Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022最新文献

{"title":"Depositional Environment Based on Palynological and Foraminiferous Analysis of The Klasaman Formation in The Salawati Basin Klayili Area Klayili District Sorong Regency West Papua Province","authors":"","doi":"10.29118/ipa22-sg-114","DOIUrl":"https://doi.org/10.29118/ipa22-sg-114","url":null,"abstract":"The Salawati Basin, West Papua is a mature basin producing oil. One of these basins was filled by sediments from the Klasaman Formation consisting of shale, claystone, sandstone, especially in the northern part there are conglomerates, rarely coral reef limestone deposited in a deltaic to fluvial environment. An a analysis of the depositional environment in the Klasaman Formation provides knowledge on the facies development and depositional environment in the study area. The study was carried out by using the surface geological data such as measured stratigraphy section (MS) with approaches of palynology, foraminiferous and petrography analysis. The development of palynology studies in Indonesia, especially in Eastern Indonesia is still very minimal and can be improved along with the increasing number of oil and gas exploration moving to transitional environments. The results of the analysis show that the Klasaman Formation is Late Miocene-Pliocene (N18) with stratigraphy sorted from the oldest to the youngest units, namely carbonate sandstone units and conglomerate units. The geological structure that developed in the study area was controlled by a structure Klayili Normal Fault which causes a subsidence in the Northwest–North part of the study area and folding in the Southeast, namely Klayili Syncline. Overall facies development as a delta plain environment that show shallowing upward vertical succession with relatively dominant progradation process. Carbonate sandstone as the older unit was deposited in a lower delta plain environment as a tide dominated delta with mangrove vegetation to a peat swamp with freshwater vegetation. There are three facies associated with this unit which are distributed channel, marsh, and interdistributary bay. Conglomerate as the younger unit was deposited in the upper delta plain environment which is influenced by tide-fluvial dominated delta. Several facies associated with this unit are distributary channel, interdistributary bay, swamp, and crevasse splay.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"62 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130936157","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 Comprehensive Ensemble Modelling Study to Evaluate Subsurface Uncertainties Associated With Tangguh CO2 Enhanced Gas Recovery (EGR) Project to Deliver a Robust and Quality-Optimized Development Plan","authors":"A. Dewanto","doi":"10.29118/ipa22-e-40","DOIUrl":"https://doi.org/10.29118/ipa22-e-40","url":null,"abstract":"Tangguh Field, in Bintuni Bay, Papua Barat Province, Indonesia, commenced development following a successful exploration program in the 1990s. Tangguh has been on production since 2009 through development of two liquified natural gas (LNG) trains (Kasim, Titus, Roberts, & Bulling, 2000). Full development includes a third LNG train with the expected first gas in 2023 and Enhanced Gas Recovery (EGR) and Carbon Capture Utilization and Storage (CCUS) in 2026. EGR/CCUS fits within the Government of Indonesia’s (GoI) gas production and carbon emissions reduction targets by 2030. The EGR/CCUS project will inject approximately 90% of reservoir CO2 back into the reservoir in the southwest part of Vorwata Field. Reservoir CO2, that is currently vented, will be captured from the Acid Gas Removal Unit, compressed, flowed via a subsea pipeline to an offshore facility, and then to injection wells. The CO2 is injected at supercritical conditions, to increase gas production and recoverable reserves through pressure maintenance and gas displacement mechanisms. Understanding the subsurface uncertainties and their impacts on production and operations are essential for optimizing field development plans and mitigating risks. The key risks to CO2 injection/capture are early CO2 breakthrough and reduced hydrocarbon recovery. bp’s proprietary Top-Down Reservoir Model (TDRMTM) based ensemble modeling workflow successfully assesses subsurface uncertainties, matches historical performance, and quantifies the value associated with the EGR/CCUS development. TDRMTM driven assisted history matching algorithm was matched the model against 12 years of historical production. Match qualities associated with historical rates and pressures were used as screening criteria to obtain a robust ensemble of history-matched models and ensure a healthy and sufficient exploration of uncertainties. The resulting metrics include the range of net hydrocarbon incremental gas recoverable, CO2 breakthrough times at offset producers, and CO2 sequestration volumes. Results from the ensemble-driven study have enabled a robust development plan, particularly associated with the","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133315011","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":"Characteristics of Eocene Carbonate Reservoir – A Case Study of Ngimbang Carbonate in North Madura Platform, East Java Basin.","authors":"H. I. Darmawan","doi":"10.29118/ipa22-g-62","DOIUrl":"https://doi.org/10.29118/ipa22-g-62","url":null,"abstract":"Exploration in the East Java Basin began in 1888 when first discovery was found in the Kuti field from the Lidah play. Fast forward to 2022, there has been a total of 143 discoveries accumulating to total resources of at least 2.2 Bbl oil and 13 TCF gas from more than 600 exploration wells drilled in the basin. More than half of the resources are contributed by the Kujung Play. As Kujung exploration matured, other exploration started to focus on the deeper plays such as the Eocene Ngimbang Carbonate, an underexplored play with sizeable potential. A newly drilled well in North Madura Platform well has succeeded to prove that Ngimbang carbonate contains excellent porosity and permeability as shown by the well test result and the total loss experienced during drilling. Cased hole logging results further proved the high porosity of the carbonate with values of up to 25-30%. Seismic analysis and well data analysis show that the Ngimbang carbonate experienced 3 stages of carbonate growth; Stage 1 – Initiation Phase, Stage 2 – Aggradation Phase, and Stage 3- Backstepping Phase. Based on the well log and petrography thin section analysis, the secondary porosity in Ngimbang carbonate was caused by intensive dissolution-karstification related to subaerial exposure and fracturing and dissolution due to the later diagenesis phase. The secondary porosity developed varies depending on the depositional environment setting and carbonate growth phase, with average of 10-15% porosity range within the shelf-edge to shelf depositional environment, and average of 20-25% (up to 35% max) on the distal isolated carbonate. The unique intense karstification in the isolated carbonate was contributed by tectonic subsidence rate variation which fluctuated the accommodation space formed, and global sea level falls and eustatic fluctuations during the Eocene-Oligocene periods which further promoted major subaerial exposures and contributed to the episodic karstification and secondary porosity generation.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"177 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114854708","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":"Customized HPWBM Using Dual Brine System to Provide Wellbore Stability in Exploration North Madura Offshore Indonesia","authors":"M. G. Samudra","doi":"10.29118/ipa22-e-44","DOIUrl":"https://doi.org/10.29118/ipa22-e-44","url":null,"abstract":"The Water-Based Mud (WBM) system was planned to be used in drilling at Offshore North Madura, Indonesia. However, a review of offset wells found they experienced issues while drilling and running the casing. Designing a proper WBM is the key to successfully drill into problematic clay. This paper shares the optimization done by using a combination brine in High-Performance Water Based Mud (HPWBM) to minimize the potential risk of time dependent shale in the North Madura area. A series of shale reactivity and WBM performance tests such as CEC, CST, Shale Erosion Test, Shale Accretion Test, Swelling Test, and Lubricity Test were performed using the representative cutting samples from the offset wells. The testing used a combination of KCl & NaCl and a single NaCl, with an inhibitor combination added of polyamine, encapsulation, and non-ionic polymer blended with glycol to give the optimum results. This fully formulated HPWBM to provide the most effective inhibition and lubrication was tested and evaluated prior to drill the exploration campaign. The HPWBM with dual brine combination was successfully implemented in the well. The formulation facilitated the execution of the exploration well and provided good penetration rate, wellbore stability, and lubricity. There was an unexpected occurrence whereby the Driller Cyber System malfunctioned, causing the draw works to be unable to move and stay in the same position which suspended operation for 96 hours. However, the mud system proved to be stable during the troubleshooting of this problem. There was no issue related to the mud system during the drilling and casing job. The cementing job proceeded smoothly with no excessive cement required which meant that the well was still within acceptable hole-gauge range. No Non-Productive Time (NPT) was recorded related to the mud execution. By executing the HPWBM properly, the company saved around 7% of the planned mud cost to drill the section, from a reduced system maintenance of the HPWBM which required less dilution compared to a regular WBM. This paper shares the novel approach of using a brine combination formulation in designing the HPWBM system to provide a better result than the previously formulated WBM.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114509119","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":"Identification of Condensate Banking With Combination of Pressure Transient Analysis and Simulation Approach: A Case Study","authors":"A. Hudiman","doi":"10.29118/ipa22-e-151","DOIUrl":"https://doi.org/10.29118/ipa22-e-151","url":null,"abstract":"Gas – Condensate reservoir system would be more complicated regarding fluid effects. To understand the fluid effects of Gas – Condensate reservoir system, several studies have been carried out, but there is no type curve matching method especially for Gas-Condensate reservoir system. In general, we use a composite model in Pressure Transient Analysis to analyze Gas-Condensate system, but we are still unable to map the condensate banking boundary in the reservoir. In this paper, we will use a numerical model approach to understand Gas-Condensate reservoir system based on Pressure Build Up analysis. We use a simulator for modelling the near well bore condition by using local grid refinement, then perform history matching with Pressure Build Up analysis result. This method will give us a clearer reservoir description and path of the condensate forming as a condensate banking. We will focus on the well MTD-02 to get a better understanding of our reservoir. The results of our method show that our Gas-Condensate reservoir system is a lean gas system, with several behaviors as we can see from PVT data, PBU Analysis result, and from the Simulation Model. This method gives us the path of condensate banking, so we can prepare strategy to overcome this situation. Gas fields have characteristics that are affected by the gas components itself, namely dry gas, wet gas and gas condensate. Sometime we call dry gas and wet gas as conventional gas reservoir. There are obvious physical environmental differences between gas condensate reservoirs and other conventional gas reservoirs (Qianhua et al, 2020). Ahbijit (2015) has stated that the term of wet gas is sometimes used as more or less equivalent to gas condensates.The methods and development of the operations of each gas field type has its own uniqueness, especially gas condensate type that has characteristic of liquid phase (condensate) which will form when the reservoir pressure reaches below its dew point pressure along with the depletion of reservoir pressure due to production. One of the effects of liquid phase (condensate) in the reservoir is that it will reduce gas mobility near wellbore area and there will be slightly change of relative gas permeability, so that gas production will not be optimal. The effect can reduce the well potential between 0% to 50% (Giamminonni et al, 2010) Matindok Field is gas field producer located in Banggai Districts, Central Sulawesi, Indonesia. The production zone comes from Minahaki Formation, which is limestone. Since the beginning of production, condensate has been produced with average Condensate Gas Ratio (CGR) of around 13.5 STB/MMSCF and Gas Liquid Ratio (GLR) of around 73000 scf/STB with 48-50 API of condensate. Currently, Matindok Field’s average gas production is around 40 MMSCF/D. Moreover, with these parameters, Matindok Field is included as a gas condensate reservoir. To keep gas production stable, we conducted well surveillance campaign each year to do pressur","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128223704","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 Holistic Approach of New Amine Solvent Evaluation and Transition in Banyu Urip Acid Gas Treatment Unit, From Study to Field Implementation","authors":"S. Kaswan","doi":"10.29118/ipa22-f-83","DOIUrl":"https://doi.org/10.29118/ipa22-f-83","url":null,"abstract":"Banyu Urip Acid Gas Treatment Unit consist of Acid Gas Removal Unit (AGRU), Acid Gas Enrichment Unit (AGE), Sulfur Recovery Unit (SRU), and Tail Gas Treating Unit (TGTU) where generic Methyl Diethanolamine (MDEA) solvent is chosen to treat acid gas with 45%-mole CO2 and 1.6%-mole H2S, however the proprietary amines may be substituted in the future with minimal design changes or modifications. As local industry has capability to produce formulated MDEA solvent, ExxonMobil Cepu Limited took the opportunity to perform the feasibility study of utilizing proprietary formulated amine for Banyu Urip AGRU and AGE system. This paper shares Banyu Urip Acid Gas Treatment’s holistic approach for a new solvent change from evaluation into real implementation while minimizing negative impact to existing operations. Several steps were carried out sequentially, starting from process simulation, pre-solvent selection, laboratory and material compatibility check to determine a suitable solvent and continued with field trial and optimization. Field trial was conducted by introducing new solvent into the AGRU and AGE system while the system was running with careful strategy to minimize process interruption. Subsequently, process parameter and field laboratory analysis were closely monitored and assessed to maintain stable operation. Throughout the field trial, all key performance indicator (KPI) parameters were within acceptable limits and no process anomalies, foaming issues, leaks, and other integrity issues identified. Despite amine solvent transition is practical in gas processing, such strategy should be considered from desktop process study to extensive laboratory works prior to field implementation. Good workmanship exhibited by all parties involved in this Field Trial resulted all the works carried out safely without major concerns. In this case, the amine solvent transition process will provide benefit for a continuous supply chain, cost optimization, and support domestic content enhancement and utilization.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132967404","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":"Success Story to Implement Well Operation and Operational Excellence By Maintaining Well Integrity and Production Optimization in Offshore Field","authors":"Eyinade Kila","doi":"10.29118/ipa22-e-39","DOIUrl":"https://doi.org/10.29118/ipa22-e-39","url":null,"abstract":"This paper describes the method to keep wells in operation according to industrial code and Well Integrity Management System (WIMS), in order to continue supporting gas supply and demand in the field,. It includes identifying tubing/ annulus communication, mitigating excessive annulus pressure, and corrective action against tubing casing leaks. In one of the wells in the field a leak was found between the production tubing and production casing (“A” annulus) and no excessive pressure from “B” & “C” annulus. There was no way to shut-in the well due to the field’s contribution to gas supply and demand. The well had to be operated safely by conducting annulus pressure monitoring, pressure limit calculation, regular bleed-off program, and modifying surface facilities. We provided technical recommendations, specified mitigating engineering solutions to reduce risks, and changed surface facilities to keep wells in operation. Based on job results, we operated “W” well safely with efficient technology, delivered fluid from 3 ½” production tubing to surface facilities, performed cost optimization, and minimized production loss. Furthermore, in this particular case no serious hazards occurred in offshore field conditions. The paper shares a well integrity implementation success story, methods, and detailed procedures to keep wells in operation in the offshore field by maintaining annulus casing pressure. We have done this method by efficient technology/ solution, with lower operating and construction costs, and with no production loss during operation.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122270642","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 Comprehensive Experimental Study on The Performance of Alcoholalkoxyl-Sulfate-Based Surfactant: A Case Study on Light Crude Oil Field A","authors":"E. Despriady","doi":"10.29118/ipa22-se-185","DOIUrl":"https://doi.org/10.29118/ipa22-se-185","url":null,"abstract":"Indonesia's crude oil production has been declining steadily. With the ever-increasing oil demand, the challenge of sustaining production urgently needs solutions. Chemical-Enhanced Oil Recovery (CEOR) is a tertiary recovery method involving the injection of chemicals such as surfactants. Surfactant flooding is a well-established method that has been proven to have a better sweep efficiency. The objective of this study is to examine the performance of surfactant X based on laboratory experiments. In total, 7 tests were conducted consisting of compatibility test, IFT test, thermal stability test, phase behavior test, wettability test, filtration test, and spontaneous imbibition test. Three surfactants were sampled for this study, named surfactants X, Y, and Z, all anionic in nature and possible to be extracted from natural resources. Crude oil with an API gravity of 44.4 (light oil) was used in the experiments. The study ultimately shows that of the three surfactants, surfactant X has the best performance. Specifically, surfactant X at concentration of 0.3% in 18000 ppm brine is considered the best formulation because it can reach ultralow IFT value, form a middle phase (Windsor type III), yield the highest contact angle decrease, pass the filtration test, and have the highest recovery factor in the spontaneous imbibition test.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130135514","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":"Analysis of Rock Permeability Variation and Sulfonated Surfactant Concentration in The Oil Recovery By Imbibition and Coreflooding Test in High-Temperature and Waxy Reservoirs","authors":"Y. D. Rendragraha","doi":"10.29118/ipa22-e-330","DOIUrl":"https://doi.org/10.29118/ipa22-e-330","url":null,"abstract":"Oil production of the mature field in Indonesia is decreasing sharply with one of the efforts to increase oil recovery by implementing Enhanced Oil Recovery (EOR) methods. EOR techniques have been used to minimize the amount of crude oil and petroleum that is left behind in underground reservoirs from conventional extraction methods. One of the proven EOR methods is surfactant flooding. The effectivity of surfactant flooding is influenced by various parameters. Rock permeability and the concentration of surfactant are some of the parameters affecting the oil recovery factor. Rock permeability could affect the effectiveness of surfactant injection performance in the reservoir. The surfactant concentration determination for the slug injection in the reservoir will give an optimum oil recovery by creating a low interfacial tension and microemulsion phase in the high-temperature and waxy reservoir. In this study, an imbibition and core flooding experiment were conducted in the laboratory to determine the optimum surfactant concentration to increase oil recovery with variations in rock permeability for a high temperature and waxy reservoir. In this experiment, sandstone with a permeability range of 5,000-10,000 mD was used with a synthetic brine solution (salinity of 18,000 ppm) that removes scale levels to control the precipitation problem. From the results, the imbibition using only synthetic brine gave only 40% oil recovery, while imbibition using surfactant X#3 solution produced 80% oil recovery. The core flooding experiment at a surfactant concentration of 0.8% with rock permeability of 6,000 mD and 10,000 mD gave the optimum recovery compared with using 0.6% and 1% surfactant concentration. The results gained from coreflooding experiments were 80% RF in 6,000 mD rock samples and 70% RF in 10,000 mD rock samples. In conclusion, surfactant injection using 0.8% concentration into 6,000 mD reservoir layer gave the optimum injection scenario into this reservoir.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130444598","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":"Application of SPE SRMS and Certification of CO2 Storage Capacity","authors":"B. Billingsley","doi":"10.29118/ipa22-bc-286","DOIUrl":"https://doi.org/10.29118/ipa22-bc-286","url":null,"abstract":"Assessment and certification of CO2 storage “capacity”, which is analogous to an oil or gas “reserve”, is an increasing focus area for those seeking storage and the investment community. The Society of Petroleum Engineers (SPE) 2017 CO2 Storage Resources Management System (SRMS) provides a classification framework to assess CO2 storage quantities which is likely to become widely adopted. Guidelines to support the SMRS are needed and expected during 2022. As companies in Indonesia seek recognition of carbon storage projects the complexities of the 2017 SRMS are discussed through theoretical and actual case studies. Specific technical issues with saline aquifer storage and depleted gas field storage differ but can largely be solved. However, the commercial requirements to mature “storage resources” to “capacity” are more complex. Both are discussed in this paper. A key criterion is the commerciality test required to move “contingent storage resources” to “capacity”. The commercialization pathway of CO2 storage projects will vary significantly between direct air capture (DAC), emissions reduction and third party CO2 disposal. In addition, the legislative framework in the host country or the investors country may have implications on what can be claimed as “capacity”. Developing the Indonesian Carbon Capture and Storage (CCS) sector depends on understanding current definitions of “capacity” and how future guidance, or investor requirements, may develop. The SRMS provides not only a framework for classification and certification, it can also be useful to expose successful strategies on the route to commercialisation.","PeriodicalId":442360,"journal":{"name":"Proceedings of Indonesian Petroleum Association, 46th Annual Convention & Exhibition, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129696514","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}