North Arthit field in Gulf of Thailand is a gas condensate field, but also has oil reservoirs that produce from number of wells. This paper explains the implementation of in-situ gas lift and gas dump flood technologies to increase production and improve recovery from a partially depleted oil reservoir in North Arthit field. A simulation study was performed to understand reservoir characteristic, drive mechanism and expected oil rate prior to the field implementation; the study results were to allow cross flow within the tubing to dump high-pressure gas from a deeper gas reservoir into the oil reservoir to increase reservoir pressure and sweep the oil to a nearby producer. This successful pilot work has opened up the opportunities for other small oil pools in Gulf of Thailand. A proper design of the in-situ gas lift and dump flood will significantly improve the oil recovery.
Liquid loading is a common problem in many gas wells in the Gulf of Thailand. At the late stage of well life, reservoir pressure declines, gas production rates decrease, and liquid begins collecting on the wall of the tubing and accumulates at the bottom of the well, eventually killing the well. This paper presents promising results from foam-assisted lift (FAL) field trials to remove liquids, re-establish flow, and increase production in previously idle wells. The injection of foaming agents can be used to remove liquids through artificial lift. High downhole temperatures in Gulf of Thailand wells requires special foaming agents that can operate at 450°F. Using high-temperature foaming agents in nearly dead wells can extend their life by reducing the production decline rate and preventing premature water loadup. Because foam density is significantly lower than liquid density, hydrostatic pressure is reduced, which assists the flow of fluids from the bottom hole to the surface, resulting in increased gas production rates and reserve recovery rates compared to natural flow. An operator in the Gulf of Thailand experienced promising results from a field trial using high-temperature FAL with batch treatments in five high-temperature wells in the offshore field. Three wells that were previously not flowing were able to flow to the production system after treatment. One well was able to flow at even higher rates after the FAL treatment compared to prejob rates. Only one well did not respond to the treatment. Understanding the FAL procedure and addressing critical issues before implementing the technology can help enhance mature field production in otherwise idle wells. Using FAL in mature wells with low or no production can help remove liquid accumulation at the bottom of the well, preventing premature water loadup and returning idle wells to production.
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.
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