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Sumatra
Uncovering the Actual Safety Integrity Level (SIL) of Critical Safeguards in Aging Hydrocarbon Facilities as the Basis for the Development of a Performance-Based Maintenance Strategy of Critical Safeguards; Lessons Learned from Rokan Block
Safrudin, Safrudin (PT Pertamina Hulu Rokan) | Yudhy, Muhammad Riandhy Anindika (PT Pertamina Hulu Rokan) | Joelianto, Endra (Institut Teknologi Bandung)
Abstract Equipment aging is one of the main challenges faced by companies operating oil and gas processing facilities with a brownfield engineering approach. As equipment ages, it breaks down more quickly, making it more susceptible to failure. The consequences of equipment failure can be disastrous, especially if the equipment is listed as a critical safeguard that protects the system from hazardous conditions. Failure of critical safeguards will increase the likelihood of hazardous scenarios occurring and thus impact the overall risk ranking of operating the facility. As a risk management effort, it is important to validate the safety integrity level (SIL) of the critical safeguards currently installed at the facilities and design an appropriate maintenance strategy to maintain the SIL value as originally designed. However, given the vast amount of equipment that is scattered over a large area, this is a very challenging effort. This paper discusses a novel attempt to validate the actual critical safeguards SIL in brownfield facilities by conducting a hybrid of an extensive reliability-centered maintenance study and a regression-based machine learning model to obtain the actual equipment failure rates based on incomplete historical failure data stored at the Computerized Maintenance Management System (CMMS). A recalculation of the current SIL level and comparing the results with the original SIL design will provide information on the level of degradation that occurred and the appropriate solution. To illustrate the application of the technique, a case study is presented based on the experience in implementing the life cycle of a safety instrumented system (SIS) according to the IEC 61508/61511 guidance as a maintenance strategy to maintain the SIL of a critical safeguard. Through these efforts, critical safeguard SILs are maintained on designed SILs and are capable of achieving credit risk reduction aimed at hazardous scenarios while setting the database for further improvement in the adoption of digital technology.
- Asia > Indonesia > Sumatra > South Sumatra Basin > Rokan Block > Rokan Block (0.99)
- Asia > Indonesia > Sumatra > Central Sumatra Basin > Rokan Block > Rokan Block (0.99)
Abstract The Suban field’s gas reservoir, located at approximately 2000 mTVDSS, is composed of Pre-Tertiary rocks including Igneous and Metasediments, as well as Tertiary sedimentary rocks like LTAF (Lower Talang Akar Formation) and BRF (Baturaja Formation). Before accessing the gas reservoir, drilling activities must navigate through overburden formations, predominantly shale-based Palembang and Telisa Formations. A particular challenge encountered within the Telisa Formation is the presence of overpressure conditions. Historically, drilling through overpressure-prone formations has posed formidable obstacles. Earlier approaches employed water-based mud (WBM) for drilling, which encountered issues such as shale instability and slow rate of penetration (ROP), necessitating the use of multiple drilling bits. In 2012, a shift was made to Synthetic Oil-Based Mud (SOBM) to address these challenges and enhance hole stability. The outcome was not only improved hole stability but also a noteworthy surge in the rate of penetration (ROP). Consequently, SOBM applications have been employed for drilling gas-fractured reservoirs in the Suban and Sumpal regions since 2012. However, the adoption of synthetic oil-based mud (SOBM) presented its challenges, including significantly higher costs compared to water-based mud (WBM) and challenges in handling and disposing of non-environmentally friendly drilling waste associated with SOBM. Recent developments have introduced High-Performance Water-Based Mud (HPWBM) as an alternative to Synthetic Oil-Based Mud (SOBM) for drilling. While HPWBM is not a complete replacement for SOBM, it aims to match its performance in terms of shale inhibition, wellbore stability, and rate of penetration (ROP). Additionally, HPWBM offers the potential for cost reduction and improved drilling performance. To incorporate HPWBM into the Suban field, a meticulous technical review and analysis were conducted to align the formulation with the reservoir’s mineralogy. The implementation was initially carried out in a specific Suban well, focusing on the 12.25" hole section due to overpressure. Key goals in designing the HPWBM included achieving superior shale inhibition, countering clay swelling and dispersion, and maintaining stability at high application temperatures. This alignment was particularly critical in the 12.25" section to minimize standpipe pressure (SPP) and Equivalent Circulating Density (ECD) and avoid formation fractures. A comprehensive laboratory testing process led to the development of 134 HPWBM formulations, with Formula 134 emerging as the optimal choice to fulfill the required objectives. The successful implementation of HPWBM, specifically formula 134, in the Telisa Formation marked its efficacy in delivering performance on par with SOBM. This achievement not only demonstrated cost-efficiency but also streamlined and effective drilling operations.
- Asia > Middle East > Saudi Arabia (1.00)
- Asia > Indonesia > Sumatra > South Sumatra (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.76)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Palembang Basin > Corridor Block > Suban Field > Talang Akar Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Palembang Basin > Corridor Block > Suban Field > Fractured Basement Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Palembang Basin > Corridor Block > Suban Field > Durian Mabok Formation (0.99)
- (5 more...)
Abstract Suban Field was discovered in 1972 and has been abandoned until 1998. The fracture reservoir has a characteristic high permeability compared to the matrix reservoir. This special characteristic is causing losses in drilling at the reservoir section. In the early drilling campaign (1972 – 2006), conventional drilling (loss and cured) was applied to overcome the challenge. However, this method has prolonged drilling time and caused high skin in terms of reservoir productivity. Since 2010 until now, Managed Pressure Drilling (MPD) had been applied to optimize drilling time and resulted in less skin to have good reservoir productivity. During this period, there are some challenges in MPD application especially due to depleted reservoir pressure (~6 ppg EMW) forcing the engineering team to optimize the creative design that aligned with project optimization without jeopardizing the operation. In the early stage of MPD drilling campaign, a downhole valve was installed as a mechanical wellbore isolation tool while tripping in/out when losses occur. The performance of downhole valve has been evaluated from the last 5 wells drilling campaign before drilling Suban-X well with a statistical evaluation showing 6 successful isolations out of 18 total attempts. Some experiments were performed when the downhole valve was not closing properly on the last 3 wells during the Drilling and Completion campaign. The experiments were successful to suppress the gas by bull heading the well with a sufficient rate of water, periodical high viscosity sweep injection as a precaution for gas migration and having Dual Seal Element Adapter installed on Rotary Control Device (RCD). Based on the above circumstances, prior to drill Suban-X in 2021, the decision was made to drill Suban-X well with MPD without downhole valve installed. The mitigation to overcome gas migration and suppress the gas was by preparing sufficient water from water pond at wellsite and establishing a water network to keep filling the water pond. As a result, the well was successfully drilled to TD safely without any issues. The innovation to eliminate the utilization of downhole valve provides cost-reduction for material and drilling time savings. This innovation was first implemented in Corridor Block and is currently being used as a basic template for future drilling campaigns.
- Asia > Middle East > Saudi Arabia (1.00)
- Asia > Indonesia > Sumatra > South Sumatra (1.00)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Palembang Basin > Corridor Block > Suban Field > Talang Akar Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Palembang Basin > Corridor Block > Suban Field > Fractured Basement Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Palembang Basin > Corridor Block > Suban Field > Durian Mabok Formation (0.99)
- (2 more...)
Managing Safety Risk and Oil Spill During Pre-Breakthrough Steam Flood by Steam Early Detection with Artificial Intelligent
Triananda, Ade Hamzah (PT. Pertamina Hulu Rokan) | Aji, Muhamad (PT. Pertamina Hulu Rokan) | Wibawa, Ramdhan Ari (PT. Pertamina Hulu Rokan) | Silaban, Meita (PT. Pertamina Hulu Rokan) | Pasaribu, Rinaldi (PT. Pertamina Hulu Rokan) | Rifani, Ria Ayu (PT. Pertamina Hulu Rokan)
Abstract Delta Area-X is the newest steam flood project in Delta Heavy Oil Field in Riau Province of Sumatra, Indonesia. The area currently produces 12,000 BOPD from 450 oil producers and 145 steam injectors that are supported by high proactive optimization that consists of steam cyclic stimulation, chemical stimulation, and pump optimization. The steam flood life cycle is divided into three general phases: immature phase, transition/steam breakthrough phase, and mature phase. Delta Area-X is currently entering the transition period. The transition phase is the most challenging period because steam has broken through for some producers. Many producer failures experiencing sanding problems, holes in pipes, rapid production changes, scale problems, etc. These are the challenges to completely heat the project area. At this period, the team is supposed to maintain and continue steam injection, conduct cyclic steam in cold producers to connect steam zones, and mitigate steam breakthrough impact on producers by building a fluid level and pinch casing valve. Steam rate reduction in this phase may delay heating area. Delta Area-X has experienced several steam breakthroughs events that caused the production casing line to be cut out and cause oil spills. To prevent similar cases, similar events should be identified earlier to know which wells, where and when for later on leading preventive actions. Identification started by integrating data from surveillance data from field such as artificial lift, field operation pressure and temperature survey and production performance trend. Artificial intelligence was introduced to the identification process by pattern recognition artificial lift surveillance data to determine indication of steam. The result of Artificial Intelligence combines with dynamic well condition drives condition to meet: gradually detection and sudden detection to oil producer. Since there are many wells operated in the area, an exception signal is required to alert engineers only on wells that has potential issues. Since application of steam breakthrough signal, the team can quickly make recommendations to manage steam by installing chokes, size up casing choke, reduce stroke per minute (SPM), reduce stroke length (SL) or the most massive action: shut in well oil producer / steam injector. Managing the steam will help controlling the steam causing casing cut out or oil spill and in term of steam flood management, it will redistribute steam to other wells or redirecting steam growth in order to have good sweep efficiency. Since the implementation of this approach, the team has identified more than hundred wells that were captured by steam breakthrough signals, then it followed up with appropriate action that successfully prevented potential safety hazard.
Low Cost Alternate Solution to Produce the Shallowest Productive Low-Quality Reservoir in WK Rokan
Afif Ikhsani, Muhammad (PT. Pertamina Hulu Rokan) | Putra, Azarico (PT. Pertamina Hulu Rokan) | Rafi, Muhammad (PT. Pertamina Hulu Rokan) | Alfajrian, _ (PT. Pertamina Hulu Rokan) | Barezzi, Muhammad (PT. Pertamina Hulu Rokan) | Jati, Nugroho (PT. Pertamina Hulu Rokan) | Sunjaya, Rizky (PT. Pertamina Hulu Rokan)
Abstract Low Quality Reservoir in WK Rokan is quite famous as a large volume of remaining recoverable resource, where TLS Formation owned the biggest share (~51%) of the total Low-Quality Reservoir potential additional reserves. This formation develop widely in Central Sumatra Basin with range ~600 ft TVDSS depth and the deepest productive reservoir in ~4000 ft TVDSS. The 600ft TVDSS TLS Reservoir is identified as the most challenging Low-Quality Reservoir in term of its subsurface and operation since this formation has been producing for decades. This Reservoir located in BLSO field in Riau Province, Central Sumatra, Indonesia approximately 140 km Northwest of Pekanbaru or 50 km northwest of the DRI field. The field is a large elongated anticlinal structure bounded on the southwest by a major high-angle reverse fault. The shallowest productive TLS in WK Rokan has a minimum recovery factor with a low reservoir quality which has permeability range of 20-300 MD due to the thin overburden barrier (shallow structure), reservoir complexity (low reservoir permeability, low sand connectivity) that led to limitation of completion strategy resulted in low oil recovery. It is found in 1972, and commercially produced as an oil-producing well with a reservoir depth of 800 - 1000 ft TVD with current recovery factor only 8%. The drive mechanism in this reservoir is shown as a weak water drive reservoir. The old-fashioned development strategy from this shallow low-quality reservoir is by having hydraulic fracturing with cased hole completion which will be driven a high-cost development scenario if we want to increase oil recovery in this reservoir. The alternate solution in developing this shallow reservoir is by optimizing productive section interface, and Open Hole Screen Liner is coming out as solution with lower investment to add more recovery with average production 49 BOPD and low average water cut (51%). This paper will talk about in how we develop well candidacy to apply open hole screen liner completion method, the result and future development plan to improve oil recovery in shallowest low quality reservoir in WK Rokan.
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Telisa Formation (0.99)
- Asia > Indonesia > Sumatra > Central Sumatra Basin (0.99)
Extending the Production Lifetime of Oil Well with Paraffin Problems Through Thermal Application of Mobile Steam Injection of Mature Field
Pratama, Satria (PT Pertamina Hulu Rokan Zona) | Azhim, Luthfan Nur (PT Pertamina Hulu Rokan Zona) | Suwitno, Agus (PT Pertamina Hulu Rokan Zona) | Daniel, Sofyan (PT Pertamina Hulu Rokan Zona) | Saputra, Medyansah Eka (PT Pertamina Hulu Rokan Zona) | Susilo, M. Danang (PT Pertamina Hulu Rokan Zona) | Imansyah, Ali Ganjar (PT Pertamina Hulu Rokan Zona) | Sucipto, _ (PT Pertamina Hulu Rokan Zona) | Kuncoro, Anang Arie (PT Pertamina Hulu Rokan Zona)
Abstract Oil wells that produce crudes with high paraffin content usually lead to precipitation due to deposits forming near wellbore up to downhole equipment of artificial lift which potentially cause downhole problems resulting loss production opportunities. This paper presents success practical case from PT Pertamina Hulu Rokan Zona 4 in handling paraffin deposition in oil well producers with most widely used sucker rod pump as artificial lift without well services job. Thermal treatment has been used in a number of paraffin deposition problems, steam injection is the one of method to overcome the deposits in well producers. Mobile Steam Injection (Steamject) is built by steam generator installed on the truck which has capability to produce steam from water which has adequate heat capacity to melt the paraffin deposits and the steam will be injected into annulus with temperature up to 250 oC. Flexibility of Mobile Steamject provides prompt action to remove the deposits from the well during the production phase. Early detection of downhole problem such as plunger stuck was able to identified from dynacard card analysis. Once the problem is confirmed, Steamject will propagate the heat through annulus into well and downhole equipment to reduce restriction of pump volume displacement. After the steam was completely injected, production will start to continue while observing the production test result and re-run the dynacard analysis. Two promising advantages of Steamject are the deliverability and cost efficiency as implemented in Benakat Barat Operation Area. Based on practical case, Steamject can reduce the operation time up to 116 hours. Then, the faster the deliverability time, the lower operation cost. Practical case presented in this paper about steam injection to overcome paraffin deposition provides lesson learned for operation excellences. Implementation of Mobile Steamject has opportunity in any mature field that needs flexible and low-cost solution of paraffin problems.
Abstract KS field faces low production challenges from Telisa formation. In addition, other problems in Telisa formation are also high GLR and solid production. ESP equipped with sand control and gas handler can still be used for liquid production above 100 BLPD. The problem is that the rest of the wells producing from Telisa formation that still use gas lifts, the production of which is already below 100 BLPD. In this case, the usual ESP configuration is no longer be used. The production method with gas lifts can no longer be used due to the limitations of gas production which continues to decline. Currently, there are still more than 30 wells that use gas lift and to maintain production from these wells, the right artificial lift solution must be sought. A modification has been made to the ESP artificial lift to be able to accommodate the very low production rate. The trial has been carried out in KS-001 and KS-002 for more than 1.5 years and as the result, the ESP is still running normally today. To improve run life for low rate ESP which may exposed to down-thrust condition and increased temperature resulted from low cooling fluid pass thru ESP motor housing, several precautions must be taken during designing ESP which fit for application: Pump with compression stages construction were selected for low rate application. This compression stages design will improve down-thrust handling in the pump. Down-thrust force generated by pump will be transferred into protector thrust bearing, where the thrust bearings were covered with lubrication oil. High load thrust bearing were selected to handle the thrust load. Tandem BPBSL – BPBSL protector selected to give extra motor oil reservoir to the ESP motor in the case of motor run on higher temperature due to low cooling fluid passes thru ESP motor housing. Due high GOR up to 800 SCF/STB, with ability to handle free gas up to 45% GVF, combination of Advance Gas Handler and gas separator were selected for better handling of free gas produced by the well. In low flow rate ESP system, fluid velocity pass thru the ESP motor housing is essential for cooling system. In the case of KS-002, well was completed with 7″ casing. ESP casing shroud were selected to improve fluid velocity. In overall ESP parameter in 2 wells trial are in normal condition, even though running with low frequency and limited liquid rate. Application of tandem protector, gas handling device, and sand screen successfully handle very low liquid rate with high GOR in hydraulic fractured wells. With the success of ESP's very low rate in Telisa, there is no longer any concern if gas production decreases. This paper will describe an integrated application of very-low rate ESP in sandy gassy wells with low productivity. These applications are required to improve the run-life of the ESP in Telisa zone to minimize oil deferment.
- Asia > Indonesia > Sumatra (0.29)
- Europe > Norway > Norwegian Sea (0.24)
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Telisa Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Kaji Semoga Field > Telisa Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Kaji Semoga Field > Talang Akar Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra Basin > South Sumatra Basin > Kaji Semoga Field > Baturaja Formation (0.99)
Semut Field Enhancing Production: Integrated Analysis to Reveal Thin Layer in Thick Sand Formation on Brown Waterflooded Field
Evelyn, Katerina (PT. Pertamina Hulu Rokan) | Ustiawan, Arief Budiman (PT. Pertamina Hulu Rokan) | Ramadhani, Urfi (PT. Pertamina Hulu Rokan) | Moestopo, Hendar Soeharnoko (PT. Pertamina Hulu Rokan) | Masyhuri, Ali (PT. Pertamina Hulu Rokan) | Afton, Muhammad (PT. Pertamina Hulu Rokan) | Fardiansyah, Iqbal (PT. Pertamina Hulu Rokan)
Abstract 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.
- Asia > Indonesia > Sumatra (0.76)
- North America > United States > Texas (0.70)
- Asia > Middle East > Israel > Mediterranean Sea (0.25)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.62)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin (0.99)
- Asia > Indonesia > Sumatra > Central Sumatra Basin (0.99)
- North America > United States > Montana > Sumatra Field (0.97)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.91)
Successful Hydraulic Fracturing Breakthrough in New Low Quality Reservoir Target from Paku Field, Rokan Block, Central Sumatra Basin
Kurniawan, Hendri (PT. Pertamina Hulu Rokan) | Pradana, Aulia (PT. Pertamina Hulu Rokan) | Safarina, Aulia Sherly (PT. Pertamina Hulu Rokan) | Prasetio, Mario Hadinata (PT. Pertamina Hulu Rokan) | Kristanto, Irwan (PT. Pertamina Hulu Rokan) | Tjahjono, Hendro (PT. Pertamina Hulu Rokan)
Abstract Paku Field is a relatively small oil field that is located in Rokan block, Central Sumatra Basin. Paku field had a long production history since 1988 with current recovery factor 24%. The field is still under primary depletion with ESP as its major artificial. Currently, Paku field has two active producers with total oil production of around 100 BOPD. Paku field mostly conducted regular well intervention & well service (add perforation and pump recondition) to maintain/improve production, while special well stimulation like hydraulic fracturing was last conducted in 2016 on Paku #04. Paku #04 fracturing job targeting MGL1 sd with reservoir properties average resistivity 20 ohmm, average porosity 13%, average permeability 44 mD and reservoir pressure 1600 psi. Hydraulic fracturing stimulation in this reservoir successfully conducted resulted in 311 BOPD oil gain and 24% water cut from commingle several reservoirs. Until now Paku #04 is still a good oil producer from the same reservoirs with oil average 60 BOPD and water cut 77%. Looking at the historical success story of Paku #04 as an analog, Paku #05 also has similar low-quality reservoir sand but from the different geological formations that is BK1 sd. The BK1 sd has reservoir properties of 32 ft net pay, 18 Ohmm resistivity, 11% average porosity, 25 mD average permeability and 1534 psi reservoir pressure. The fracturing job in Paku #05 was successfully executed in October 2022 targeting BK1 sd. The job was conducted with several improvements from the previous job of Paku #04 such as conducted with three times more proppant volume (63 k vs 21 k previously), full sand body perforation, and produced from single zone. Hydraulic fracturing stimulation in Paku #5 resulted in initial production of 242 BOPD and water cut 60%. Hydraulic fracturing jobs have been proven as one of the solutions to significantly improved production in primary fields such as Paku Field. Especially to improve production from reservoirs that are identified to have oil in low-quality reservoirs in other well or in another reservoir in Paku Field and from other fields that has the same reservoir properties characteristic.
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.31)
- North America > United States > Mississippi > Improve Field (0.99)
- Asia > Indonesia > Sumatra > South Sumatra Basin > Rokan Block > Rokan Block (0.99)
- Asia > Indonesia > Sumatra > Central Sumatra Basin > Rokan Block > Rokan Block (0.99)
Chemical Stimulation Success Stories – A New Integrated Process to Support Massive Aggressive Strategy in Complex Operation of World Largest Steam Flood Field
Terosela, Andro (PT. Pertamina Hulu Rokan) | Etri, Yulmi (PT. Pertamina Hulu Rokan) | Efendi, Faried (PT. Pertamina Hulu Rokan) | Pramono, Wasis (PT. Pertamina Hulu Rokan)
Abstract 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.
- North America > Canada > Alberta (0.40)
- Asia > Indonesia > Sumatra (0.36)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Asia > Indonesia > Sumatra > Central Sumatra Basin (0.99)
- North America > United States > Montana > Sumatra Field (0.90)