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Well X is an infill horizontal well designed for the Gulf of Thailand. It is challenging due to the following factors - A long 8 ½ inch open hole section, An extended reach section at horizontal or near horizontal, the presence of loss circulation zones, an Extended Reach Drilling (ERD) ratio of 2.725 and a Drilling Difficulty Index (DDI) of 6.762. The key challenge was to successfully deploy the 7 inch casing across 12,350 ftMD of open hole, with potential loss circulation zones. In spite of these difficulties, the 7 inch casing was successfully landed with the use of an Ultra-High Speed Rotational Reamer Shoe. Historically, losses of circulation have posed significant challenges to well delivery in the Gulf of Thailand wells. In Well X, this is further complicated by a long open-hole section with a step-out of over 10,000 ftMD. It was determined that the successful deployment of the 7 inch casing would require some degree of agitation at the nose, and such a device must be tolerant to the Lost Circulation Materials (LCM) type and the composition of the drilling fluid and the cement. An ultra-high speed rotational reamer shoe was specially configured to meet the LCM requirements in the displaced fluid, for use in deploying the casing. While deploying the 7 inch casing, losses of up to 20 bbls/hr occurred from 7,043 ftMD while running at 15 joints/hr. A loss circulation recipe comprising of 60 bbls of 30 ppb Tiger LCM was mixed and successfully displaced through the customized ultra-high speed reamer shoe to cure losses. The casing was washed down from 10,569 to 11,610 ftMD, filling casing each stand. The 7 inch casing was successfully landed at the target depth of 12,353 feet and subsequently cemented. Drill out operations took 1.5 hours to complete. A formation integrity test (FIT) showed good shoe strength which was later confirmed by the cement evaluation logs. The comprehensive Ultra-High Speed Reamer Shoe was configured with a minimum restriction of 15mm, which is 5 times the diameter of the maximum particle size in the LCM of 3 mm. The tool was designed to tolerate the prescribed loss circulation materials, making it possible to cure the losses while running the casing string. The innovative Ultra-High Speed Reamer Shoe has demonstrated its usefulness by providing a higher probability for successfully deploying the 7 inch production casing over the extended reach section of Well X. The application of this technology can mitigate against non-productive time such as wiper trips or excessive washing down or casing rotation. It has proven to be a reliable technology that can be used in the industry in challenging well designs.

Effective zonal isolation in wellbores with a challenging mud removal environment is well known to be very difficult to achieve. In wells at the technical limits of Non- Aqueous Fluid (NAF) removal prior to cement placement, cement bond quality and hydraulic isolation can be compromised by leaving channels behind the casing, which can result in several long-term well integrity issues. An Interactive Cementing System (ICS) is developed through special experimental methodologies to mitigate mud channeling issues and improve zonal isolation, by immediately interacting with any residual mud channels left in the well after cement is in place, hence reducing the permeability of mud channels and sealing off microannulus gaps. Casing centralization is considered to have the greatest influence on mud removal efficiency because it directly affects the flow movement on each side of the wellbore. Mud removal has been studied from numerical simulations, laboratory experiments, and field results, and these show that good mud removal can be achieved only when adequate casing standoff is achieved during cementation. In modern wells where there are many operational restrictions and limitations, especially in highly deviated and horizontal wellbores, final cement designs may not allow good casing standoff and thus not all of the best practices for effective mud removal can be applied. The objective of the innovative cement system is to have a design that interacts with residual mud in the annulus to "fix" the channels, thereby enhancing cement bond quality and zonal isolation. Two detailed case histories of the application of this technology in the development campaign showed visible improvement in cement bond logs using the ultrasonic imaging tool as compared to offset well that was cemented using a conventional cement system. After two successful implementations, the ICS was selected as the cement system of choice for wells with challenging mud removal.

The Jasmine oil field, in the Gulf of Thailand, has several pools of unconsolidated sandstone reservoirs. Multi-zone completion is usually deployed in these reservoirs, however, sand control in this completion type could be a challenge. Several sand control techniques were evaluated and the most promising strategy was found to be chemical sand consolidation treatment. In the design phase, the most critical challenge was to determine the optimal and safe chemical recipe and placement technique. A single chemical recipe optimized for all of the reservoirs was achieved, yielding an unconfined compressive strength (UCS) of at least 500 psi while retaining a permeability of 40%. Bullheading was selected as the placement technique. To minimize contamination of the chemical with annulus fluid, we designed to shorten the distance between the packers of each completion zone. Cut-to-release packers were used instead of pull-to-release packers to mitigate the concern of unwittingly unsettling the packers. A risk assessment was conducted to cover all aspects of the job. High risk activity like pumping flammable fluids at high pressure was specifically singled out and special mitigation was put in place to ensure a safe execution of the activity. Some other mitigations such as minimizing nearby hot surface areas, real-time monitoring of oxygen levels, and purging the mixing system with CO2 were also considered. This paper provides a case study for chemical sand consolidation treatment from the view of an oil company and covers the full lifecycle of the application from concept selection to the finalized procedure, taking into account both technical and operational considerations. This research contributes to the public body of knowledge within the oil and gas industry with regards to an emerging technique for sand consolidation.

We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.