Well Control and Temperature Modelling Facilitates the Effective Delivery of Challenging Shallow Water HPHT Exploration Well

A geopressure interpretation technique known as the seismic velocity method is a common workflow in which shale compaction functions are characterized at offset control wells, matched to interval seismic velocities, and then used to predictively calculate geopressure away from well control. The seismic velocity method is used to interpret the expected geopressure profile at the Deep Blue subsalt exploration well in Green Canyon 723 in the deep water Gulf of Mexico. The Deep Blue prospect is distinct from other prospects in the play fairway in that the prospective section is overlain by a salt withdrawal minibasin, whereas the offsetting fields are positioned either along the flanks of minibasins or under a thick allochthonous salt canopy. Predrill geopressure interpretations using numerous tomographic imaging velocity data sets shows a large degree of consistency with the magnitude of geopressure encountered in offsetting supra salt and subsalt fields. Results from the Deep Blue 1 exploration well indicate the predrill geopressure interpretation from interval seismic velocities failed to anticipate the extreme degree overpressure encountered in the subsalt section of the well due to poor deep velocity resolution and an “unloaded” compaction signature. The magnitude of overpressure in the primary section is attributed to the emplacement of an unconformable halokinetic sequence over the primary subsalt basin. An interpretive paradigm is described in which the Deep Blue pressure cell is created through two halokinetic episodes: (1) rapid progradation of a salt canopy followed by (2) subsequent salt withdrawal and emplacement of an overlying minibasin. The linkage between halokinetic sequences, burial history, and the development of overpressure can be used to predictively characterize subsalt geopressure environments.

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Successful Wellbore Pressure Management Using Intelligent MPD and Continuous Circulation System on an HPHT Well in Vietnam

10.2118/205600-ms ◽

2021 ◽

Author(s):

Bao Ta Quoc ◽

Harpreet Kaur Dalgit Singh ◽

Tuan Nguyen Le Quang ◽

Dien Nguyen Van ◽

Essam Sammat

Keyword(s):

Detection System ◽

Lessons Learned ◽

Circulation System ◽

Well Control ◽

Fracture Pressure ◽

High Pressure High Temperature ◽

Managed Pressure Drilling ◽

Increased Risk ◽

Wellbore Pressure ◽

Exploration Well

Abstract A managed pressure drilling (MPD) and early influx detection system is gaining worldwide acceptance as an enabling technology for drilling wells with challenges that can lead to tremendous nonproductive time (NPT), significant unplanned costs, and increased risk exposure. MPD counteracts the high cost of these wells by delivering significant savings when eliminating fluid losses or well control events that cause NPT. MPD technology has proven that is used to not only reduce NPT but also enable access to reserves previously considered un-drillable. In this case history, MPD helped to reach reserves that could not be reached in the first well. Client planned to drill the well A, which is its second offshore exploration well. Early on in 2019, the campaign encountered significant problems because of high temperatures and a narrow pore-pressure/fracture-pressure (PP/FP) gradient window. Additionally, using conventional drilling methods in offset wells led to problems relating to kicks, loss scenarios, and stuck pipe. Before drilling the second exploration well, the relevant parties considered that the first well-presented multiple drilling issues, and they drew from past success. The latter job had ended with reaching all the well targets despite high-pressure/high-temperature (HP/HT) conditions using a continuous circulating device in conjunction with an MPD system. Therefore, this combination of technologies was chosen to drill the well A. The operator used the MPD system, from the start when drilling the 14 3/4-in × 16-in. hole section to the end when drilling the 8 1/2-in. hole section, in offshore Vietnam. Applying MPD technology on this well resulted in many benefits, including the main benefit of always controlling the bottomhole pressure through the challenging zones. MPD also helped to maintain the equivalent circulating destiny (ECD) and equivalent static density (ESD) during drilling, connections, and a logging operation to mitigate the risk of any gas breaking out at the surface and to drill the well to the desired target depth. This paper focuses on using MPD technology in conjunction with the continuous circulation system, in offshore Vietnam. It goes into detail by describing the experience and providing some of the lessons learned.

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Development of the Global Equipment Inventory and Network for Subsea Well Response

International Oil Spill Conference Proceedings ◽

10.7901/2169-3358-2021.1.1141381 ◽

2021 ◽

Vol 2021 (1) ◽

Author(s):

Neil A Munro ◽

Andy R Myers

Keyword(s):

Shallow Water ◽

Source Control ◽

Mutual Aid ◽

Gas Industry ◽

Well Control ◽

Remote Areas ◽

Response Network ◽

Industry Collaboration ◽

Control Event ◽

Drilling Operations

ABSTRACT 1141381 The Montara (2009) and Macondo (2010) incidents resulted in step change in safety for the oil & gas industry. Since then many improvements have been implemented to keep the highest standard of safety in drilling operations. Through industry collaboration subsea well response equipment not available at the time of these incidents is now globally accessible. Technology continues to be developed to provide comprehensive response capabilities. A recent area of focus for industry was how to cap an incident well in water depths less than 600 meters where vertical access may not be possible due to hydrocarbons at surface and a possible gas boil in the case of a gas well. An innovative concept was developed, manufactured and tested to deal with a loss of well control event in shallow water. The Offset Installation System (OIS) allows a capping stack to be deployed and installed on a blowing out well in shallow water, deployed and controlled by vessels offset from the incident well. In addition, the OIS can be used for debris clearance, removal of the lower marine riser package (LMRP), and deployment of other subsea response hardware. By virtue of their source control operational function capping stacks are relatively large and heavy pieces of hardware. Despite these physical characteristics, there is expectation by stakeholders and international regulators for capability to transport capping stack equipment across significant distances in an expeditious manner to respond to an incident. For remote areas of the globe, capping stacks air transported as a single unit could provide an effective solution. A key objective in responding to a subsea loss of well control event is the ability to effectively mobilise source control equipment and trained personnel to readily manage an emergency response scenario in a timely manner globally. A number of companies with a range of capabilities will be required to provide a comprehensive response. To further assist, initiatives focused on personnel resources have been developed including a global subsea response network, and continuing industry collaboration for mutual aid of personnel. This paper will provide information on the development of the global subsea response equipment inventory available to industry. Latest developments such as OIS and air freightable capping stacks for transportation to remote areas will be discussed in detail as well as the above-mentioned initiatives for personnel.

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Dual Gradient Drilling Will Control Shallow Hazards in Deepwater Environments

Volume 7: Offshore Geotechnics; Petroleum Technology ◽

10.1115/omae2009-79790 ◽

2009 ◽

Cited By ~ 1

Author(s):

Brandee A. Elieff ◽

Jerome J. Schubert

Keyword(s):

Shallow Water ◽

Closed System ◽

Drilling Fluid ◽

Detection Methods ◽

Methane Hydrates ◽

Shallow Gas ◽

Well Control ◽

Water Flows ◽

Shallow Water Flows ◽

Dual Gradient

Currently the “Pump and Dump” method employed by Exploration and Production (E&P) companies in deepwater is simply not enough to control increasingly dangerous and unpredictable shallow hazards. “Pump and Dump” requires a heavy dependence on accurate seismic data to avoid shallow gas zones; the kick detection methods are slow and unreliable, which results in a need for visual kick detection; and it does not offer dynamic well control methods of managing shallow hazards such as methane hydrates, shallow gas and shallow water flows. These negative aspects of “Pump and Dump” are in addition to the environmental impact, high drilling fluid (mud) costs and limited mud options. Dual gradient technology offers a closed system, which improves drilling most simply because the mud within the system is recycled. The amount of required mud is reduced, the variety of acceptable mud types is increased and chemical additives to the mud become an option. This closed system also offers more accurate and faster kick detection methods in addition to those that are already used in the “Pump and Dump” method. It has the potential to prevent the formation of hydrates by adding hydrate inhibitors to the drilling mud. And more significantly, this system successfully controls dissociating methane hydrates, over pressured shallow gas zones and shallow water flows. Dual gradient technology improves deepwater drilling operations by removing fluid constraints and offering proactive well control over dissociating hydrates, shallow water flows and over pressured shallow gas zones. There are several clear advantages for dual gradient technology: economic, technical and significantly improved safety, which is achieved through superior well control.

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