The successful development of a light weight slurry system for cementing long intervals at high temperatures in three dimensional multiple stacked gas zone wells, has been achieved in the Gulf of Thailand. The cementing system has been developed to successfully complete progressively more difficult wells, starting with conventional large bore wells and tubing plus packer completions, and later down-sizing into single monobore wells whereby the tubing is cemented in place. The problems associated with the down-sizing of the wells are further increased by more challenging well paths and higher temperature fields. Many problems and risks were overcome to complete this task successfully. These changes have posed new challenges in primary cementing. Like the well size, the slurry system has also undergone a refinement and improvement process. The local industry has gone from dry blended slurry systems to all-liquid additive slurry systems saving considerable dollars, whilst realizing large gains in slurry flexibility, ease of mixing and improved logistics. Whilst developing and realizing these gains, the system has been refined and successfully applied to smaller, hotter and more difficult wells. This paper presents the concerns associated with cementing these challenging wells where remedial cementing has been effectively eliminated. The processes related to this success, evaluation methods and field results will be discussed. Introduction In terms of completing the well, cementing operations are arguably one of the most important operations done on a well. When performed correctly they give a well every opportunity to perform as it was designed. However, poor primary cementing can lead to lost reserves, increased water rates and expensive remedial work. The prime goal of cement is to provide adequate zonal isolation throughout the life of the well. This is essential for trouble free production. In slim hole cementing the importance of adequate zonal isolation is magnified due to the fact that remedial options are both limited and also expensive. Unocal Thailand has drilled over 1400 wells (Figure 2) in the Gulf of Thailand. During this period there have been many changes in well design. This paper will deal with the two most recent. Older completions utilized 13 3/8" casing to 1,000', 9 5/8" casing to 4,500’ TVD (+/-7,000’ MD) and 7" casing to 8,900’ TVD (11,700’ MD) with a conventional packer and sliding sleeve completion installed for production. One recent change occurred with the elimination of the 13 3/8" casing and conventional completion. The resulting wells were completed with 9 5/8" casing, 7" casing and 2 7/8" tubing being cemented in a 6 1/8" hole. The 9 5/8" casing is set at 1,000 TVD, the 7" casing at 4,500’ TVD and the tubing is run to TD at 8,900’ TVD (Figure 1). To date 627 of these wells have been completed. The most recent change has been to down-size one more level with the elimination of the 9 5/8" casing. This has been achieved by setting 7 5/8" casing at 1,000'. The 7" intermediate casing from the original Gulf of Thailand Monobore well has become 5 1/2" casing. Finally the production hole is drilled with a 4 3/4" bit and the same 2 7/8" tubing cemented in place. This ultraslim well architecture has been used on 13 wells to date. The well paths of all types are predominantly three-dimensional with 35° to 60° inclinations and 90° azimuth changes. These wells are intersecting alternating sand shale formations with numerous thin coal seams. The sandstone reservoirs contain gas condensate and high CO2 with an average thickness of 13 feet. The reservoirs themselves are broken into many smaller sections as a result of being in a complex faulted graben system. In addition to this, there are multiple gas/water contacts in the wells, making isolation essential for trouble free production.
Interest in CCS project development is accelerating in SE Asia, driven by the need to monetize emission-intensive assets in the region while complying with increasingly ambitious GHG emissions targets. Depleted hydrocarbon fields represent an attractive storage option for early CCS project due the enhanced understanding of the reservoir, its dynamic behavior, and proven storage capability. Re-use of existing infrastructure also presents the potential to reduce both project costs and time to first injection, however, these brownfield sites also carry significant risk to the long-term, safe containment of injected CO2 through risk of leakage via legacy wells. A methodology is presented in this paper to investigate the risk-reward balance of developing a depleted gas field as a storage site in the Gulf of Thailand. A screening process to assess all abandoned, suspended, and active wells is used to identify wells with re-use potential as CO2 injectors or CO2 plume monitoring wells, and those which represent a leakage risk to the project. A set of legacy well risk identifiers is generated for the field based on well construction records, descriptions of current well barriers, well utilization history, and current best practice guidelines. Southeast Asia has significant remaining reserves of oil and gas, and coal, and an active liquefied natural gas (LNG) export industry. The region's energy demand is increasing rapidly and is forecast to continue to grow over the next decades (World Economic Forum, 2019). To date, fossil fuels have supplied nearly 90% of this growth in the demand for energy in the region (IEA, 2021). To meet this growing energy demand, several new gas projects are under development across Southeast Asia, but many of these are associated with high CO2 gas fields where the produced gas contains significant (up to 70% by volume) CO2 (GCCSI, 2020). In Thailand, where nearly 94% of the primary energy is met by fossil fuels (BP Statistical Review, 2022), the energy sector represents the biggest contributor (74% in 2013) to the country's greenhouse gas emissions (GHG; UNFCCC, 2020). However, as per the nationally determined contribution to the United Nations Framework Convention on Climate Change (UNFCCC), Thailand intends to reduce its GHG emissions by at least 20% from projected business as usual levels by the year 2030 (UNFCCC, 2020). Carbon capture and storage (CCS) represents one option to help meet this increased demand in fossil energy while also reducing GHG emissions. An approach which is gaining traction across the region is to utilize the high concentrations of CO2 stripped out of the raw gas streams at gas processing plants and, instead of venting to atmosphere, the CO2 can be compressed, dehydrated, and transported to suitable long-term storage locations. Depleted oil and gas fields form an attractive opportunity for long-term storage of CO2 due to the wealth of both static and dynamic knowledge available from appraisal through production activities. Depleted fields also have the advantage that they have a working primary seal for hydrocarbons, which has been proven over geological time and so can be considered, in general, to carry low risk of leakage through geological means. Brownfield sites can, however, also represent a challenge to project success through an increased risk to the containment of the injected CO2 due to the presence of legacy wells. These existing wells represent a variable risk to containment depending on well age and type, well history, well design, and plug and abandonment methodology applied. This paper presents the outcomes of a CO2 storage feasibility study for a depleted gas-condensate field in the Gulf of Thailand. The main aims of the study were to:1) identify the project risk associated with the integrity of the field legacy wells, and 2) to evaluate the potential for well re-use for the CO2 injection project. Reusing an existing field offers new life to an otherwise end-of-life asset, inching towards decommissioning and site closure. As commercial scale CO2 storage in depleted hydrocarbon fields represents a ‘First of a Kind’ project, the feasibility study is designed to evaluate the current status of the field and surface facilities with respect to CO2 injection and long-term storage. As a feasibility study, the focus of the technical work was to identify any ‘showstoppers’ which might indicate that the selected site was not suitable for long-term CO2 storage and, if sufficient positive storage indicators were identified, to select the most appropriate options for progression into a Concept Selection study in which more detailed engineering studies will be completed.
Field-X is a large offshore gas structure located 50 nautical miles from Miri City, Malaysia. The reservoir is a High-Pressure High-Temperature (HPHT) carbonate formation with high contaminants i.e., 1.8% mol of Hydrogen Sulfide (H2S) and 18% mol of Carbon Dioxide (CO2). This paper dwells on the completion design for the high-rate wells planned for this development. Exploration and appraisal wells showed severe reservoir properties that are "unique" as compared to other HPHT developments around the world. A multidisciplinary engineering team including HPHT drilling and completion specialists, production technologists, reservoir engineers, external specialist consultants, and facilities engineers are all working with a One Team One Goal mindset to address the challenges of completing this carbonate reservoir. Some of the completion design challenges addressed in this paper are Annular Pressure Management (APM) systems, perforation strategy for long intervals, well intervention philosophy, compaction and subsidence loading, thermal well interference due to the proximity of the platform well slots, HPHT monobore completion equipment design, qualification, and availability due to a very limited number of suppliers with long lead times. Another critical challenge addressed in this paper is an extensive material selection process to withstand the extremely corrosive well fluids, high temperature, and potential material cracking that historically has led to catastrophic consequences. As a result of the environment, exotic tubular materials are proposed based on intensive laboratory tests and computer simulations. Three-dimensional time history geomechanical and reservoir models explicitly detail the displacement compaction field which the downhole tubulars will be exposed in their lifetimes. Any annular pressure build-up will be handled by an APM system addressing the A, B, and C annuli with a permanent downhole gauge (PDG) installed for pressure and temperature monitoring tubing and annuli. These are some examples of the well design challenges tackled and resolved. The project is currently at the design phase, and all the thought process and design philosophies would be tested in this field. The authors wish that the lessons learned, engineering approaches, and design results will be useful in future sour HPHT completion developments.
HPHT wells are typically associated with high complexity, technically challenging, long duration, high risk and high NPT as many things could go wrong especially when any of the critical nitty-gritty details are overlooked. The complexity of this project is amplified with very high level of contaminants compounded by high pressure and high temperature environment. In the conceptual planning phase for the upcoming development of such project where its scale and severity are unprecedented in the country/region, a fit for purpose casing and tubing design is critically important to ensure the well integrity over its design life is assured. At the same time, cost optimization can be achieved utilizing industry practices, testing and qualification of materials and vast learning from incidents and failures occurred in similar HPHT projects over the last three decades scattered around the world. This paper intends to outline the challenges and optimization of casing design philosophy which is drawn upon various perspectives such as long term well integrity, drilling operations, working stress design, effect of compaction and subsidence, probability of failure analysis, multi-well thermal analysis, downhole material corrosion performance, connection performance and a combination of all the above in a holistic manner. A particular focus would be discussing the delicate balancing act between satisfying the working stress design of downhole tubular versus the complexity of downhole material selection work. With the given challenging environmental condition, this points towards exotic type of CRA materials which require certain magnitude of yield strength deration attributed to the given environmental condition and their respective manufacturing processes.
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