bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemical Stimulation Success Stories – A New Integrated Process to Support Massive Aggressive Strategy in Complex Operation of World Largest Steam Flood Field
Authors: Terosela Andro , Etri Yulmi , Efendi Faried , Pramono Wasis
Published: October 2023

Drainage Field is the largest active steam flood in the world comprising 7,000 active producing wells, 1,250 steam flood patterns and encompassing 21,000 acres in the Sumatra, Indonesia. The Drainage Field produces 60,000 BOPD and 10,000 optimization jobs are executed annually to support base production. Drainage produces rich carbonate formation water and high asphaltene oil which generates solid deposition inside the wellbore due to high temperature exposure as an impact of steam flooding. Solid deposition extracted into carbonate scale and congealed oil would lead to plugging effect on influx from the reservoir into the wellbore, causing faster production decline. Chemical stimulation well intervention plays main role to improve well productivity by removing solid deposition in the wellbore. Aligning with the massive and aggressive strategy in Drainage Field, there are too many challenges in increasing the execution level like artificial lift assurance, location preparation, resource optimization, plant operation, and sampling analysis capability.

This aggressive scenario requires an excellent and integrated process in delivering effective well intervention program which managed by the following improvements:

Artificial Intelligence (AI) assisted well intervention candidate selection process. A systematic value-based well intervention schedule and prioritization process. Artificial lift assurance process. Effective well site readiness & preparation, include mitigating rainy season challenges. Comprehensive monitoring dashboard. Synergic resources support, i.e.: rigs, chemical pump, surface unload tank, vacuum truck, and heavy equipment support. Pre and post job fluid analysis supported by dedicated lab to optimize chemical unloading process. An integrated web-based tool to monitor the overall process of chemical stimulation well intervention job. Lookback process.

Value creation:

Multi-function collaboration effort i.e.: increased success rate by 70 %, reduced suspended execution by 70%, idle time by 30%, increase plant acceptance rate by 60%, and shorten acid unloading time by 50%. Increased job execution rate to ~200%. Improve Drainage field base production decline rate, ~15% better. Provides additional ~3.000 BOPD annual production gain correlates to 77 MMUSD additional revenue.

The effort contributes a significant impact in the way of company should run a massive activity strategy as well as providing an important value to company in optimizing performance.
Analysis of the Oil Distribution and Evolution Characteristics of Gulong Shale Oil Plays Using Nuclear Magnetic Resonance (NMR)
Authors: Xu Fei , Jiang Hanqiao , Zhou Kaihu , Wang Yong , Zhang Miao , Liu Ming , Li Junjian
Published: October 2023

The Gulong shale oil plays is a shale reservoir characterized by well-developed fracture bedding planes. To study the distribution and evolution characteristics of Gulong shale oil, namely, the size of the oil-bearing pores, the content of oil in organic and inorganic pores, and the oil distribution evolution during gas displacement, could contribute to the development of shale oil. In this study, the one- and two-dimensional NMR spectra were used for the above studies.

Two Gulong shale dry cores with different fracture bedding characteristics were tested in the experiments. NMR T1-T2 and T2 maps of the cores are scanned under dry and kerosene-saturated conditions. Gas displacement experiments were conducted under different injection pressures. NMR scans were taken at the end of each displacement stage. The oil distributions in the organic and inorganic pores were characterized through the T1-T2 maps. The oil distribution evolution under gas displacements in the shale cores were characterized by NMR T2 distributions of all stages.

The T1-T2 map results showed that the oil in organic and inorganic pores was presented in two distinct regions with different T2 value intervals. The oil in the organic pores were residual heavy oil components and saturated kerosene, which were distributed in small T2 value interval and different T1/T2 value interval. The oil located in the inorganic pores was mainly saturated kerosene. Mobile oil exists in the inorganic pores and was presented in the largest T2 value interval of all oil phases. The T2 distributions showed that there was a threshold pressure for gas displacement in the shale cores. The higher the gas injection pressure, the more oil could be displaced. However, once the pressure reached a certain value, further increasing the pressure would not further improve the oil recovery. Finally, it was found that the threshold pressure of shale cores without developed fracture beddings was higher, and the more developed the fracture was, the lower the threshold pressure was and the higher the oil recovery would be.
Characterization of Micro-Nano Pore Structures in Shale Oil Reservoirs and FIB-SEM 3D Reconstruction: A Case Study
Authors: Zhang Yunfei , Song Zhaojie , Meng Yufan , Zhang Lichao , Zhou Qiancheng
Published: October 2023

Shale reservoirs in lacustrine sedimentary basins represent crucial sectors for shale oil exploration and development. Given their mixed sedimentation, complex origins, and pronounced heterogeneity, the stratigraphic reservoirs exhibit diverse spatial types. Identifying the characteristics of the shale reservoir, such as the distribution pattern of storage space, porosity volume distribution, reservoir properties, and three-dimensional structure of porosity, assists in pinpointing high-quality reservoirs, thus reducing exploration and development risks. This study examines representative shale samples from three formations of a lacustrine sedimentary basin, analyzing shale reservoir pore size and distribution characteristics, and characterizing the complexity of their porosity through low-temperature nitrogen adsorption and high-pressure mercury intrusion experiments. Argon ion polishing-scanning electron microscopy and focused ion beam-scanning electron microscopy techniques provide an intuitive characterization of the form and size of the shale reservoir space/porosity. In particular, FIB-SEM can reconstruct the spatial distribution of shale on a nanometer scale, authentically reproducing the three-dimensional structure features of shale nanopores, allowing for more precise results in analyzing porosity three-dimensional spatial components, pore size distribution, and connectivity. The study reveals that the quartz-rich Formation A exhibits developed mesopores and macropores in the shale, with large pore and small throat interwoven arrangements. Simple and well-connected pore structures render it easily exploitable, albeit with a smaller storage volume. Formations B and C, dominated by dolomitic shale and mixed shale properties respectively, show extremely developed shale mesopores and underdeveloped macropores. Their complex pore structures house larger storage spaces, indicating high extraction potential. Shale in Formation B, enriched with carbonate rock minerals, presents interwoven arrangements of microcracks and pore systems, featuring a higher coordination number and superior seepage capacity, despite a considerable number of unconnected closed pores. Formation C, having a higher clay content, contains numerous and dispersed isolated pores, incapable of interconnection. Connectivity can only be achieved through a small number of lamellar cracks.
Artificial Lift Real-Time Monitoring Digitalization Method: An Advanced Approach with Artificial Intelligence to Achieve Efficient Well Surveillance by Utilizing SCADA
Authors: Putra Hilman Lazuardi , Tanjungsari Fadhila , Edyawan Wuldan Sokery , Hidayat Azis , Suwono Sugiyanto
Published: October 2023

In Block X, there are a limited number of engineers and a vast number of wells that require to be monitored on a daily basis. Before 2018, engineers must visit each well to survey and monitor its status. This process proved to be inefficient due to the shortage of engineers which was aggravated by arduous journeys to remote areas, and long response time during test line leakage.

To improve the quality of surveillance and artificial lift systems, Medco E&P proposed the installation of Supervisory Control and Data Acquisition (SCADA) monitoring systems. SCADA was installed using Global System Mobile Communication (GSM) modem in ESP wells while SRP wells used Rod Pump Controlled modem. Data from both artificial lift wells is sent automatically to the user's platform through the installed system. By implementing this SCADA system, the data can be acquired more efficiently without the need for engineers to be present in the field. This leads to an effective surveillance monitoring activity where well status can be determined remotely and shorten response time when problems arise. Since the installation of the SCADA system, the average loss potential oil of ESP wells was decreased to around 24% while the down duration was decreased by 33%. These percentages correspond to a savings of $20,000 per month in LPO (Loss Potential Oil) after the implementation of SCADA.

The test line leakage problem can be solved through creating a virtual metering feature using machine learning based on the SCADA data acquired. This virtual metering is used to predict the liquid rate of each well using already existing well parameters without the need for well testing.

The SCADA data can be further used for further analysis to prevent Sucker Rod Pump (SRP) pump failure and increase lifespan of the pump by determining SRP Unit Balance.
Case Study for Enhancement of Production of Heavy and Highly Viscous Crude Oil Using Electrical Downhole Heater
Authors: Kumar Rakesh , Kakati Pinku , Lone Aqib Showkat , Bharadwaj Shailaj , Gurjar Satyaveer Singh , Pathak Diganta
Published: October 2023

It is a very challenging task to produce highly viscous and extra heavy crude oil from the Jodhpur Sandstone reservoir of Baghewala field of Western Rajasthan in India by any conventional methods. The crude obtained are having API in the range of 14 – 17 and viscosity ranging from 8000 to 15000 cP @ 50 deg C.

Considering above, it was planned to extract the oil from around 1100 m by using various thermal and non-thermal techniques. After a thorough study, it was found out that thermal methods performed better than the later in these kinds of fluid.

Accordingly, it was proposed to carry out the trial test with the Electrical Downhole Heater (EDH) in one of the horizontal wells and check the performance in the production rates in comparison with other wells without EDH. Since the maximum pressure loss observed in any heavy oil well is near the perforation, accordingly it was planned to carry out the test by placing the heater in a horizontal section with a drain hole and a slotted casing liner of 7 inch.

The methodology behind using the Electrical Downhole Heater was to increase the temperature in and around the wellbore, which will not only reduce the viscosity of the crude but will also help in increasing the production rate of crude. These kinds of techniques also help in increasing the efficiency of the downhole pumps and help in reducing the drag forces experienced on crude movement due to the presence of various downhole completion equipment. The installation of EDH in any well does not depend much on well integrity issues unlike other thermal EOR methods.

After applying the process, production initially increased from less than 20 bbl/ day to more than 80 bbl/day and stabilised at around 40-50 bbls /day.

This paper intends to present the design, placement, installation and performance of downhole heater in a horizontal well in comparison with a similar horizontal well in the same formation without any heater.
A Decision Method at the Concept Select Stage for Choosing Onshore LNG or Floating LNG Production Facilities for Large Offshore Gas Discoveries
Authors: Meulengracht Chresten Steen , Djukvik Jack Andre
Published: October 2023

Objectives/Scope

Several offshore areas with large gas discoveries (> 2 Tcf of reserves) that are distant from markets now have 2 different LNG development options. The first is the classical onshore LNG production facility and the second is the offshore floating LNG (FLNG) production facility, a comparatively new development solution. This paper examines both options from technical and economic perspectives and proposes a method for selecting the best development solution at the Concept Select stage.

Methods, Procedures, Process

Appropriate gas production profiles and costs including DRILLEX, CAPEX and OPEX were determined for 2 remote prospective gas basins areas - Australia's North West Shelf and the Rovuma basin offshore Mozambique. Both areas have comparable physical settings in terms of reserves, reservoir depth, water depth and distance to shore but they are different from a gas industry maturity perspective. Australia's North West Shelf has both onshore LNG facilities and the Prelude FLNG in operation and is a mature oil and gas area with significant local construction and operational experience. Mozambique's Rovuma basin now features the Coral South FLNG in production, and several onshore LNG production facilities are being planned. However the latter area is in the early phase of building upstream construction and operational expertise. The technical analysis was based on a comparison of key physical settings and project parameters such as production profiles, costs and schedules. This was performed for both FLNGs and onshore LNG production facilities in the 2 mentioned areas. The economic analysis was based on detailed after-tax cash flows of all technical options and provided the key economic metrics for both types of solutions in both areas. Where appropriate a portfolio analysis was performed to include the effect of being in tax positions with multiple units (FLNGs) in operation.

Results, Observations, Conclusions

The technical and economic analyses were combined to create decision tables for both mature and less mature areas. These tables can be used as a tool at the Concept Select stage to determine under which conditions that an FLNG (or several) is a preferable development solution to onshore LNG, and vice versa. The method was applied to relevant examples.

Novel/Additive Information

The floating LNG production facility is a relatively new development solution for remote offshore gas discoveries compared with the classical onshore LNG supplied with offshore gas. The novelty of the developed decision tables is that they provide a simplified approach for making high level decisions on whether to choose onshore LNG or floating LNG production facilities at the Concept Select stage.
Best Practice Utilising New Drilled Well Data to Improve Workover Performance in Existing Old Wells
Authors: Rahman Yudi , Tjahjono Hendro , Al Marawi Faizal , Anggreiny Yayu
Published: October 2023

KILAU Field is a mature field that produced through primary recovery. Managing mature field to keep performance in existing wells has many challenges, especially in performing workover activity. With limited data to knowing current subsurface condition, it has a high level of uncertainty in achieving a success rate in workover activity.

In 2021, 10 workover programs were executed but success rate was only 30%. Five jobs were failed with no oil gain and others only delivered average 19 BOPD/well. Part of improvement process, it conducted lookback to find the root cause. The result observed that if the well was produced from A-1 sand, it would have failed. The type of well completion, both even produced with commingled completion or single completion were failed since producing the A-1 sand.

Detailed subsurface review as part of lookback process was carried out. It turns out that the A-1 sand, based on log data from new wells (which were drilled in Q3-2021 until Q1-2022), shown that the level of OWC (Oil water contact) has clearly raised, or the oil already drained. So, if the well was perforated or produced from A-1 sand, then the production of the well will experience high water (high WC).

Another analysis result obtained from information of new wells was a high oil opportunity in sand of A-3, A-5, & C-1. So, the new wells log data told the mystery of the current condition of the subsurface. This very meaningful information enabled revised strategy to optimize existing old wells.

This paper discusses how to utilize new wells data to improve success rate of doing workover job by integrating updated subsurface information and production data though well log correlation and mimicking the completion of high production wells. The improvement process has been carried out in 7 wells through workover programs, which targeted reservoir A-3, A-5, & C-1 and to avoid producing sand A-1. It was obtaining a 100% success ratio with total oil gain of 966 BOPD.
Can Artificial Intelligence Enhance Gas Well Deliverability Testing? Exploring the Application of Machine Learning in Backpressure Testing
Authors: Bestman Somiari , Almahdi Rasheed Mahdi , Alyomny Assem Ahmed , Lawson-Jack Awoye
Published: October 2023

A deliverability test is a flow test performed to generate data utilized in the characterization of the short and long-term production performance of a well for various conditions of reservoir and bottomhole pressure. The generated data includes bottomhole pressure and temperature, flowing wellhead pressure and temperature measurements as well as the associated flow rates. An analysis of the acquired data ultimately yields a well model capable of predicting a tested well's productivity under stipulated conditions.

This paper presents a methodology by which the data output from a flow-after-flow test may be generated without ever performing the actual test. A machine learning (ML) model developed and trained on historic production data is used to simulate a producing wells performance at several rates as is typical for an actual flow-after-flow test.

The methodology utilizes a ML model trained on recent historical production data comprising of flow rates, flowing pressures and flowing temperatures, measured at surface and/or downhole. The ML model is then used to predict the flowing pressures and temperatures for a user specified flow rate. In its current form, the model is designed to utilize a continuous data stream that may be from a real time or archived source. The model may also be adapted to utilize data with a batch type configuration.

By minimizing the need for actual deliverability tests, or altogether eliminating the need for testing, operators stand to benefit immensely. The benefits include minimization or reduction of costs associated with testing requirements, curtailed production, as well as the minimization of emissions.
Novel Compact Integrated Cyclone and Filtration System for Solid Mercury Removal
Authors: Mohd Sahak Muhammad Zakwan , Myo Thant Maung Maung , Alias Azila , Abdul Salam Safwan , Ehsan Muhammad Ariff Asyraf , Mohd Hanafiah Ahmad Syukri Na'im
Published: October 2023

Mercury presence in produced fluid poses serious issues to gas production process due to HSSE risk, process disturbance and product quality for export. Mercury management is conducted based on type of mercury presence, for instance elemental mercury and solid mercury. For elemental mercury, adsorbent is typically being used, while solid mercury removal is managed via filtration. However, established mercury removal strategy is limited to "single" phase (gas, hydrocarbon liquid, water) thus can only be carried out post phase separation, while there is no available mercury removal technology for full well stream (FWS) treatment as early as at the wellhead.

A novel compact separation concept based on integrated cyclone and filtration design for removing solid mercury in gas dominant full well stream was developed, to allow for flexibility in implementation location (from multiphase at wellhead to single phase post separation) and achieve reliable and consistent separation performance at 1 μm particulate size. Testing with solid mercury particles demonstrated the technology feasibility in removing particles of 1 μm and larger, where particles of 1 μm and larger was not detected by the high-speed imaging camera used at the clean fluid outlet for solid monitoring. CFD simulation conducted provided reference on the feasibility of the technology based on fluid regime and dynamics in removing solid mercury at test conditions, as well as at intended site conditions. A reliable and flexible solution is key to ensure effective contaminant management from the target production, and safeguarding production loss due to contaminant presence in the long run.
The Guiding Principle of Well Placement to Maximise Hydrocarbon Recovery through Enhanced Reservoir Characterisation and Prolific Seismic-Driven Approaches
Authors: Zulkipli Siti Najmi Farhan , Hendrawati May Sari , Abdullah Noor Azmah , Hardiani Rosidah
Published: October 2023

Finding the best well location to drain the remaining hydrocarbon volume often poses a challenge particularly in the absence of good quality seismic data, presence of heavy fault compartments, uncertainty in the production data and limited well penetration in the surrounding area. Targeting the well penetration solely based on the brightest seismic amplitude carries significant uncertainties which may undermine the project economics and attainability. Aggressive well surveillance, sand correlation and lateral connectivity are among the mitigation measures taken to minimize the uncertainties. This paper will highlight several case studies and best practices of improving technical success in well placement through various well intervention, data acquisition and seismic-driven approaches to maximize the drainage volume and recovery.

Several infill wells have been drilled post proactive seismic reinterpretation to include the RGB blending, VpVs and also spectral decomposition approaches. Regional geological understanding on depositional environment, reservoir body geometry and rock quality delineation have improved as a result. Drilling multiple pilot holes dedicated for data acquisition, intervening nearby wells for fluid contact surveillance and effectively geosteering the pay zones to maximize hydrocarbon recovery have been properly planned and conducted during the project execution. In addition, identifying zonal flow contribution and reinventing continuous gas lift supply during well unloading, strategizing well drilling and testing sequences and prioritizing cement barrier for zonal isolation throughout production period are also emphasized to gain fruitful production insights.

Results from the post drill well test operation indicate that more than 3000 barrels cumulative oil and 25 MMBOE cumulative gas had been successfully produced following the rigorous intervention and prolific subsurface approaches mentioned. Production has sustained since from beginning till now which helps to arrest the field production decline by 22% and sustain the gas supply for regional gas network for power generation.

In conclusion, strategic well placement and production play a key role in determining the success of monetizing the remaining hydrocarbon reserves in a mature producing field. Integrating various subsurface lenses and guided by prolific seismic perspectives will reduce the uncertainties and open up more pathways to maximize the production.
Optimization Chemical Acid Stimulation by Improving Selection Intervals in Lateral Section of Horizontal Well in X Field Heavy Oil Steam Flood
Authors: Fatichin Fatichin , Paksi Willy Rhauda , Apriyanto Zepri
Published: October 2023

The production of horizontal wells in X field has decreased since 2019-2021 at a decline rate of 40% per year. Therefore, it is essential to increase production of horizontal wells through proper and effective jobs. The decreased production rate of the horizontal well due to plugging by CaCO3 scale in the wellbore along the lateral part of the horizontal well. It is because during the process drilling horizontal well using a fluid loss additive in the form of CaCO3 to prevent total loss circulation. To eliminate the problem of plugging scale along the lateral section of the horizontal well, chemical acid stimulation job is required. Some chemical stimulation jobs on horizontal well have been carried out, such as acid bullhead, solvent bullhead, and chemical acid CTU (Coiled Tubing Unit). The chemical bullhead work in 2020 is less effective on horizontal wells because it cannot reach the right target on the lateral section of the horizontal well. In 2020 there were 20 CTU chemical acid of horizontal wells were stimulated in all lateral areas even though there were areas that had low resistivity values because the wells penetrated the shaly sand. This has resulted in the ineffectiveness of the acid treatment area on the lateral section resulting in a low average oil gain of 2 bopd/job and a low success rate of 40%. It is caused by two factors, methods, and materials. The first factor is methods due to horizontal wells were stimulated in all areas section of lateral horizontal even though there were areas that had low resistivity values. It caused some of volume chemical acid treated at improper zone in lateral section of horizontal well. The second factor is materials due to HCl15% didn't effective working properly at immature reservoir. This paper shows how to improve two main factors that caused low oil gain and failures job of previous acid CTU in horizontal well. The improvement process must solve both two factors caused failed acid CTU jobs. The first improvement for the factor method by selecting intervals only for zones which have resistivity above 10 ohm and no found cross over between Neutron and Density log. The second improvement is to ensure that reservoir is mature (hot) for candidates of chemical acid CTU horizontal well to ensure that oil will flow from reservoir to wellbore. By improving selection process of chemical acid CTU in horizontal wells, it successfully achieves to improve oil gain from 2 bopd/job to 28 bopd/job, success ratio increased 40% to 98% and decline rate of oil production horizontal well 40%/year to incline rate 14%/year. Besides that, this improvement process success to deliver actual financial benefit about $US 4 MM. The new smart method for selecting effective area in lateral section of horizontal well successfully significantly improve result of oil gain and success ratio in performance of stimulation acid job using coiled tubing in horizontal well.
A New Technology Approach Using Permanent Chemical Tracer for Water Source Identification in Ujung Pangkah Field
Authors: Eviany Ameria , Mario Cio Cio , Hakim Arief Lukman , Nugrahanto Anang , Pramana Harris , Murtani Anom Seto , Rashed Rasha , Koumouris Steve , Huseby Olaf
Published: October 2023

One of the most common challenges in oil and gas production today is the multiphase production from a well with a high-water ratio continuously increasing along with the natural depletion of reservoir pressure. Wells in Ujung Pangkah (UP) field, generally completed in order to segment the flow. This is achieved by using Inflow Control Device (ICDs) and Sliding Sleeve Doors (SSD). This completion strategy aims to overcome the water continuity problem that creates a steeper drop in oil or gas production. As part of reservoir surveillance and water source identification, typically, a Production Logging Tool (PLT) is utilized as the standard technology. Nevertheless, it requires an equipment unit to convey this PLT technology into production tubing up to the target depth. To optimize production in wells completed with horizontal with multi sections, determination of water sources is essential to make decisions on intervals to isolate in order to minimize water production rate. SAKA Energi Indonesia, as the operator of Pangkah PSC, has applied another approach to this water source identification known as permanent installed chemical tracer.

Considering the dependency on equipment, tool, and cost of running conventional PLT technology, SAKA has implemented chemical tracers embedded into each well completion's ICDs. The tracer technology was installed in WPA-X and used twice, to identify the ICD sources responsible for the incoming water. The installed chemical water tracers (one unique tracer chemical per inflow section) can detect that specific ICD's contribute to flow – simply from pure mass-balance considerations. Furthermore, if the well is shut-in and restarted, the time-evolvement of tracer signals and differences in arrival-time for individual signals can be used to assess the zonal inflow contribution across separate inflow points along the well.

Compared to other methodologies (e.g. production logging tools), the tracers can provide results during unrestricted flow (i.e. without any tool affecting the flow). Other key benefits of this permanent solid tracer in the well are intervention-less activity that reduces cost and continuous reservoir monitoring. For short-term advantages, the inflow tracer data could provide quantification of each zone contribution, water break-through identification, and indirectly get information on packer integrity and other completion design performance. For mid-term benefit, the result could drive an action plan to eliminate water production in WPA-X. This tracer technology is a flexible technology with several applications to support specific decisions over a long time period in the well's life.
Recover the Well Integrity Issue Successfully in Combined Surface Casing and Intermediate Liner Annular for Offshore Re-Entry Well, Case in STS Platform - East Kalimantan, Indonesia
Authors: Laksono Setiadi , Palgunadi Haryotomo Budi , Aristya Ramadhana , Sianturi Bidner
Published: October 2023

Sejadi re-entry well is located in STS platform, offshore East Kalimantan, PT Pertamina Hulu Kalimantan Timur. SJ-2 well slot has been selected as re-entry well for drilling development from 5 existing well slot at the same location. As part of Stacked Template Structure (STS) where the SJ-2 conductor is used as one of platform leg, surface and wellbore integrity is important to maintain platform stability as well as well integrity.

During well preparation work by using Hydraulic Workover Unit (HWU), the leaking was observed on the surface through annular 13-3/8″x30″ casing. In term of surface wellhead, observed the unihead has tilting indication which may degraded related of structural capacity. Both of the integrity issue need to be recovered prior to proceed re-entry drilling operation. In order to get optimum work capability, the well preparation work has suspended and for well integrity recovery work it will be performed by Jackup rig.

The unihead tilting issue need to be verified and to ensure the structure capacity is sufficient, some stiffeners were welded on the unihead to 30″ casing housing plate as a supporter. In term of wellbore integrity issue, the recovery plan has been developed with the scope as follows; leaking point identification, remedial cementing which include the installation of additional 9-5/8″ as "suspended" tie back casing, and barrier verification test.

This paper is describe the process to recover both surface and wellbore well integrity issue by Jackup Rig, in consideration to optimize operation timeline, chance of success and rig daily spread cost. This practice has successfully implemented safely, to provide well integrity assurance to be able to continue the operation until put on production phase.
A Collaborative Solution in Optimising Deepwater Well Placement in Challenging Seabed Environment with Close Proximity to Mud Volcano
Authors: Mohd Safari Lai Harni Farihah , Mohd Sukri Eskandar
Published: October 2023

Deepwater development drilling is going to be one of the main keys to revitalize oil and gas industry in Malaysia as most of the shallow water reserves are heading towards their end-of-field life. However, this region's deepwater shallow seismic studies and findings from exploration and appraisal drilling shows that the subsea environment here comprises set of challenges, that if not carefully tackled, will turn the project to be un-attractive and irrelevant. This paper will explain the "collaborative" method that is used by the Deepwater Field Development Plan team during the well planning phase in detail and show how this method helped the team overcome a set of challenges efficiently, making the project able to progress to next stage.

The approach is to utilize different technology platforms where multiple disciplines gathered in collaborative well planning sessions to share their expertise in determining the optimum well placement that better suit the well trajectory, subsea facilities equipment placement and pipeline installation; whilst at the same time fulfilling the subsurface target requirement. This development field encompass enormous challenges such as presence of shallow gas, hydrates pocket, seafloor roughness, slope and slope failure, mud volcano, gulleys and pockmarks. All concerns are evaluated in detail on their risk ratings and associated impacts on the well design. The entire well plan is shared live during the session for better view and understanding, and any amendment is done and evaluated in real time to accommodate all parties’ requirement.

In conclusion, this paper will discuss the step-by-step method used to achieve the best engineering design for subsea development producer and injector wells in a complex seabed environment. Iterative collaborative sessions have proven to provide a platform to achieve a collective agreement to safely place the development wells efficiently. These sessions are key to unlock the opportunities and identifying threats at a very preliminary stage of the Field Development Plan (FDP). This paper would provide a greater insight of deepwater development well planning strategy in a challenging oil and gas environment with lessons learnt and best practices recommendation for future complex subsea FDP planning references.
Success Story of Repairing Casing Leak Near Surface Using a Bandage Cementing Technique in Central Sumatra Basin
Authors: Kurniawan Imron Fajar , Tarigan Jan Hendri , Hamdani Nanang Lutfi , Dova Rudi , Nataliawati Nurul Ayu
Published: October 2023

During the water injector workover campaign in 2018, some casing leakage near the surface was identified (depth range 10 to 300 ftRT). Several attempts were made to seal the leakage, but none of them succeeded. In response to investigation, a specific cementing technique was developed, called "bandage cementing", and it was successful in repairing casing leaks near the surface with over 75% success rate.

The focus of this technique is to build a column of cement in annulus between production casing and surface casing to create a "bandage" covering all leaking points in production casing. To build it, a cement evaluation log was run to investigate the presence of cement in annulus surface-production casing. A perforation gun was then run into the well to make some holes in production casing below leaking points. Injectivity and communication test was then performed to check the connection between perforation hole and leaking points and casing valve in surface. Once communication confirmed, cement retainer was then deployed to perform cementing jobs inside production casing and in annulus surface-production casing. The goal is to fill the void in annulus between surface and production casing with cement to build a cement column covering the casing leak.

This repair casing technique was applied to 4 (four) water injector wells with casing leak problems. The repair job succeeds to seal the casing leaks and all wells were put back on injection. They passed the pressure test and confirmed the leak was completely sealed. The key success for this repair casing method lies in how well we can place cement columns to surround the leak points from both below and above the leak. Several observations include whether the injectivity connection could be established between leaking points, perforation hole and casing valve and how much barrel of cement could be placed behind the casing are the supporting factors to achieve it.

The goal of this paper is to provide an alternative to casing repair for wells with casing leak problems near the surface which are usually very difficult to repair and take a lot of time on the rig to repair.
Semut Field Enhancing Production: Integrated Analysis to Reveal Thin Layer in Thick Sand Formation on Brown Waterflooded Field
Authors: Evelyn Katerina , Ustiawan Arief Budiman , Ramadhani Urfi , Moestopo Hendar Soeharnoko , Masyhuri Ali , Afton Muhammad , Fardiansyah Iqbal
Published: October 2023

Semut Field is a small brown field located in Central Sumatra basin produced since 1966 and waterflooded since 2009. Semut Field production has already depleted at 1/10 from its peak production and produced with high water cut. Earlier production strategy had been targeted at waterflooded thick and good permeability (~1 Darcy) reservoir and produced comingle. Deep dive and comprehensive analysis on G&G and rock properties on sand basis will be the answer to reveal any hidden opportunity on mature reservoir to increase oil production in Semut Field.

The approach to increase oil production is done by using and analyzing new data from Carbon-Oxygen (CO) logs and new infill well in 2021 to map the unrevealed potential of remaining by-passed oil. This field opportunity is hidden in lower permeability thin sand (<300 mD) with limited distribution that was previously overlooked in wide scale stratigraphic analysis. Comprehensive analysis of high-resolution stratigraphy also could figure out some thin sand that separated from the main sand lobes in each formation. More analysis on historical production and completion of old wells that have thin sand opportunity should be done to find out the earlier sand performance.

High-resolution stratigraphy approach analysis by layer sand is proven for revealing hidden opportunity in Semut Field. The remaining oil was found stored in a thin sand layer with perm ~200 mD which is lower than the average overall sand formation permeability. There are two main recommendations to unlock the opportunity at Semut Field based on the analysis result. First, completion strategy by selecting and precising perforation depth is critical since the separation between sand layer could only be between 2-3 ft shale. Second, production strategy by producing single or commingle with other sand that have similar PI and reservoir pressure. This approach gives outstanding results with oil gain 1,600 BOPD and oil cumulative 28 MBO within 1 month production, it is doubling Semut Field production.

This effective approach could be an alternative strategy to be applied in other Mature waterflood field or Primary field. This is a good case of how workovers on old wells can increase oil production in cheap way and dramatically extended good economic life.
Exceptional Length of Coring Recovery in a Very Loose Sand or Unconsolidated Formation in South Natuna Sea Block B at 8-1/2" Hole Section with a Conventional Full Closure System
Authors: Wales Benny Richard , Aribowo Triadi Herwasto , Hartanto Daru Mulyo , Darmawan Kurnia , Putranto Heru , Panjaitan Julianta
Published: October 2023

The South Natuna Sea Block B field is located in the waters of the Riau Archipelago and is a large and fragmented PSC that covers a number of oil and gas fields in the Natuna Sea, of which a few are currently operated by Medco E&P Natuna Ltd. Coring Service is one of the processes that is required by Medco E&P Natuna Ltd. for unconsolidated formations as the target reservoir zone.

Unconsolidated formation is very challenging to core, especially with the standard conventional system, as the core could slide and slip off from the inner barrel assembly of the Standard Conventional System while pulling out of the hole while the whole coring assembly is in progress. A Full-Closure System technology with a Double catcher assembly (Clam Shell Catcher and Spring Catcher as the main component) is necessary to address the problem.

The full closure system technology, which was created specifically to catch any unconsolidated formations, has gained widespread acceptance for its effectiveness in a variety of fields, particularly in Indonesia. Even when the Full Closure system is assembled and run in the hole, anomalies like core jamming and milling the core are difficult to detect at the surface gage while coring is taking place at unconsolidated formations.

The challenge is further increased by the 90-foot length of the core that must be retrieved in a single-run in order to save cost by reducing the number of trips. This plan goes against the best advice or rule of thumb given by the majority of coring services, which stated that when coring, especially in an unconsolidated formation, a shorter length of barrel is highly recommended, such as per joint or only 30 feet to be done in one run, for example, for a Total of 3 (three) × 30 feet to retrieve the entire target of 90 feet, in order to avoid any unforeseen anomalies.

Since vibration always increases the likelihood of core jamming, a shorter core barrel could potentially cause less vibration while coring is taking place. If this happened, the core would then be milled. Therefore, a shorter barrel always presents a lower risk of losing precious data samples if core jamming and core milling anomalies ultimately occur undetected.

This paper is made to inform, demonstrate, and discuss how Full-Closure System technology and certain key procedures that are strictly followed and monitored could mitigate the potential hazards or risks mentioned to Successfully Core the 90-foot core target in one run at an Unconsolidated formation and be the first to ever do it in that length, especially in Indonesia.
Performance Improvement in Wellbore Side-Tracking: A Case Study of Dual-Casing Exit in Mahakam Offshore
Authors: Sinaga Rahmat , Hutahaean Ray Henry , Andhika Lutfi , Nurmida Arrofi , Haryasukma Kresna Prabu
Published: October 2023

In the last two years, an operator has been performing drilling and completion from an existing well's slot to access geological targets means a sidetrack operation is conducted in a cased hole. This initiative needs to be efficient in budget-wise and regulation as well.

Cased hole sidetrack operation can be challenging, particularly when the milling assembly has to cut dual-casing due to the existing well condition and the geological target requirement. The centralizer and casing collar position inside the wellbore is considerably to select the kick-off point and optimize the well's trajectory. Besides, the work sequence and the Bottom Hole Assembly (BHA) selection are significant to avoid costly multiple trips. Moreover, a unique challenge to ensure the window is in good condition when the wireline logging job needs to conduct in an open hole.

This paper provides a case study of performance improvement of dual-casing sidetrack in 9.625 in and 13.375 in within the last 2 years. The study was started by modeling the BHA which generates the least amount of vibrations to pass through the window. Further, a comparison between a bi-mill and a tri-mill BHA includes the position of each mill and the milling parameters to achieve the most efficient result. Doglegs severity within the interval depth of setting the whipstock is also taken into account since the dogleg through the window can create additional issues. There was no casing collar locator logging job run as the tool will not able to identify the collar position in the 13.375 in the casing string. Therefore, historical data on the casing tally and the well's information has become essential for determining the whipstock setting depth.

This integrated and collaborative planning has resulted in a successful dual-casing exit operation during the last two years in Mahakam offshore. Improvements made in the engineering and operations have successfully overcome the challenge identified in the initial period of the campaign.
Maintain Oil Production Equal to 7,600 Bopd Through Vsd Excellent Workflow and Best Practices in 100 ESP Wells
Authors: Alkahfi Sayid Habibi , Purba Monas Octavianus , Ifani Refni , Garini Sistha Ayu , Wusodo Winoto , Junaidy Ichwan
Published: October 2023

There are currently more than 50 active fields and 1,000 ESP wells in Light North Area. Those fields are having various problems both surface and subsurface. Sanded, gassy, scale, limited productivity, high temperature, congeal are common problems in this area which impact directly to well failure and loss production.

An initiative to build workflow and best practices to reduce well failure and improve production utilizing Variable Speed Drive (VSD) had been started since 2016. There are more than 100 ESP wells installed with VSD as per today across this area. It needs effective surveillance and monitoring workflow to be managed to keep production level while minimizing failure at the same time. Installation process, routine review and dismantle decision included all related surveillance data are become part of integrated workflow.

The number of VSD has been increasing significantly since 2018 from 60s to 100s in 2023. Associated oil from these VSD is around 7,600 BOPD. It is a significant number to be maintained to support the government target as 1 MMBOEPD in 2030. Excellent coordination review among Subsurface, Well Reliability, Operations, Well Test and ESP Vendor are key success to manage these VSD wells properly. The team decided to set monthly VSD review. Semi-automatic and established processes have been put in place to monitor all the process. Activity cycle time has been improving to ensure less oil loss during installation and dismantle job. Several best practices related to ESP and VSD design, setting and modification are also provided in this paper.