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Gender diversity and inclusion in the oil and gas industry has been widely promoted in the last decade to advance women in leadership roles. Following this, the SPE Java Section launched an initiative to encourage and empower women in the industry. The section held a webinar in November, which was moderated by Niesharsa Triaswari from BP Indonesia. In the webinar four high-profile women discussed and shared their leadership and experience in the oil and industry: Shauna Noonan, 2020 SPE president and director of artificial lift engineering at Oxy; Evita H. Legowo, general director of Oil and Gas Government of Indonesia (2008-2012) and professor at Swiss German University; Melanie Cook, president of ExxonMobil Indonesia; and Dian Andyasuri, president of Shell Indonesia. The opening session was led by Shauna Noonan, who shared her experience and first steps in the industry when she first came to Indonesia working for Chevron.
Wijaya, Aditya Arie (Halliburton) | Aulianagara, Rama (Halliburton) | Guo, Weijun (Halliburton) | Naibaho, Fetty Maria (Pertamina Hulu Sanga-Sanga) | Asriwan, Fransiscus Xaverius (Pertamina Hulu Sanga-Sanga) | Amirudin, Usman (Pertamina Hulu Sanga-Sanga)
In mature fields, pulsed-neutron logging is commonly used to solve for the remaining saturation behind the casing. For years, sigma-based saturation has been used to calculate gas saturation behind casing; however, the high dependency of sigma-to-water salinity of the formation, especially the low-dynamic range at porosity near 12 p.u., has proven to be challenging in low-porosity gas rock. A new measurement from the third detector from a multidetector pulsed-neutron tool (MDPNT) is proposed to provide a better estimation of the gas saturation in a low-porosity reservoir.
Two sets of independently measured sigma and the third detector were taken in a casedhole well, with a dual-tubing system of a long string and short string. For the third-detector measurement, the measurement was based on the ratio of the slow capture gate and inelastic gate component from the decay curve created by the long detector. This ratio can be used to detect gas in a tight reservoir with a minimum salinity and lithology effect. This data will then be used to calculate the gas saturation from the third detector, and the result is compared to sigma-based gas saturation.
At an interval where the porosity is above 12 p.u., the sigma-based gas saturation and MDPNT-based gas saturation are very much in agreement. However, in a low-porosity reservoir near 12 p.u. or below, the sigma-based measurement starts to show its limitation. Meanwhile, the MDPNT-based gas saturation clearly shows the remaining gas saturation where sigma-based measurements failed to detect it. The subsequent decision was made based on the log analysis result, and perforation was done at a potential interval based on the MDPNT result. The results from the production test confirm the MDPNT-based gas saturation with 700-Mscf/d gas production added.
This study showcases a new technology to solve a low-porosity gas reservoir issue where a sigma-based measurement underestimates the remaining gas saturation. Using two different measurements in the same well, the results from the MDPNT measurement demonstrated a better result compared to the sigma-based measurement in low-porosity rock.
The 2020 Presidential Award received by the SPE Bandung Institute of Technology student chapter marks the ninth consecutive award the chapter has received since 2012, with 6 Outstanding Student Chapter Awards and 3 Gold Standard Awards received earlier. Many events are held by the chapter to facilitate members with platforms to better themselves. Two highlight events held in 2020 are “exSPEdition” and “Integrated Petroleum Festival (IPFEST) 2020.” ExSPEdition is a field trip event series with a total of seven visits to oil and gas companies across Indonesia. It is further divided into regular field trips, Freshman on Field, and Big Field Trip.
Banyu Urip, which is the highest producing oil facility in Indonesia with 220 kbd, generates up to 40 MW electrical power to maintain production. Any power blackout results in significant production upset including high flaring. This is exacerbated by usually extended recovery time post power blackout due to complex electrical distribution system. The Banyu Urip facility has experienced production loss due to historical power blackout events, most recently in 2019. This paper provides a case study on optimizing load shedding and gas turbine fuel control system, which could serve as learning for other power generation facilities in various industries for designing a robust blackout prevention system.
An integrated blackout prevention system comprises of Electrical Control and Monitoring System (ECMS) as primary load shedding, Gas Turbine Generator (GTG) temperature peaking control, and backup load shedding by under-frequency protection relay is designed. All these load shedding layer of protection cover multiple blackout prevention scenarios or protection system element failure such as GTG trip, overloading, and ECMS failure.
Multiple parameter analysis and simulation were performed to determine characteristic of each protection layer. Turbine exhaust temperature response, load, fuel supply, as well as generator frequency are all taken into consideration for the integration of blackout protection layer.
Key factor for the seamless integration is timeline of each element to work and for backup element to activate. All must be done within GTG overload capability corridor.
ECMS load shedding system is put as the frontline to prevent overload in case GTG trip. As the backup layer, protective relay will enable under-frequency load shedding upon overload and GTG slowdown. GTG temperature peaking control and under-frequency set point are properly designed to ensure that the under-frequency relay is operating.
After implementing these optimizations, load shedding is proven to work very effectively and there has been some GTG trip events without blackout nor significant production impact.
Evaluation of system performance continues as Banyu Urip Central Processing Facility (CPF) operates. The results will be critical for reliability improvement as well as production continuity assurance. In other words, this also provides a best practice for blackout mitigation to optimize successful power generation facility operation.
Sajjad, Farasdaq Muchibus (PT Pertamina Hulu Energi) | Nugroho, Wisnu Agus (PT Pertamina Hulu Energi) | Chandra, Steven (Institut Teknologi Bandung) | Panaiputra, Harris Grenaldi (PT Pertamina Hulu Energi) | Nurlita, Dian (PT Pertamina Hulu Energi) | Towidjojo, Reynaldo Billy (Institut Teknologi Bandung) | Rahmawati, Silvya Dewi (Institut Teknologi Bandung) | Vico, Hendro (PT Pertamina Hulu Energi) | Wirawan, Alvin (PT Pertamina Hulu Energi)
Flow assurance has been a major problem in the development of a heavy oil field. It is not common that this issue has a multiplier effect from reservoir up to processing facilities, reducing productivity and in turn, increasing financial burden. Many of oil and gas operators in Indonesia have spent a lot of capital to deal with managing complex reservoirs with severe flow assurance issues, namely high water cut, excessively viscous oil and its effect on fluid flow.
Y Field has been produced for thirty years and currently produces 2800 BOPD with fluctuations in flow rate. This field is characterized by extreme oil viscosity, up to 4000 cP at surface condition, which leads to high backpressure while delivering fluid to pipeline system. This viscous oil creates unstable flow, causing unfavorable flow-pattern; slug flow to annular flow. As a result, the water and oil are not coherently arrived at the same time at receiving facilities, leading to highly frequent occurrence of oil-water slug phenomenon. Chemical injection efforts do not show significant impact toward the production, therefore an alternative approach is generated to address the production problem.
A new approach is presented in this publication to reduce the occurrence of severe slugging phenomenon by performing water blending scheme during fluid transportation. The idea is based on a hypothesis that performing forced emulsion of brine and heavy oil promotes dispersion of oil into small droplets which can be carried out by injected water under relatively low velocity of fluid flow. This idea is quite interesting since it is simple to perform, by only directing produced water from water zones below hydrocarbon bearing zone or by reactivating high water cut wells to the pipeline system.
In order to increase the efficiency of forced emulsion process, we approximated the minimum acceptable water cut to develop sufficient emulsion viscosity to prevent exceeding backpressure. Based on simulation using commercial software, the result shows that water cut should be maintained above 80%. A lower water cut will lead to high backpressure which will delay arrival time of oil for more than one day behind the water arrival. This result infers that one of the available solutions to handle severe slugging is by modifying water cut profile during hydrocarbon transportation. This approach gives a new insight into marginal field optimization.
The operator, rig contractor and services company formed a trilateral collaboration to plan the safe plug and abandonment of four onshore wells located in a densely populated region of Indonesia. These wells, located in scattered locations, posed a significant logistical challenge for project mobilization and moves between the wells. Well information was incomplete due to a change in asset ownership.
Some of the challenges faced in these wells were: Well integrity issues resulting from the presence of H2S and CO2 Sustained casing pressure Surface water safety Fluid losses
Well integrity issues resulting from the presence of H2S and CO2
Sustained casing pressure
Surface water safety
Personnel safety and future well integrity was crucial to this operation. Consequently, plans were developed to conduct the operation safely and efficiently, as well as to provide solutions that mitigated well integrity challenges.
The method adopted for this project was to approach this as an integrated project where the collaboration team was responsible for planning, executing, monitoring and closing out all segments of the project. Well information from the previous field operator was analyzed and a solution to safely plug and abandon these wells was created. Because inadequate well information posed a major challenge, the collaboration team planned multiple contingencies. An abandon-the well-on-paper (AWOP) workshop was organized to review and refine the execution plan.
An intelligent coiled tubing system, which could be used for simultaneous logging and pumping operations, was selected as well as an efficient and environmentally friendly mechanical pipe cutter that did not use explosives or hazardous chemical substances for tubing severance operations. The sustained casing pressure challenges (in previously fully cemented/non sealing annuli) were addressed by using advanced milling technology for section milling.
The early engagement plan enabled development of a project execution strategy that clearly outlined equipment mobilization schedules from various locations in Indonesia. Because of the collaborative projects structure, local personnel recruited for this project were quickly on boarded and integrated with the rest of the project team. This approach led to the safe and efficient execution of the plug-and-abandonment scope of work, with zero HS&E incidents and 167 perfect HS&E days during project execution.
Extensive testing of cement mix water was introduced to this project. The testing improved the cement design and enabled accurate plan transition times that reduced waiting on cement. Based on lessons learnt from the first well, extensive logging operations were performed to determine the formation temperature and specific leak locations in the casing. These pre-cementing logging operations helped in collecting accurate well temperature and pressure information that aided the design of cement recipes for the barriers placed in these wells.
Iskandar, Dedy (PHE – Operation & Production) | Hartawan, Iman B. (PHE – Operation & Production) | Soelistiyono, Dony (PHE – ONWJ) | Soetjipto, Hermanto (PHE – ONWJ) | Irfan, Fahmi (PT Trihasco Utama)
Pertamina Hulu Energi - Offshore North West Java, also known as PHE-ONWJ, owns 426 subsea pipelines from which only 185 are active operating to support PHE-ONWJ's production activity and the rest, 241 pipelines, are inactive which status is either remain idle or being preserved. Need to be noted that 67% or 284 pipelines aged more than 30 years, which is more than its design life. From which, 120 pipelines are still actively operating distributing fluids such as Oil, Gas and 3-phase. Multiple events of leak have occurred which implicates PHE-ONWJ's production activity.
Based on observation, more than 90% of leak events occurred, were caused by internal corrosion. The specific cause is that PHE-ONWJ pipelines transports such fluids that contains corrosive agents such high CO2 content, sands or solid particles, SRB and water.
The existing integrity management plan such as in-line inspection, fluid sampling, chemical injection and others have been performed onto several pipelines. However, since the size of PHE-ONWJ's pipeline network facility is complex and massive, to perform in-line inspection to all pipelines is not economically beneficial. Moreover, performing in-line inspection induced high risk and not all of the pipelines are piggable either because of its design or operating condition. Therefore, by considering such conditions mentioned previously, an effective and efficient pipeline integrity management developed based on corrosion rate prediction from topside piping within corrosion circuit with pipeline.
It is clear unwanted event such leak shall interrupt PHE-ONWJ production activity, moreover the age of most pipeline facility are old which means it has probability to fail, even though not all leak event associated with the age of the pipeline. To maintain and predict failure event such as leak or even rupture, a corrosion model has been developed. This model is constructed from combining several parameters which are; fluid sampling, In-Line Inspection of several pipelines with different services, Topside piping inspection data, Operating history and pipeline design data. The model generated in the form of an equation that associates topside piping corrosion rate and pipeline corrosion rate which both were obtained from inspection data and the boundary is operating and design history of the pipeline itself.
The developed model or equation is continuously validated as In-Line Inspection (ILI) performed onto several pipelines that previously has been assessed by using the internal corrosion model. Since the model developed, an accuracy ranging from 80-99% has been achieved in predicting maximum internal corrosion rate of PHE-ONWJ's pipeline. Which later on, this corrosion model become as a basis in determining pipeline's integrity status, remaining life and assisted in assessing the pipeline risk which outcome are mitigation / action plan. All of these were obtained by only using topside inspection data.
Even though the corrosion model developed is able to represent PHE-ONWJ's pipeline internal corrosion rate, further study should be done to be applicable onto other facility or even company pipelines. Therefore, a joint study may be made to create such corrosion model for pipelines. The goal is to have an in-depth approach in managing matured and unpigable pipeline integrity that operates across the world with such effectiveness and ensure all stakeholders that the pipeline is safe to operate.
The YC13-1 gas field commenced sales from offshore platforms to Hong Kong and Hainan Island in 1996. Following 22 years of continued production, the field depleted naturally to approximately 10% of the original reservoir pressure, with most wells producing with tubing pressure varying from 150 to 200 psi. The field is underlain by a relatively small water aquifer, which has caused water cut to increase marginally in a few wells and has affected performance in lower-pressure gas wells. The installation of a gas injector helps to reduce backpressure on producing wells, thus providing more energy to lift water from the wellbore. This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196440, “Giving a Boost to a Low-Pressure Gas Well by Installing a Gas Ejector,” by Ping Wei and Brian Macdonald, SPE, KUFPEC, prepared for the 2019 SPE Asia Pacific Oil and Gas Conference and Exhibition, 29–31 October, Bali, Indonesia. The paper has not been peer reviewed.
Noviaris, Ahmad Burhan (PT Pertamina EP) | Syarif, Mustafa (PT Pertamina EP) | Murdiansyah, Warnandes Ambar (PT Pertamina EP) | Pramono, Reza Yudha (PT Pertamina EP) | Nugroho, Sapto Edi (PT Pertamina EP)
Pertamina EP with North Kedung Tuban structure is located in East Java Indonesia. The drilling target is to produce gas from "Kujung" carbonate formation. The characteristic of this carbonate are vugular rock which caused total loss circulation, contain high concentration H2S and 20% CO2. Conventional curing loss methods such pump Lost Circulation Material (LCM) with various type, carbonate cementing and blind drilling, were not the good option since after loss circulation occur, gas kick immediately come up.
To encounter this situation, Floating Mud Cap Drilling (FMCD) technique with sandwich system was applied. This method used Rotating Control Device (RCD) as surface barrier and multiple treating line tied to the annulus casing valve to pump down sandwich. While blind drilling performed, water pumped down through drill string and sandwich system fluid pumped through annulus. Sandwich is a combination of water + kill mud + water and so on. Volume, Kill Mud Weight and time delay for pumping were obtained from previous well data and observations until effective parameters were obtained during blind drilling.
Sandwich fluid purposed as hydro static barrier to overcome gas influx come up to surface during blind drilling. To help good hole cleaning, high viscosity mud pumped frequently through drill string. When TD reached, sandwich system continue applied until BHA pulled inside casing. To accommodate tripping inside casing, change of RCD rubber element and RIH completion string, Downhole Casing Valve is attached in previous casing as mechanical barrier. As a result, the well completed with no gas kick occur while blind drilling and completion string placed as purposed accordingly. Furthermore, good communication between all personnel involved are necessary.
This paper contains the Lesson Learned of FMCD application which is effective and efficient proven in NKT-001 and NKT-001TW well, with the drilling time and cost of hole section 8-1/2" 80% lower than conventional methods.
Indonesia is home to numerous oil and gas fields, and upstream oil and gas activities are integral to the country's economic growth. Here are the key regulatory changes in response to the COVID-19 pandemic affecting Indonesia's oil and gas sector. Aerial surveillance of oil and gas operations can help in decision-making and lead to quick and appropriate responses to deal with potentially detrimental matters. Aerial surveillance of oil and gas operations can help in decision-making and lead to quick and appropriate responses to deal with potentially detrimental matters.