pipeline, capture and record the geometry and reveal any corrosion information related to pipelines. This information is then downloaded to a computer when the PIG is removed from the pipe to enable engineers to 'see' inside the line. This process is known as intelligent pigging.
• To ensure the integrity of subsea pipelines, rigorous monitoring is done by using remotely operated vehicles and autonomous underwater vehicles (AUV). The challenge we face is poor visibility in the murky Caspian waters, particularly in water depths of less than 25m. So, we have introduced some state-of-the-art equipment never utilised in the Caspian before to provide pipeline assurance. It carries out acoustic surveys, it works well and it allows inspections to be performed faster and more efficiently. The Caspian became one of the leading regions in the application of AUV technology, sharing valuable expertise with bp operations globally.
  
• Some new technological tools such as Crawler and Drone have been successfully deployed for facility and structure inspection on some of ACG platforms. Further development of these technologies is being assessed to expand the area of their application to all of ACG platforms.
  
• The Azeri Central East platform - the seventh oil producing platform installed on the giant ACG field in the Caspian Sea - is technologically and digitally the most advanced bp-operated platform in the world. 
  1. ACE has a remote-control concept - this offshore platform is controlled from the onshore control room at the Sangachal terminal.
  2. ACE is the first bp platform that was started up remotely.
  3. The platform is connected to the Sangachal terminal through a fibre optic cable, which is backed up by Line-of-Sight (LoS) communications to the Central Azeri platform. This step significantly enhances safety by reducing PoB and proves the effectiveness of the remote-control concept. Additionally, ACE has a Crisis and Incident Command facility (CIC) with full ICSS functionality allowing the platform to be controlled offshore in the event of communication loss.
  4. The platform utilises technology to automate labour intensive processes such as well diverter valves and chemical injection packages. Utilising technology to automate these tasks frees up operator time and increases efficiency.
  5. ACE platform has a digital twin which combines documents, data and 3D model / imagery of both the topsides and the drilling rig. This provides the operations team with a quick and easy access to up-to-date documents and data. This, coupled with the laser scan images, reduces the need for offshore visits for completing site surveys.

During the design, construction and commissioning of the ACE platform, reducing emissions was top of mind. New techniques to do so included:

• Installing a single, gas-fired generator. Instead of relying on a second or even third generator, back-up power is supplied through a connection to the offshore grid via the nearby the East Azeri platform.
• Using thermal imaging cameras throughout the platform to help quickly detect leaks and seeps should they occur. 
• Blowdown testing, which is usually completed offshore with hydrocarbons, was done onshore ahead of start-up with nitrogen -  a first for bp and could be rolled out to other projects in the future.