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The productive section in a high-pressure, high-temperature (HP/HT) geothermal Field A in the Philippines features shallow and deep reservoirs separated by a low-permeability formation. However, recent years have seen a reduction in production levels. To activate and enhance well production, coiled tubing (CT) nitrogen-lift operations were required. CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations.
All drilling challenges relate to the fundamental objective of maintaining a workable wellbore throughout the well-construction process. A workable wellbore can be drilled, logged, cased, cemented, and completed with minimal nonproductive time. The design of the drilling-fluid system is central to achieving this objective. With a poorly designed system there are some challenges that will occur. Most operational problems are interrelated, making them more difficult to resolve.
Fields in the Bolivian Sub-Andean Basin are remote and difficult to access. The producing zones include the country's most challenging wells, with depths of up to 26,000 ft, with high pressure/high temperature (HP/HT), high gas cut, crossflow, dogleg severity, and well-access restrictions. The complete paper reviews 25 coiled tubing rigless well interventions (CTRWI) to extend the life of those wells, including operations involving nitrogen (N2) lift, acid wash, milling, shifting sleeves, setting packers, stimulation, velocity strings (VS), and fishing. CTRWI in Sub-Andean Basin fields had not been implemented historically because of limited road access to the fields, lack of available equipment with high technical capabilities, high pressure, and well depth. Beginning in 2017, however, operators evaluated the risk and elected to perform CTRWI involving stimulation, cleanout, N2 lift, fishing, VS jobs, and other techniques.
Summary Ultra‐high‐pressure high‐temperature (uHPHT) reservoirs undergo extreme pressure depletion during their production life cycle. This results in significant reservoir compaction and consequent overburden subsidence with major consequences for wellbore mechanical integrity, safety, and field economics. However, the use of underdetermined geomechanical models to accurately predict compaction‐induced stress/strain changes on wellbores and its consequences during production time results in significant residual uncertainty. One method of measuring compaction‐induced stress/strain changes in wellbore is by the emplacement and measurement of radioactive markers. Although it is long established in normal pressure reservoirs, it is rare in uHPHT projects. The Culzean uHPHT gas‐condensate field is located in the UK Central North Sea. To constrain geomechanical model compaction uncertainty, radioactive markers were deployed. The objective was to accurately acquire preproduction baseline measurements and subsequent changes through periodic measurements during production life. These accurate wellbore measurements would then be compared with the geomechanical model to help calibrate predicted to actual compaction. By doing so, the objective is to enable better informed decisions regarding well and field management. The Culzean uHPHT radioactive marker project comprised a planning phase and a preproduction safe deployment including a baseline survey phase. Subsequent repeat measurements are planned during field production life. The emplacement and surveying of the subsurface radioactive markers for compaction monitoring in uHPHT reservoirs is a high value but nontrivial operation. In addition, much knowledge and experience of the methodology has been lost. This paper contributes to published literature by describing the successful emplacement and monitoring of subsurface radioactive markers on Culzean and aims to capture learnings and knowledge for future workers. Early detailed planning coupled with extensive testing is key to successful deployment. Timely engagement of all stakeholders and ensuring all decisions are aligned with safety and environmental considerations also contribute to realization of the project aims.
While the world is transitioning into a greener and less-carbon-rich energy source, the fact remains that there is a growing need for exploration and production of hydrocarbons in previously untapped resources. These frontier reservoirs, while extremely hot, are prolific and make the footprint of the exploration activity much smaller than shallower drilling, which would require many more wells to deliver the same amount of hydrocarbon. HP/HT wells can be found offshore in the North Sea and Gulf of Mexico, or on land--as seen recently in the Gongola Basin. Fluid identification, which is a critical process in fluid sampling, continues to be a challenge in temperatures above 350 F. At temperatures up to 450 F, fluid identification is currently achieved by bubblepoint and compressibility measurements, which cannot quantitatively measure contamination levels of the subject sample fluid. A possible solution to this problem would involve using pyroelectric detectors in the process of estimating a property of a downhole fluid.
HPHT is where the undisturbed bottom hole temp at prospective reservoir depth or total depth is greater than 300oF or 150oC, and either the maximum anticipated pore pressure of any porous formation to be drilled through exceeds a hydrostatic gradient of 0.8 psi/ft, or a well requiring pressure control equipment with a rated working pressure in excess of 10000 psi.
He, Xinxing (PetroChina Tarim Oilfield Company) | Wang, Kelin (PetroChina Tarim Oilfield Company) | Fan, Wei (PetroChina Tarim Oilfield Company) | Liu, Hongtao (PetroChina Tarim Oilfield Company) | Long, Yan (CNPC Tubular Goods Research Institute) | Xie, Junfeng (PetroChina Tarim Oilfield Company) | Fu, Anqing (CNPC Tubular Goods Research Institute) | Deng, Peng (PetroChina Tarim Oilfield Company) | Jiang, Tianhong (PetroChina Tarim Oilfield Company)
Abstract Kuqa foreland basin, which is located in the western of China, has the characteristics of HPHT with high CO2 partial pressure, and covered Yaha, Kela, Dina, Dabei, and Keshen gas fields. This story dated back to 2000 year that Yaha gas field was put into production, and the reservoir temperature 140°C, pressure 56 MPa, depth 4900-5300 m, and CO2 concentration 0.7-1.3 %. Carbon steel was selected for tubing material in the early stage of field development. After about 3 years, tubing perforation was caused by serious corrosion. Then carbon steel wasupgrade to 13Cr. However, it was found that there was serious corrosion in the connection part of tubing, and the corrosion was caused by the CO2 and condensate water. Based on the experience in Yaha gas field, the modified 13Cr tubing was used in the Dina2 gas fields, and the reservoir temperature 140C, pressure 110 MPa, depth 5200 m, and CO2 concentration 0.26-1.02 %. Although the well condition is less harsh, serious corrosion still occurred concentratedly on tubing pin end. Considering premium tubing leak in Dina field happened during acidification operations, and the results of series simulation tests conducted, the understandings were achieved that acid will cause serious corrosion to the inner wall of tubing, aslocal corrosion is dominant factor of stainless steel. The super 13Cr material was used in Keshen gas field which has reservoir temperature 150-188C, pressure 105-136 MPa, depth 6000-8038 m, and CO2 concentration 0.1-1.1 %. However, tubing fracture happened one by one, which originate from stress corrosion cracking caused by mixture of phosphate packer fluid and killing mud. Therefore, material selection needs to considerthe compatibility of different fluids, and formate was chosen as packer fluid. By December 2020,it has been used in 103 wells of Kuqa foreland basin, abnormal annular pressure is presented in 6 Wells, and the longest service time is six years. As the rapid exploration and development of Kuqa foreland basin, the proper material selection become more difficult for gas reservoir temperature more than 190C and its pressure greater than 140 MPa, the past practices about material selection may provide the reference, and the story about material selection will be continued.
Khalid, Ali (Weatherford International) | Ashraf, Qasim (Weatherford International) | Luqman, Khurram (Weatherford International) | Hadj Moussa, Ayoub (Weatherford International) | Ghulam Nabi, Agha (Pakistan Petroleum Limited) | Ahmed Baig, Umair (Pakistan Petroleum Limited)
Abstract With the energy sector in crisis the worldover, oil and gas operators continue to seek more effective and efficient methods to reach potential prospects. With sharply declining oil prices, it is imperative that operators minimize the non-productive time in the drilling of all wells. Many operators are actively seeking riskier exploration to establish a strong foothold in this volatile market. One such area of interest to operators is HPHT and beyond wells. An HPHT prospect carries a high-risk high-reward potential, therefore newer and advanced methods are being deployed to successfully drill and complete HPHT wells. The Makran Coastal belt in south western Pakistan is one such area containing a potential Ultra-HPHT prospect. Many operators had attempted to drill about 9 wells in the locality but never managed to reach target depth due to drilling operations being plagued with a large number of problems. The drilling problems included high pressure influxes, stuck pipe while controlling influxes, circulation losses with high mud weights and ECD’s, differential sticking against permeable formations, inefficient bottom hole pressure control due to mud weight reduction with high temperatures and swabbing from the formation due to having an insufficient trip margin. The operator was facing an extremely narrow drilling window in the target section. The maximum formation pressure was estimated to be around 2.29 SG while the maximum fracture pressure of the formation was estimated to be around 2.35 SG in EMW. It was abundantly clear that drilling with a conventional mud system would be impossible and impractical on all forthcoming wells. As it was of paramount importance to precisely manage the wellbore pressure profile, the operator decided to apply managed pressure drilling on a candidate well. By applying managed pressure drilling techniques the operator expected to drill the section with an underbalanced mud weight and maneuver the bottom hole pressure just above the pore pressure line and thereby avoid circulation losses, detect influxes early on and control influxes without the need of ever shutting in the well, account for mud density variations with temperatures by executing an advanced thermal hydraulics model in real time, mitigate swabbing from the formation again by maintaining a constant bottom hole pressure while tripping, and finally ascertain the downhole pressure environment by conducting dynamic formation pressure tests. The successful application of MPD enabled the operator to reach target depth for the first time in the history of the area. The paper studies the planning, design, and execution of MPD on the subject well.