Day 1 Wed, March 01, 2023最新文献

{"title":"Identifying Optimal Operating Envelope in Horizontal Wells Producing from Dual Permeability Media","authors":"Abdulrahman Alrumaih, K. Kanu, Zahra Sakhin","doi":"10.2523/iptc-22777-ea","DOIUrl":"https://doi.org/10.2523/iptc-22777-ea","url":null,"abstract":"\u0000 In this paper, we present an integrated workflow utilizing a numerical model to identify optimal operating envelope for horizontal wells producing from dual permeability media. A synthetic dual permeability numerical model comprised of critical components namely: fracture and matrix permeabilities, matrix-fracture conductivity (shape factor), and fracture distribution based on Discrete Fracture Network (DFN) scheme was built. In addition, two horizontal producers completed with Inflow-Control – Devices (ICDs) and as open-hole respectively, are also connected to the model. Rigorous sensitivity analysis is implemented on these key parameters using the dynamic model under Equalspacing sampling scheme with well oil rate as the objective function. Range of values on each variable are typical for naturally fractured reservoirs. In addition, detailed sensitivity on ICD parameters such as flow resistance ratings are performed. Results from the analysis are presented in cumulative probability function identifying most likely, pessimistic and optimistic values.\u0000 Among all the variables, Matrix-fracture transmissibility has most impact. Unfortunately, it is often neglected when designing horizontal wells in dual permeability reservoirs. Current practice pays most attention on permeability contrast lack of consensus in the industry on best technique for its estimation. Most common methodologies applied are Kazemi and Warren-Roots. Nevertheless, it plays a critical role in describing dual permeability subsurface flow mechanism. Most significantly, it is widely acknowledged that beaning up choke sizes enhances production performance of wells connected to dual permeability. However, in this study, we have been able to establish operating limits for this phenomenon.\u0000 Matrix-fracture transmissibility could significantly influence a producer, which has not intersected high permeability streaks. Our study clearly demonstrates this observation using high-resolution dual permeability dynamic model. In addition, by performing multi-variate characterization, we establish operating envelope for optimizing well production performance in dual media systems through choke size settings.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"182 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121257115","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"First Worldwide Development and Deployment of a Uniquely Designed Blowout Stopper","authors":"Mustafa Buali, Mustafa R. Al-Zaid, Thamer Abdulghaffar, B. Gallagher","doi":"10.2523/iptc-23023-ea","DOIUrl":"https://doi.org/10.2523/iptc-23023-ea","url":null,"abstract":"\u0000 With the increasing challenges in gas well interventions, especially with the need to intervene in wells with extreme sour gases called \"high and ultra-high H2S wells,\" it became vital to have improved safety standards; including, but not limited to, pressure control equipment (PCE). Also, it became necessary to add an extra barrier to shear and seal under any conditions to safeguard against the risk of such toxic release. This improvement and new additional capability have been achieved by developing and successfully deploying a new technology for high risk completion and intervention applications.\u0000 This new blowout stopper is an electrically initiated, pyro-mechanical gate valve that performs the critical function of shearing and sealing during drilling, completions and intervention operations. It may be added to the stack or retrofitted to an existing blowout preventer (BOP) cavity. The new BOP is designed to shear anything above the bit and seal instantly even after full flow has been established, with the ability to instantly and reliably stop the release of toxic sour gas regardless of what may be across the BOP. This technology is considered the industry's first true blowout \"stopper,\" as opposed to current \"preventers.\"\u0000 The working components of this BOP are isolated from the wellbore fluids before activation to provide unmatched component integrity. In an emergency, such as a work string bottom-hole assembly (BHA) stuck across the BOP, it can shear anything and seal instantly to avert a potentially devastating release of toxic sour gas.\u0000 This technology has gone through an extensive qualification program on an international scale. This program was designed to satisfy well control manual requirements, API 16A PR2 and DNVGL-OS-E101. All applicable tests were witnessed and approved by oil and gas well intervention specialists in both the field and yard tests. This paper will describe the technology in greater detail, and talk about the qualification program, including the yard test and first worldwide field trial testing.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115680287","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Automated Seismic Interpretation Mis-Tie Corrector","authors":"W. Promrak, W. Seeyangnok, W. Inthung, P. Ekkawong","doi":"10.2523/iptc-23071-ea","DOIUrl":"https://doi.org/10.2523/iptc-23071-ea","url":null,"abstract":"\u0000 Seismic interpretation is the key process to support the evaluation of all petroleum system elements. With traditional interpretation workflow, seismic interpreters have to put a significant effort to ensure that interpreted reflection does tie at the intersecting lines. Since correcting seismic interpretation mis-tie is tedious, repetitive, and time-consuming, we have developed an in-house python toolkit to automatically identify and correct the interpretation mis-tie.\u0000 To identify seismic interpretation mis-tie, first, we will loop over interpreting line intersections and extract the values of interpreted horizon near each intersection. Then, the statistical distributions of interpreted horizon from each interpreting line will be compared. Interpretation agreement will be justified based on the proximity of derived distributions. If their medians are closer than the averaged standard distribution, such locations will be classified as valid interpretations; otherwise, they will be marked as potential mis-ties. Eventually, identified mis-ties will be corrected to the new location suggested by interpolation of valid interpretation nearby.\u0000 The toolkit has been validated and used to correct seismic interpretation from PTTEP oil fields onshore Thailand. The results are satisfying as the tool can correct most interpretation mis-tie errors in a few minutes, while manual correction would take up to a few weeks. Furthermore, we have assessed the volumetric difference from the maps with and without mis-tie correction. The result shows that the preliminary interpretation with remaining mis-ties yields 9.02% less gross rock volume (GRV) than the actual GRV from the final mapping. Meanwhile, the resulting map from the automated mis-tie correction yields 2.93% different from the actual GRV. By reducing volumetric uncertainty, the automated interpretation mis-tie corrector could lead to better decision-making on block evaluation/acquisition, well planning, and field development.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114891749","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Novel Seawater-Based Fracturing Fluid for Streamlined Logistics, Long-Term Scale Protection, and Enhanced Oil Recovery","authors":"Linping Ke, Zhiwei Yue, Andrew C. Slocum, Chunli Li, T. Larsen","doi":"10.2523/iptc-23106-ms","DOIUrl":"https://doi.org/10.2523/iptc-23106-ms","url":null,"abstract":"\u0000 Seawater-based fracturing fluid systems are well known for the economic and logistical benefits they provide, including unlocking a usable water source in locations that lack access to fresh water and eliminating the need for extra freshwater supply vessels at offshore wellsites. However, a common challenge with these systems is the formation of scale that results when the high content of sulfate in seawater contacts a barium-rich formation. Additional challenges include minimizing gel residue and mitigating water blockages that can negatively impact oil production after the fracturing treatment. To address these issues, a new seawater-based borate-crosslinked fracturing fluid, with integration of a phosphorus-free polymeric scale inhibitor (SI) and a flowback aid, was developed and evaluated for scale inhibition, oil displacement efficacy and rheological performance.\u0000 The seawater-based fracturing fluid rheology and compatibility with a scale inhibitor at varying concentrations were studied in a rotational rheometer. Static bottle test was used to evaluate the long-term barite inhibition. Oil migration and displacement of the fracturing fluid through a column flow apparatus were investigated to demonstrate the synergistic effect of the scale inhibitor and surfactant on enhancing oil mobility through porous media.\u0000 Addition of various concentrations of SI does not impair the fluid crosslinking, aging and breaking process, and provides effective scale inhibition over a six-month extended shut-in period. With respect to oil displacement, the frac fluids containing the scale inhibitor and surfactant at certain concentrations outperform the control samples without these additives or that only contained a single additive. It is shown that the seawater-based fracturing fluid has good stability under all shearing schedules and has quick shear recovery after exposure to high shear, indicating the fluid has excellent proppant carrying capacity.\u0000 With integration of a polymeric scale inhibitor (SI) and a flowback aid, the seawater-based borate crosslinked fracturing fluid demonstrates reliable rheological performance, superior scale inhibition, and improved oil displacement with reduced water blockage due to the synergistic effect of combining these chemistries.\u0000 The integrated fracturing fluid system designed for seawater operations not only provides a reliable fluid performance, long-term scale protection, and better oil recovery, but also significantly reduces logistical costs for offshore applications, especially for those requiring additional supply vessel support to transport frac fluid. All these aspects of the fluid system result in a reduced treatment cost, increased operational efficiency in time and process, reduced fluid waste, and lower CO2 emissions.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129826322","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Jasmine Field, Gulf of Thailand, Fill and Spill History Across Faults: A Fault-Seal Calibration","authors":"R. Davies, P. Wilson, D. Povey, Pattarapong Prasongtham, Siriporn Shibano, T. Ampaiwan, Farid Saifuddin","doi":"10.2523/iptc-22827-ms","DOIUrl":"https://doi.org/10.2523/iptc-22827-ms","url":null,"abstract":"\u0000 Compartmentalization of reservoirs in operating fields is commonly caused by sealing of faults (Cerveny et al., 2004; Davies and Handschy, 2003;Davies et al., 2019; Knipe, 1992; Yielding et al., 1997; Yielding et al., 2010). Calibrating this seal, however, is difficult without adequate subsurface data. A local region across the central part of the Jasmine Field, Jasmine A, along the northern extent of the Pattani basin in the Gulf of Thailand, was selected in this study for detailed fault-seal analysis calibration. The objective was to present the details of the fill and spill history from a juxtaposition analysis across the faults. The large number of well penetrations with fluid and lithofacies data and the 3D models of mapped permeability distribution provided a subsurface framework to reduce the uncertainty and allow a more comprehensive analysis of the crossfault reservoir juxtaposition and fluid contact levels. Crossfault flow behavior and fill and spill history were evaluated by examining fluid contacts in a strike view of the fault, with the properties juxtaposed.\u0000 The Jasmine Field is a narrow structural high that is cut by many NE-SW and NNW-NNE trending faults forming fault-bounded compartments. Reservoirs in the field are typically thin, stacked high-permeability fluvial sandstones of primarily Miocene age separated by thin shale beds that occur over a depth range of several thousand meters. Many of the sands have unique hydrocarbon-water contacts of oil or gas and water. Reservoir juxtaposition across the faults suggests that fault seal plays a major role in the trap. By comparing fluid contacts in each fault block, cases with different contacts across the fault likely represent a fault membrane seal. Contacts occurring at the same height suggest crossfault leakage.\u0000 The evaluation was done by estimating permeability distributions across the fault. These results, however, were not adequately determined simply from the fluid contacts on either side of the fault: fill histories in adjacent fault blocks and lateral structural controls also had to be accounted for. The results together allowed a unique fill and spill history to be defined. The results of the juxtaposition analysis for the main faults bounding the local structural trap in Jasmine A provided a calibration for a 3D analysis of the faults, including estimation of fault-rock properties.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121861655","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Dual Diversion System for HT Acid Fracturing Treatments","authors":"Basil M. Alfakher, Abdullah Al Moajil, Luai Alhamad, Sajjad Aldarweesh","doi":"10.2523/iptc-23083-ea","DOIUrl":"https://doi.org/10.2523/iptc-23083-ea","url":null,"abstract":"\u0000 Acid fracturing is a common stimulation technique used on low permeability carbonate reservoirs to enhance the productivity and deliverability of hydrocarbons. The success of acid fracturing treatments ultimately depends on the created fracture geometry, complexity and surface area. To maximize these parameters, it is imperative to include a fluid diversion strategy in the treatment design. The use of high viscosity fluids and solid particles is well addressed in the literature as effective diversion methodologies. In this study, the benefits of a dual diversion system composed of solid polymer-based particulate diverters suspended in a viscoelastic surfactant (VES) fluid were investigated for high temperature acid fracturing.\u0000 The degradation profile of the solid particulates was examined for different temperatures (ranging from 250 to 300°F) in different fluid systems (15 wt% HCl, spent HCl and KCl brine). The selection of fluids was also made to ensure the compatibility of the resulting diverter monomer solution with expected formation fluids. The viscosity of the VES system was examined at 275°F to ensure its thermal stability. The bridging capability of the dual diverter system was assessed using a filter press apparatus with a slotted metallic disk by measuring fluid leak-off as a function of time.\u0000 Results showed degradation rates increased with increasing temperature where a soaking time of 4 hours at 300°F was enough to fully degrade the solid particles as opposed to only 8% weight loss at 250°F for the same soaking time. Results also indicated faster degradation in more acidic environments where almost full degradation was observed in 15 wt% HCl at 250°F and 4 hours soaking time. The VES fluid system maintained sufficient viscosity for solid diverter carry with approximately 94 cP at 275°F and 100 s-1 shear rate. Bridging tests indicated the capability of the dual diverter system to completely plug the slots on the metallic disks and stopping any fluid leak-off up to 800 psi in a filter press apparatus.\u0000 This paper presents a full methodical study of an innovative dual diversion system for application in high temperature acid fracturing treatments. The paper also presents design optimization considerations in order to achieve successful diversion without causing any permanent formation damage.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121591057","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fast-Drill Method as a Risk-Based Approach to Reduce Deepwater Exploratory Drilling Cost","authors":"Michael Runtuwene, Chee Yong Ang, Guy De Boehmler, Ashutosh Kumar, Denise Lee, Mel Dulam","doi":"10.2523/iptc-22745-ea","DOIUrl":"https://doi.org/10.2523/iptc-22745-ea","url":null,"abstract":"\u0000 Discovering new oil and gas resources is the key for any energy companies to sustain or improve the hydrocarbon production. However, it is evident that most Exploration & Production (E&P) companies have reduced their exploration investment in recent years and the downturns have contributed to the strain. Therefore, it is critical to choose the strategy and allocate budgets efficiently to make sure the best possible return in the exploration sector.\u0000 Recently, the Operator restarted the exploration campaign in the deepwater territories of Brunei water, and it was key to leverage the learning curve from the Operator's global experience where essential strategies for cost reduction have been effectively implemented. The Operator has extensive deepwater drilling experience in Asia Pacific region as well as globally, where operational best practices are being replicated in the effort to standardize the Operator's deepwater activities. The Fast-Drill method in the riserless drilling section was identified to be a valuable replication in this part of the globe as it has proven to add values in other regions.\u0000 The Operator has long concluded that the use of weighted mud (dynamic kill drilling, DKD) in the riserless section contributes considerably to the high cost of subsea exploration drilling. In anticipation of the shallow flow event and to mitigate subsurface uncertainties, the usual Pump-and-Dump method necessitates a substantial contingency volume of DKD mud. To reduce the volume of DKD mud required, the Fast-Drill method was employed instead of the Pump-and-Dump approach. Fast-Drill refers to the method of drilling riserless with seawater at high penetration rates where cutting loadings that are created by fast penetration rates results in the required equivalent circulating density (ECD). The Fast-Drill method has been implemented in two wells in Brunei and the results have been favorable. Among the benefits found were reduced rig time, significantly lower mud costs and the avoidance of gumbo. Borehole stability was maintained, and the hole was cased-off without difficulty.\u0000 This paper describes the requirements set at the planning stage, to ensure that the project was competitively scoped and that it adhered to the Operator's global standard deepwater operations practices, following a franchise concept. It outlines the challenges encountered and how they were addressed to successfully implement the Fast-Drill approach. Additionally, this paper examines the advantages of this method and illustrates how thorough planning and risk assessment were critical for a safe and efficient execution.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"216 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134187782","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Understanding the Complicated Fracture Network in a Fractured Granite Reservoir Using the Borehole Image and Geochemical Log, Case Study from Songliao Basin","authors":"Weihe Yan, Cong Zhou, Yuhua Wang, Baoyan Jiang, Bo Liu, Jinlong Wu, Xunqi Liu, Qingzhi Lu, R. Paramatikul, Dung Doan Thi My","doi":"10.2523/iptc-22987-ea","DOIUrl":"https://doi.org/10.2523/iptc-22987-ea","url":null,"abstract":"\u0000 Granite basement reservoir has become a very important exploration target in Songliao Basin of North-east China. Several exploration gas wells were drilled in the study area, and it shows strong heterogeneity and complexity in reservoir properties. Since it is very difficult to perform accurate formation evaluation in fractured granite reservoir using the conventional open-hole logs, the advanced wireline logging such as borehole resistivity image and geochemical logs were acquired to understand the impact of the fractures on the producibility in the tight granite reservoir. The objective of this research is to understand the complicated natural fracture system in the tight granite reservoir.\u0000 The high-resolution borehole resistivity image logs could provide abundant information to evaluate the fracture distribution, direction, and intensity. It can also reveal the secondary pores and dissolution enhanced features in the granite basement reservoir. The high-definition spectroscope logs provide significant information for geological description and evaluation of the downhole formations. One parameter \"K/Na (potassium/sodium) ratio\" was developed to differentiate the composition of the minerals in the formation. It was found that the intervals with high K/Na ratio have higher fracture apertures than other intervals in the case. The reservoir quality is controlled by fracture density and secondary porosity. Different sets of nature fractures have a different angle range or strike, and it will create a complex natural fracture network. The fracture zones with complex fracture network have suffered stronger weathering process than the zones with simple fracture network.\u0000 The case study shows that the high porosity zone with complex natural fracture network has strong dissolution. The K/Na ratio from geochemical log also have clear anomaly in that zone. It indicates that there has strong chemical weathering process in that zone which has high K/Na ratio than other zones. These zones have complex fractures network and strong dissolution than other zones. Better understanding the controlling factors of the fractured granite reservoir could be helpful for fracturing design and well positioning.\u0000 The integration of borehole image and geochemical log in the fractured granite reservoir was proven to be effective method in this case study. It could be used as a reference for similar reservoir fracture evaluation.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133851011","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Sand Fill Clean-Out on Wireline Enables Access to Additional Perforation Zones in Gas Well Producer","authors":"D. Field","doi":"10.2523/iptc-23048-ea","DOIUrl":"https://doi.org/10.2523/iptc-23048-ea","url":null,"abstract":"An Australian operator wanted to explore options for wireline conveyed sand bailing in one of their offshore platform gas producing wells. The objective was to remove twenty-six meters of sand fill inside 9.625\" production casing, with an internal diameter of 8.681\". Due to the landing nipple at the end of the tubing, the minimum run-in-hole restriction of the production tubing string was 3.987\".\u0000 To limit the number of clean out runs, the latest technology in e-line deployed suction tools with a 4.25\" OD was chosen, which provided increased recovery volume over its smaller cousins, plus real-time surface control and monitoring. Because of the tool's overall diameter, the landing nipple also required milling to allow access. Therefore, a specially designed 4.412\" mill bit was manufactured and run on a milling tool – a tool requiring tractor conveyance to provide weight-on-bit and counter the reactive torque.\u0000 As the well had low deviation, the subsequent clean-out toolstring was run standalone (without tractor). One of the key factors governing the feasibility of conducting this operation on e-line was the overall toolstring lengths, where the lubricator height was limited to approximately sixteen meters.\u0000 The e-line deployed milling technology – which produces a grinding action rather than cutting – successfully milled through the landing nipple and a ball catcher in four runs, thus increasing the internal diameter sufficiently to allow access for the clean-out toolstring. A well fluid column of about seven bar is required to enable operation of the suction tool. The clean out tool was configured with three bailer sections (seven max) for the first run, to determine sand recovery optimisation. Three different sizes of micron bailer filters are provided; prior knowledge of debris particle size is therefore advantageous. In this case, a slickline bailing sand sample had been recovered, which immediately aided filter choice. Seventeen bailing runs were conducted over five days (with the number of bailer sections increased to six), successfully recovering a total of 918 litres of sand, equating to about 2.4 tons. Ultimately, the process enabled perforation of two additional gas zones to increase production.\u0000 The e-line toolstring, consisting of six different sensors and robotic tools, made this a more controllable and inherently safer operation than coiled tubing methods, as well as having a smaller footprint with reduced environmental impact. Operational details, including job planning and lessons learned will be discussed in the extended abstract.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"145 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114841763","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Overcoming Flow Assurance Challenges of the First Deepwater Gas Field in Malaysia","authors":"Suphawat Kiertkul, K. Saranyasoontorn","doi":"10.2523/iptc-22824-ea","DOIUrl":"https://doi.org/10.2523/iptc-22824-ea","url":null,"abstract":"\u0000 Block H, located in 1,300 meters of water depth at offshore Sabah, consists of Rotan and Buluh fields. The subsea trees, jumpers, manifold, umbilicals, risers and flowlines were installed and tied-back to an FLNG facility. The objective of this project was to develop most practical and effective solutions to overcome flow assurance challenges owing to low seabed temperature and high-pressure gas to achieve 1st gas from the first deepwater gas field in Malaysia.\u0000 A model was built in OLGA software with all field conditions to run simulations and predict process parameters at every critical point in subsea wells, risers and flowlines as well as topside facilities. Besides, all constraints from the subsea wells, jumpers, risers and flowlines all the way to topside inlet receiving facilities were carefully reviewed and optimized with an abundance of caution to determine the stepwise approach by utilizing the high-pressure gas from wells to remove around 1,000 m3 of pre-filled MEG fluid out of the flowline, called ‘DeMEG operation’ before feeding gas to LNG process operations.\u0000 With 200-230 barg pressures from deepwater gas wells and 2-4°C temperature at seabed as well as pre-existing water content in saturated gas given by reservoir aquifer, this start-up operation would expect to be in the hydrate zone. One of the unavoidable potential consequences was a hydrate formation and could result in plugging of jumpers, risers or even flowlines.\u0000 The DeMEG operation results indicated the lowest temperature at the downstream of the subsea choke was −23°C due to Joule-Thompson cooling during the cold start. One mitigation strategy was to inject a batch of MeOH at the subsea wellhead until the temperature is above the hydrate point. After the gas flowed along the flowlines, it would cool down to the seabed temperature during the steady state condition. Hence, additional mitigation was to continuously inject Mono Ethylene Glycol (MEG) as another thermodynamic hydrate inhibitor mixed with gas stream. The MEG affixed water molecules and thus deterred them from forming a cage around gas molecules to prevent hydrate formation.\u0000 A multi-stage DeMEG operation was carefully planned to overcome liquid handling capacity at topside and eventually executed at offshore until the remaining MEG in the flowline was as low as reasonably practical to proceed with gas production from the field.\u0000 With an excellent collaboration from the team and proper planning, the DeMEG solution together with hydrate mitigation strategy were proven to be effective and the commissioning operation was successfully completed as per the plan until the 1st gas was achieved on 6-Feb-21 and supplied to FLNG. The 1st LNG drop subsequently came in 7 days later. This field has increased production volume around 270MMSCFD, equivalent to 45,000 barrels of oil per day to PTTEP and JV partners.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117040702","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}