678 Challenges of Well Completion Design & Operation Solutions for Deep Gas Well with Multiple Producing Zone in Mildly Overpressured Reservoirs at Offshore Malaysia

Based on the production data from first development campaign in 2017, contamination reading of CO2 and H2S from gas production wells were observed increasing from 3% to 10% and from 3ppm to 16ppm respectively within one year production. These findings have triggered the revisit in 2019 development campaign optimization strategy in terms of material selection, number of wells, reservoir targets, and completion design. Thus, tubing material was upgraded to HP1-13CR for the upper part of tubing up to 10,000 ft-MDDF (feet measure depth drilling rig floor) to avoid SSC risk due to the geostatic undisturbed temperature is less than 80 deg C, however the material of deeper tubing remains as 13CR-L80 as per 2017 campaign. Moreover, the mercury content from first campaign was observed to be above threshold limit from intermediate reservoir based on mercury mapping exercise done in August 2018.As the mercury removal system is not incorporated in the surface facilities, the mercury reading from the well in the 2019 campaign need a close monitoring during well testing so that appropriate action can be taken in case the recorded contaminant reading is high. Dedicated zonal sampling plan to be performed if the commingle zone (total) mercury reading was recorded to be above the threshold limit, and that zones will be shut off to preserve the surface facilities. Opportunity was grabbed to optimize number of wells by completing both shallow and intermediate sections in a single selective completion to maximize the project value. However, this combination will lead to major challenges during operation due to the huge difference in reservoir pressure and permeability contrast in each perforated reservoir as the required overbalanced pressure of completion brine for shallow reservoir is much lesser than the requirement for the mildly overpressure intermediate reservoir. Thus, a potential risk of severe losses and well control is present at shallow reservoir. To mitigate this risk, loss circulation material was pre-spotted in the TCP (Tubing conveyed perforation) BHA prior to fire the gun to allow for self-curing process should losses take place. During the first development campaign, the completion tubing was running in hole in two stages. The lower completion was deployed via drill pipe and the perforated zones was secured with fluid loss device located between lower completion tubing and gravel pack packer. The upper completion tubing was then deployed and tied back to the lower completion packer. This approach was applied as mitigation to prevent fluid losses and to ensure the tubing can be safely deployed to the intended final depth. However, based on the actual performance and losses rate data during the first campaign, the completion design in second campaign was optimized and deployed in single stage. Since shallow and intermediate reservoir were combined in multiple production zones where five SSD (Sliding Side Door) were installed, the slickline option to set packer was waived due to the risk of setting tubing plug in deep wells. Pump out plug was considered as an option but then dropped due to high hydrostatic pressure. The packer setting pressure was too close to plug shear pressure. Therefore, a self-disappearing plug was utilized as it did not require any slickline intervention and can be ruptured by pressure cycle. With this option, risk of pre-mature rupture of plug was eliminated. The paper will discuss in detail each challenge mentioned above together with details calculation that was performed throughout evaluation and selection processes prior best solution being selected as these optimizations resulted in nearly three days saving of rig time, contributing to 2.6% of well cost reduction and the required number of wells were optimized to be three instead of four wells. Moreover, a safer production life of wells by selecting a suitable tubing material and eliminating the risk of mercury production above the above threshold limit.

Shallow Gas Reservoir Development in Offshore Field, Myanmar: Tapping New Reserves with Novel Approach

Discovered on the shallowest formation in Myanmar offshore field at 500 meters subsea, this reservoir is perhaps one of the most challenging reservoirs to develop in many aspects such as; risk of fracking to seabed when performing sand control completion, cap rock integrity and risk of breaching due to completion and production activities, reservoir compaction, and depletion-induced subsidence. Generally, the producing reservoirs currently developed in this field sits between 700 to 2500 meter subsea, mTVDss. Cased Hole Gravel Pack (CHGP) as sand control completion method is selected to develop the reservoir from 700 to 1650 mTVDss. None of the shallow reservoirs (shallower than 700 mTVDss approximately) has been developed in the field before, due to some technical challenges previously mentioned. Owing to these reasons, reservoir engineer and well completion team initiated feasibility study focusing on advanced Geomechanical modeling and alternative way of sand control completion combined with full project risk assessment, ultimately, to unlock huge gas reserves trapped in this field. The reservoir is finally developed with infill well and new completion technique ever been used in the company. To develop this shallow reservoir, infill well drilling with sand control completion is required. The technical analysis on the following problems was comprehensively performed to ensure that the reservoir was feasible, doable and viable to develop. Reservoir compaction and subsidence occurring with stress and pressure changes associated with depletions would not create potential hazard to production facilities. Cap-rock is stable with no breaching over entire life of reservoir depletion. No potential fault is reactivated upon depletion. Sand control completion is able to be performed safely with well-confined fracpack (risk of frac growth to seabed). Upon depletion, integrity of casing and cement is acceptable when reservoir is compacted. Full risk assessment aspects of completion operation are scrutinized. These problems were mainly analyzed using coupled 3D Geomechanical model focusing on this shallow reservoir in the area of this particular wellhead platform. Briefly speaking, the 3D Geomechanical model was coupled with reservoir pressure depletion to find stress and displacement of reservoir rock and casing due to production. The methodology is called one-way coupled modeling. To be more precise, the pre-production stress of the reservoir at initial pressure was determined and used to calculate subsequent stress change from depletion (production). Pressure depletion will increase effective stress and hence create deformation of reservoir rock which may induce underground subsidence and casing integrity. On this study, four stress-steps of pressure depletion were computed i.e. initial pressure, 25% depletion, 50% depletion and 75% depletion. On each step, stress equilibrium was simulated using finite element software. This project makes the pending development of shallow reservoir in this field doable and viable. All risks associated with well completion and production-induced depletion were deliberately reviewed and mitigated. Based on this study, the most critical risk is gas leak through seabed due to sand control completion activity (CHGP). Apart from this, the other risks such as seabed subsidence, cap-rock breaching, fault reactivation, and casing integrity upon compaction were consciously addressed, reviewed and prevented. The major risk on sand control completion was finally mitigated. The conventional extension pack was avoided and replaced with the completion technique, a so-called circulating pack. Circulating Pack is one of CHGP technique where the pumping rate and pumping pressure maintained below fracture extension rate and fracture extension pressure. This pumping rate and pumping pressure will not introduce the fracture in the formation but still able to carry proppants and place them in the annular between screen and casing to provide sand control means. Although the sand control performance of circulating pack is not up to High Rate Water Pack (HRWP) or Extension Pack, together with control of minimum drawdown and production rate will enhance the sand control performance and prolong production life. Ultimately, unlock the potential in this shallow reservoir. The well has finally been successfully completed under tailor-made design and real-time data acquisition. The reservoir has been producing successfully with the rate of about 5 MMSCFD with good flowing wellhead pressure at 590 psi similar to the design. Ultimately, this alternative approach enables the development of this shallow reservoir where the new reserves of 20 BSCF has been added to the project. This project can be a good lesson for future development of other shallow reservoirs worldwide.

Caldera resurgence during the 2018 eruption of Sierra Negra volcano, Galápagos Islands

Recent large basaltic eruptions began after only minor surface uplift and seismicity, and resulted in caldera subsidence. In contrast, some eruptions at Galápagos Island volcanoes are preceded by prolonged, large amplitude uplift and elevated seismicity. These systems also display long-term intra-caldera uplift, or resurgence. However, a scarcity of observations has obscured the mechanisms underpinning such behaviour. Here we combine a unique multiparametric dataset to show how the 2018 eruption of Sierra Negra contributed to caldera resurgence. Magma supply to a shallow reservoir drove 6.5 m of pre-eruptive uplift and seismicity over thirteen years, including an Mw5.4 earthquake that triggered the eruption. Although co-eruptive magma withdrawal resulted in 8.5 m of subsidence, net uplift of the inner-caldera on a trapdoor fault resulted in 1.5 m of permanent resurgence. These observations reveal the importance of intra-caldera faulting in affecting resurgence, and the mechanisms of eruption in the absence of well-developed rift systems.

Surface Casing Perforation, A Promising and Reliable Solution for Producing Marginal Reserves of Shallow Reservoir Layer in Shallow Gas Prone Tunu Field

In these difficult economic conditions, oil companies might accept higher challenges and risks to grasp only marginal gains. A new frontier in production methods to answer the challenge is by performing perforations in the surface casing, which is suited to fields with shallow gas such as the Tunu field, a shallow water field in the Mahakam Delta, East Kalimantan, Indonesia. This pioneering method has gone through detailed engineering studies as well as risk evaluations to validate it as a new production method. Detailed reviews of integrity, safety and operational aspects have been carried out by involving well control experts to ensure that all risks have been properly identified and mitigated. The operation begins with noise logging which aims to identify any potential cement integrity problems in the outer Annulus, and then proceeds with Annulus Cementing, Cement Logging, Perforation, Sand Consolidation and ends with Clean-Up. This operation involves 3 barges: a multipurpose barge, a testing barge and a waste containment barge. This configuration aims to minimize risks and as a part of the risk mitigation measures so that well killing operations, should they be required, could be done at any time. The operations took 51 days to complete starting from the preparation phase up to the well clean-up phase. The well clean-up shows that results exceeding the target with gas production rate of 2.6 Million Standard Cubic Feet per Day (MMSCFD) and a sand rate of only 1 cc/hr with a drawdown of 11 bars from the maximum 30 bars.Maximum drawdown is limited at 30 bars to avoid resin injection rupture which functions as a “filter” for unwanted unconsolidated sand from being produced also a the same time hydrocarbon enters from formation to inside production tubing. All operational phases have been conducted with robust engineering design and high operations standards so that the major risk of sustained annulus pressure and unintentional hydrocarbon flow to the surface could be avoided. Additionally, all precautions and risk mitigations identified during the project study have been applied throughout the job resulting in safe operations. Since the end of the operations until the production phase, the well remained intact with no integrity issue. Despite breaching the dual barrier philosophy, this job has been successfully completed without major well integrity concerns. The combination of surface casing perforation and sand consolidation has proven able to answer challenges and open up opportunities for safe production of sand prone reservoirs in shallow gas zones. The success of this pilot project proves that producing from shallow reservoirs across surface casing is operationally feasible and can be carried out in a safe manner. Other candidates are being prepared with improvements in engineering design and operational aspects to achieve maximum benefits with minimum operating cost. This paper aims to review challenges and strategies carried out starting from the detailed engineering study until operations execution which could be promising for future shallow reservoir production. Innovation of perforating the surface casing to unlock reserves in the shallow section is the first time this has been performed in the world. The context of frist time in the world since this method is specifically done in a very sensitive shallow gas prone field and targeting shallow gas pocket as reservoir.The breakthrough of this unconventional method of producing hydrocarbons will open new opportunities to enhance production especially in shallow gas prone fields worldwide.