PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
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.
This paper describes an efficient approach to evaluate waterflood connectivity performance in complex compartmentalized reservoir, the objectives are to increase the oil production performance and manage mature fields effectively, and also to enhance ultimate recovery in the long run. It is also very useful to get better understanding of detail reservoir characterization, reservoir internal architecture, reservoir distribution, pressure monitoring and subsequent water flood sweep pattern efficiency. Multi-disciplinary methods applied to maximizing all of data and create strong analysis. The first phase is deep sub-surface analysis in property distribution, simultaneous inversion, 4D time lapse seismic and sweep pattern analysis, those analysis have been done to get comprehensive interpretation of reservoir characterization and waterflood monitoring. The second phase is tracer injection, we implement tracer in several wells to ensure connectivity from injector to several producers are efficient and optimal. These methods were performed for several regions of this area which contains a large number of well, nearly 200 wells consist of vertical, deviated and horizontal wells. Reservoir distribution in Windri area interpreted as stacking channel with high sinuosity geometry. This reservoir consists of predominantly of marginal marine claystone interbedded with deltaic sandstones, thin limestone and coal. Bio-stratigraphic analysis from cores shows that the reservoir was deposited in estuarine setting, interrupted by a brief shallow marine incursion. Seismic amplitude mapping at the upper base Gita horizon reveals a system of meandering channels. Compartmentalised reservoir in Windri area divided into 5 sweep pattern to make analysis more detail and accurate. Each of compartment have different characteristic, this is the challenging part in Windri area. East of windri area channel divided into 4 channels and it shows the evolution and movement of the channel that can control the property distribution and reservoir connectivity. Group two shows good result from tracer injection and it is supporting the interpretation of reservoir distribution and characterization within the area. Integrated 4D time lapse seismic generate pressure monitoring movement from each of waterflood phase. The results of this integrated study implementation are excellent, the ineffective water injection pattern now become effective, there is no unavailing injection well, every pattern is connected and link to each other, so that we can achieve our goal to enhanced recovery factor from 16% to 20%. Reservoir characterization using multi-discipline method reduce uncertainty of heteroginity sand and fluid prediction. Integrated waterflood analysis has been implemented for prospect generation, production optimization and overcome pressure degredation in this area.
This paper covered success collaboration between sub-surface and surface engineer in managing mature offshore oil field in Asri basin, Southeast Sumatera, Indonesia. The main objective was to maintain oil production rate and increase ultimate recovery in the most efficient way, technologies that applied strictly selective to minimize risk while optimize oil production. Common problem faced are extremely high water cut and high operating cost due to massive artificial lift application.
The three effective tailored methods in this paper are: (1) Determining residual oil volume and locating the position. Material balanced calculation and core analysis are the tools to determining residual oil volume, while tracer test conducted in order to determine the location and distribution of the oil remained. (2) Surface facilities assessment, facilities are ageing and need to refurbished/replaced after 27 years of production, it creates limitation in operation area. (3) Potency screening, in this phase we focused more on technical difficulties assessment, both sub-surface and surface (from method 1 and 2) result analysis are combined to determined technology selection. After that we put into action, and do evaluation on cost spending and production performance.
Efficiency is the key issue in mature field redevelopment, solid collaboration between sub-surface and surface team lead to satisfying result to reduce production decline. Several case studies have been included in the paper to highlight the detail project: (1) Idle wells, to increase production it is very important to increase well count, the wise way is by utilize existing wells in idle condition. Mechanical failure, water out, formation damage, low potential, etc. are cause of idle wells, in the last 3 years 13 wells successfully back to production. (2) Modified completion fluid, one of technology applications with ‘breakthrough’ result. In depletion drive reservoir we found lot of residual oil potency that can't be sweep, the solution is to reduce oil viscosity around wellbore and increase the mobility using modified completion fluid, and the result is beyond expectation. (3) Water injection redirection, based on performance evaluation and tracer injection analysis, several injectors is ineffective due to reservoir connectivity and mechanical issue, this project creates new sweep pattern and successfully increase recovery factor. (4) Mechanical loss handling, we found big losses contribution from tubing leak, after laboratory and field analysis losses can be reduced.
Technology and integration of sub-surface and surface capabilities are vital to unlocking the full potential of mature assets and achieving higher recovery factors. Application of the three tailored methods was considered as an appropriate way to approach and manage a complex mature field redevelopment.
The 34-X sand is a solitary sand reservoir and locally sinuous sandstone body. This reservoir is displaced by major normal fault zone known as the Widuri Fault that divided in two contrast areas of 34-X facies and production characteristic. The objective of this paper is to present how the combination drive reservoir redevelopment project was planned, extensive evaluation process has been made, and successful cases in enhancing reservoir ultimate recovery. The solution for this title is multi-disciplinary approach to create sharp analysis. The first step is numerical calculations of material balance to determine oil-in-place in a reservoir and to predict the future performance, this phase is tricky due to multi-driving mechanism reservoir behavior, therefore material balance analysis need to be supported by deep sub-surface analysis in property distribution on second step. This part simultaneous inversion, 4D timelapse seismic and sweep pattern analysis have been done to get comprehensive interpretation of reservoir characterization and reservoir connectivity monitoring. The third phase is supporting analysis by tracer injection, we implement tracer in several wells to ensure connectivity of the reservoir, and to evaluate injection performance. The last phase is technical difficulties in operation area, complex reservoir evidently cause complex operation difficulties, sand problem, formation damage, tubing leak, water out, plug-up injector well, etc. are problems we have to deal with. From reservoir pressure data distribution, surface gas-oil ratio, water production, and well behavior concludes that 34-X is combination drive reservoir (water drive-solution gas drive) and based on fault analysis we divided into two areas east and west, 34-X West area sandstone body is straight, with approximately 100-300m wide and 8m thick. The western part water cut is over 90%, this indicates the conduits for preferential water flow has established. From material balance calculation OOIP estimated 16.3 MMSTB. The eastern part of the 34-X sand appears to be isolated from western portion of the channel by a fault with a throw of 90 feet. The eastern portion of the widuri field is influenced by a partial water drive, indicated by high water cut histories. However the water drive is weak, the average pressure has declined to 520 psi, estimated OOIP 56.2 MMSTP. Before the redevelopment project recovery factor is 22%, and increase significantly to 27.4% simultaneously with oil production rate increase up to 40%. Dominantly pressure-depletion drive during hydrocarbon production in 34-X sand in west area occur since that area provide poor connection to an aquifer and for east area of Widuri Fault condition is limited aquifer. The water cut of production in 34-X sand well varies across the axis of the sandstone body, it caused by controlled by internal heteroginity.
Afi, F. N. (CNOOC SES Ltd) | Gunawan, H. (CNOOC SES Ltd) | Widiatmo, R. (CNOOC SES Ltd) | Waskito, L. B. (CNOOC SES Ltd) | Nugroho, P. (CNOOC SES Ltd) | Luthfan, M. (CNOOC SES Ltd) | Prayogo, R. (CNOOC SES Ltd) | Suryana, A. (CNOOC SES Ltd)
Dealing with mature offshore oilfield has complicated problems both surface and subsurface. In the reservoir condition high water cut wells make some bad impact in the production stages. Liquid handling facilities, tubing pipeline erosion, broken sand control, and high power consumption are several problem caused by high water cut wells. WW is an offshore oil field which has developed since 1990s with OOIP 758 MMBO. This reservoir was divided into several layer, 33 series is depleted reservoir with water injection since year 2000s (RF 23%) and 35 Series has strong water drive as its driving mechanism (RF 56%). Almost 85% of the oil wells is producing with water cut more than 97%. Increasing water cut or even watered out phenomenon was frequently happen during production stage, some of this problem was happen after well intervention such as after pump replacement. This paper will show the successful case of decreasing water cut significantly from WW D-29, WW H-12, II A-22.
Laboratory test was firstly done to check the compatibility test of the rock with modified completion fluid. This chemical was mainly works as phase change water control and oil stabilize well for completion fluid. It was pumped simultaneously with regular completion fluid (filtered drill water and additives). Killing well was mandatory procedure when shut in wells will be repaired. GGR team supported by Production and Workover Team did integrated study to choose the chemical and well selection based on some criteria.
WW D-29, WW H-12, and II A-22 are wells which have implemented modified completion fluid treatment. Those wells are produced from sandstone reservoir and drilled more than 10 years ago. During production period, water cut was significantly jumped due to several reason, such as pump replacement job, re-start up after the well trip off, etc. The result of the project were very excellent, WW D-29 (from 98% to 86%, gain +/− 180 bopd), WW H-12 (from 80% to 40%, gain +/− 250 bopd) and II A-22 (96% to 75%, gain +/− 130 bopd). These result give a lot of impact of increasing oil production in WW Field.
This paper will elaborate how to solve the problem in offshore mature oil field special case for high water cut wells using modification of completion fluid treatment. We have succeeded increasing oil reserves.
Summary In the development stage, the identification of thinly interbedded sand bodies has brought great challenge to seismic technology. Through comparison, it's found that the slices of zero phase had a certain advantage in the identification of thin sand body morphology. This method was applied in the deep layer of Bohai Bay, East China, which identified three-stage gravity flow thin sand bodies effectively. Introduction The development of seismic attribute slice technology has played an important role in the identification of thin sand body distribution. The geological body cannot be identified in the vertical with seismic, can be possibly identified in the plane taking the advantage of lateral resolution.
Tawekal, Ricky L. (Institut Teknologi Bandung) | Shanti, Parama (Institut Teknologi Bandung) | Kurniawan, Dwinanto B. (PT. Bina Rekacipta Utama ) | Arifin, Muhamad (PT. Pertamina Hulu Energi) | Zen, Doni (PT. Pertamina Hulu Energi) | Haryanto, _ (Ministry of Energy and Mineral Resources Republic of Indonesia) | Gumilang, Fentarie (Ministry of Energy and Mineral Resources Republic of Indonesia) | Banarwoto, _ (Ministry of Energy and Mineral Resources Republic of Indonesia)
Many offshore platforms have been developed in the offshore fields in Indonesia since 1969. National authorities in Indonesia stated that the existing platforms required the performance of underwater inspection on a regular basis. However, underwater inspections are very costly. Hence, this paper proposed Risk-based Underwater Inspection (RBUI) analysis as a highly effective method of conducting underwater inspections. The analytical approach was adopted from the American Petroleum Institute Recommended Practice for Structural Integrity Management of Fixed Offshore Structures in which a mix of quantitative analysis and qualitative analysis methods were used. The analysis generated the Probability of Failure (PoF) and the Consequence of Failure (CoF) that were subsequently required to determine the risk level of a platform. Additionally, the exposure level was also categorized for each platform based on its consequence category and life safety aspects. The usage of a combination of risk levels and exposure categories resulted in different inspection intervals for each platform. In this study, only characteristic factors were used for the PoF calculation. The condition factors were accounted for in the anomaly treatment. Hence, the RBUI analysis for 14 fixed platforms in West Madura Offshore resulted in an inspection plan that accentuated safety, but also had a longer interval when compared with the previous time-based methods.
The first offshore platform in Indonesia was built in 1969. Since then, there was a tremendous increase in the number of offshore platforms. Previously, based on Minister of Mining Regulations no. 05 /P/II/PERTAMBANGAN/1997 (1977), Indonesian authority necessitate regular inspections of all oil and gas offshore platforms in which minor, major, and complete inspections require annual, biennial, and four-year inspection periods, respectively.
The decline in oil prices since 2014 has forced most oil companies to cut costs. Indonesian companies are not an exception to this matter. The implementation of the risk-based underwater inspection (RBUI) is an alternative to traditional cost cutting methods in underwater inspections. Therefore, a new regulation recommends instead of the conventional time-based method, the inspection should be performed by a risk-based method that considers the risk level of the offshore platforms.
To help with this difficulty, a cost-effective method has been proposed to boost the hydrocarbon recovery by optimizing well locations through the Simulated Opportunity Index (SOI). SOI is an intelligent method to identify zones with high potential for production which is empirically calculated from basic rock and fluid properties, and from reservoir pressure as its energy capacity. In order to obtain the best results, the original SOI formula (Molina et al., 2009) was extended to both oil and gas fields. Based on this modified SOI formula, a software program has been developed to locate the best well locations considering multilayer, existing wells, and fault existences. This paper describes how the SOI software helps as a simple, fast, and accurate way to obtain the higher hydrocarbon production than that of trial-error method and previous studies in two different fields located in offshore Indonesia. On one hand, the proposed method could save money by minimizing the required number of wells. On the other hand, it could maximize profit by maximizing recovery.
Asri basin has been on producing since July 1989, currently there are 9 fields has been developed with strong water drive reservoir driving mechanism characteristic. Peak production was 196,000 bopd, presently producing 34,000 bopd with water cut of 99 %. Challenge faced in the studies had to deal with mature reservoir, declining production, depleted reservoir pressure, unrealistic recovery factor and the need to enhance asset value. Beyond that complexity, commercial challenge in rejuvenating the field becoming more critical due to falling oil prices.
This paper present how integrated evaluation of mature offshore oil field performance and investigated various scenarios could add more value to the asset. Water flood, water shut off, and single field revitalization project has been implemented and it shows satisfaction result in reducing and maintaining production decline rate even increasing oil production volume. Recommendations also made to sustain and gain oil production by implementing successful projects to other field and also trying to implement Polymer Injection pilot project in Indonesia.
The important thing in revitalizing a mature field is to define a customized asset evaluation approach to managed large amounts of data and identify the most important mechanisms in creating value-added solutions, while minimizing costs. The team captured this through innovative systems planning and operation, displacing the traditional lab-to-field R&D search in that multiple options were generated from within functional technology contributions.
As expected, the results of full project implementation are satisfying. Depleted reservoir problem in major field producer has been solved by water flood project, the pilot project has been conduct in 1999 and shows great result in increasing oil production rate, within 2 years the oil production rate increase from 2,000 bopd to 12,000 bopd. Another project has been implemented in this major field is facies re-analysis, from this analysis new map are created, therefore new point of view can be extracted to support more comprehensive analysis, and the new analysis are very useful to gain oil production. Marginal field also part of the revitalization program in Asri Basin, in 2012 rejuvenation project has been conducted, and the result shows 4 times oil rate incremental, from 264 bopd to 908 bopd. One of other successful project is water shutoff, 2 wells are implemented for this project, and it can reduce water cut up to 17%, from 99% to 82% water cut. Those successful projects will be implemented for other field in Asri basin North Business Unit Area to Sustain and Gain Oil Production Rate.