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Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Recently in Indonesia are experiencing various of revision and improvement in the regulations, related with the oil and gas industry activity, this kind of situation certainly will impact to the investment atmosphere in the Indonesia oil and gas upstream. International Oil Company and the Government has different point of view related to contracts in PSC. Several analysis or study has been done by institutions and individuals through articles or papers on the comparing for the terms and conditions of a contract with different country. But not many have discussed particularly about the general change of PSC in Indonesia.
This study will compare the historical of Indonesia PSC generations from generation I (1966) until the recent fiscal terms of gross split (2017). Those terms will be compare by using a hypothetical block to modelize the PSC block in Indonesia, which consist of several field. Some assumption also will be used for each field with different peak rate, development scenario, capital variable cost ranges, operation variable cost ranges, which those range data are expected still within the range of most likely consist parameter for PSC block in Indonesia.
This study purpose is to analyze if the Gross Split mechanism is more attractive or equal the PSC Cost Recovery. The result of this study shown that the gross split PSC refer to the Minister of Energy and Mineral Resources no.52 year 2017 is still attractive to the investor from the contractor take perspective. Eventough with the PSC Cost Recovery mechanism the contractor feels more secure for the cost that can be recover from the oil and gas that produces, as part of cost recovery. If the application of Gross Split is clear enough from the regulation, tax, assets rent and others, surely this mechanism can attract more investor to do exploration and development in Indonesia.
Regardless of the political and strategic interests of the Indonesia government or the National Oil Company, the results of this study hopefully can be useful for the professional, educational institution, and government for lesson and learn. How the fiscal term can be impact to the government take, contractor take, cost recovery also the production target related with reserves replacement.
Oil and gas production systems are complex and usually consist of several production elements and corresponding models: (1) reservoirs modelled with reservoir simulators using geological and fluid data, (2) wells and surface production networks modelled with flow assurance applications, (3) surface processing facilities modelled in process simulators and (4) economic models. The traditional approach ("silo" approach) consists of modelling each part of the system independently from the others without considering upstream and/or downstream interactions. Integrated Asset Modelling (IAM) is a maturing solution incorporating effects of all the elements of an asset. This paper shows the benefits of successful IAM implementations in four highly complex and technically challenging assets around the globe.
IAM aims to bring together all models of the value chain, from the reservoir to the point of sales. It enables us to perform numerous sensitivity analysis by changing any parameter across the value chain and investigate its influence on the entire system. The presentation concludes with guidelines and best practices for IAM implementation. It especially focuses on three very important issues faced when dealing with IAM: (1) software and model integration, (2) PVT consistency across the value chain and (3) optimization.
Several case studies from the industry are used as illustration: diluent injection optimization for a heavy oil field in the North Sea, integration of reservoir and process models for a complex offshore multi-field asset in Indonesia, production allocation for an onshore multi-field asset in South America and API blending optimization for a multi-field asset in Middle East. The different case studies show that benefits of implementing an IAM approach can be significant and immediate: higher production, lower OPEX or better information for further CAPEX.
In the current market situation, IAM approach is a cost-effective solution to optimize oil and gas production. By bringing together existing information and models from all parts of the production system, IAM breaks barriers between disciplines and enables an asset-scale overview that leads to more informed decision-making and ultimately higher profits for operators.
The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.
Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field.
The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields.
With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation.
This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields.
The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.
It has been recognized from the early stages of exploration in the 1980s that gas bearing reservoirs with condensates were located at depths of approximately 4,000 to 5,000 feet in parts of the Pattani Trough, Gulf of Thailand. However, even though the entire pay window is evaluated for each prospect area, no regional study on the shallow hydrocarbons has been made due to the majority of hydrocarbons residing in deeper zones. In the Gulf of Thailand there are two major Cenozoic sedimentary basins, the Pattani Trough and the Malay Basin. In the Pattani Trough, commercial production started at the Erawan gas field in 1981 and subsequently more than 20 oil and gas fields have been discovered and have continued producing hydrocarbons at the current date.
The Pattani Trough is a rift type-sedimentary basin and the maximum thickness of sediments is more than 10 km. The geological column is divided into five sedimentary units from Sequence 1 to 5 in ascending order. Two major unconformities are identified: one is called the Middle Cenozoic Unconformity (MCU) and the Middle Miocene Unconformity (MMU). The latter unconformity is located between Sequence 4 and Sequence 5. Oil and gas are mainly trapped in fluvial to deltaic sandstones of Sequence 3 and Sequence 4 located between 5,000 to 9,000 feet. Structure is characterized by many normal faults.
Based on the more than 800 wells and 3D seismic data, detailed studies on well correlation, dip-meter, micropaleontology, regional isopachs and sand-shale ratio were made and it was concluded that the these shallow hydrocarbons are closely related to the incised valley-fill sediments located in the lower part of Sequence 5 immediately above the MMU. Hydrocarbons generated in the deeper levels have migrated upward through faults and moved into and are possibly trapped in the incised shallow reservoirs. Previous wells were drilled in the highly faulted areas where most of the oil and gas is trapped and there are no wells drilled in the monocline areas. Although the detailed areal distribution of the incised valleys is not clearly identified, hydrocarbons are expected in monocline areas if conditions are favorable.
Since the MMU is widely developed in the South East Asia, this type of exploration concept focusing shallow hydrocarbons can be applied not only for the undrilled area of the Pattani Trough but also for the mature sedimentary basins such as the Malay and Nam Con Son basins.
Jong, John (JX Nippon Oil & Gas Exploration Corp.) | Barker, Steven (JX Nippon Oil & Gas Exploration Corp.) | Kessler, Franz L. (Petrotechnical Inspection (M) Sdn. Bhd. currently Lundin Malaysia BV.) | Tran, Quoc Tan (JX Nippon Oil & Gas Exploration Corp.)
The Bunguran Trough (BT) covering Sarawak Deepwater Block 2F shows a number of largely parallel trends of folded Neogene anticlines, with reverse faults and thrusts in the cores, and blind thrusting and folding in the upper section of the individual mapped anticlines. The Bunguran Fold Belt (BFB), comprising the deepwater deposition setting of the Rajang Delta (synonym: West Luconia Delta), has been historically compared by explorationists/geologists with the Sabah Fold Belt, and accordingly a genetic model related to gravity sliding had been advocated.
Although multiple-zone, downhole sand-control tool systems have been in use since the early 1990s, these systems had been designed for jobs requiring low-pump-rates with low-pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oilfield. Although these jobs are becoming more common, most of the completions have been limited to four or five discretely treated zones.
This paper presents a case history from Indonesia in which a high pump rate, high differential pressure-rated single-trip multiple zone-sand control tool system was capable of treating six discrete zones in an offshore deployment. The challenges for this completion were numerous. Manufacturing lead time was very short, and the system would have to be adapted to the unique requirements of the completion design and the use of new components. Since the proppant and pump rating limit testing for these systems had been based on five zones, complicated calculations and extrapolations had to be used to ensure that the crossover tool would survive the erosive effects of treating six zones.
To provide assurance of the service tool’s elastomeric seal integrity, a testing program was executed between treatments to provide tracking and verification of conditions. Procedures and equipment would be in place to replace the service tools, if any leaks were evident. Since system installation experience was limited in this area, gathering sufficient knowledge and experience for system deployment had to be addressed quickly. This would require sharing of lessons learned, use of experienced personnel from previous installations, and conducting of detailed training discussions between subject matter experts and service personnel. Deployment challenges and solutions, successes experienced at the well site, and the actual performance of the operations will be detailed in the paper.
Production and transportation of high paraffinic crudes in offshore fields is a major flow assurance challenge for the oil and gas industry. The challenge is particularly great when the sea water temperature is lower than the pour point of the crude being transported. This paper describes flow assurance issues that have been addressed for handling subsea transportation of paraffinic crudes in Indonesia. Pour point depressant (PPD) has been continuously injected into the oil production manifold handling high pour point crude to cause the formation of a sufficiently weak gel in the subsea pipeline to enable restart after a long shut-in. Currently, production of a condensate has started that blends with the waxy crude. The PPT (pour point temperature) and live gel strength of the condensate and crude oil blends are significantly lowered and require less or no PPD injection. Since the PPD injection involves significant operating costs, this paper describes the joint effort by operations and technology staffs to develop a reliable method to optimize the PPD treating rate on a daily basis. PPTs and live gel strength were measured in the in-house laboratory using a densitometer (identical to the one used at the field lab) and a rheometer respectively. An equation was generated by fitting a smooth curve to correlate PPT with live gel strength. This equation provides a convenient method to estimate live gel strength based on onsite PPT measurements. Considering that the crude oil and condensate blend are changing over time, routine monitoring of blend PPT using a reliable and simple onsite method and estimating gel strength based on PPT results, enable identification of the optimum PPD dosage by the operations staff to ensure flow assurance and minimize treating costs in a timely fashion.
This analysis shows the important contribution that stranded gas from central Asia, Russia, Southeast Asia, and Australia can make in meeting the projected demand for gas imports of China, India, Japan, and South Korea from 2020 to 2040. The estimated delivered costs of pipeline gas from stranded fields in Russia and central Asia at Shanghai, China, are generally less than delivered costs of liquefied natural gas (LNG). Australia and Malaysia are initially the lowest-cost LNG suppliers. In the concluding section, it is argued that Asian LNG demand is price sensitive, and that current Asian LNG pricing procedures are unlikely to be sustainable for gas import demand to attain maximum potential growth. Resource volumes in stranded fields evaluated can nearly meet projected import demands.