The Challenges and Lessons Learned from the Unanticipated Long Run Well Unloading Campaign in T Field, Malaysia

2021 ◽  
Author(s):  
W M Faris W Hassan ◽  
Thivyashini Thamilyanan ◽  
Alister Suggust ◽  
M Zulfiqar Usop ◽  
Nurfatrina Hamdan ◽  
...  
Keyword(s):  
Transient Flow ◽  
Weather Condition ◽  
Lessons Learned ◽  
Drilling Fluids ◽  
Long Run ◽  
Low Performance ◽  
Gas Lift ◽  
Production Target ◽  
Multi Disciplinary Team ◽  
Daily Trip

Abstract This paper presents overall challenges and experiences that the team were facing during offline well unloading campaign recently. On paper, offline well unloading is more favorable as an option to minimize environmental impact, economize rig days and reuse produced clean-up oil. This practice is not new. The implementation of this practice to a 40-year-old brown fields led to successfully bring adopted for two drilling campaign. The well unloading to the existing facilities requires substantial strategies to be adapted and possibilities to handle drilling fluids and solid/debris are extensively discussed within multi disciplinary team whereby risk evaluation was conducted ensure the good progress of this operation. The assurance part to handle production of solid/debris along with produced fluid to surface within 12 hours operation with the assitace from Hook-Up and Commissioning (HUC) work barge initially and resumed later by daily trip via boat to offshore site will be discussed in this paper. Almost 90% of this activity is carried out with crews mobilized with 45-minute boat trip from Bintulu to site, highly depended on weather condition. This paper also will share the major challenges that resisted the good progress of unloading for four wells such as limitation associated setting of the surface Hi Lo Pilot safety switch that cannot handle the transient flow condition, huge pressure drop exerted by the inline surface strainer that temporarily installed to filter any solid production, unintentional jammed close of Tubing Retrieveable Surface Controlled Subsurface Safety Valve (TRSCSSV), unanticipated low performance of gas lift compressor that restricted the wells to continuously flow to the test separator and temporary high H2S gas release throughout the well unloading operation. Due to daily tripping, the crew left with constrained time of 4 - 5 effective hours only per day in attempts to kick off and flow the wells. On paper, offline well unloading indeed offered 70% cost saving compared to clean up with rig. However, in actual it resulted to increase 3 times in well cost and delay in achieving first production target which was 6 months later from the plan due to unanticipated causes that prolong the unloading activities.

Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

2021 ◽  
Author(s):  
Mohd Hafizi Ariffin ◽  
Muhammad Idraki M Khalil ◽  
Abdullah M Razali ◽  
M Iman Mostaffa
Keyword(s):  
New Technology ◽  
Lessons Learned ◽  
Oil Fields ◽  
Submersible Pump ◽  
Large Space ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

scholarly journals A Learning Game For Youth Financial Literacy Education In The Teen Grid Of Second Life Three-Dimensional Virtual Environment

2011 ◽  
Vol 4 (7) ◽  
pp. 1-18 ◽  
Author(s):  
Chang Liu ◽  
Teresa Franklin ◽  
Roger Shelor ◽  
Sertac Ozercan ◽  
Jarrod Reuter ◽  
...  
Keyword(s):  
Virtual Worlds ◽  
Second Life ◽  
Financial Literacy ◽  
Three Dimensional ◽  
Literacy Education ◽  
Lessons Learned ◽  
Learning Game ◽  
3D Virtual Worlds ◽  
Computer Scientists ◽  
Multi Disciplinary Team

Game-like three-dimensional (3D) virtual worlds have become popular venues for youth to explore and interact with friends. To bring vital financial literacy education to them in places they frequent, a multi-disciplinary team of computer scientists, educators, and financial experts developed a youth-oriented financial literacy education game in the Teen Grid of Second Life 3D online virtual world. This paper presents the design and development process of this financial literacy education game, its learning effectiveness in classrooms, and lessons learned from the process.

scholarly journals Numerical modeling on drilling fluid and cutter design effect on drilling bit cutter thermal wear and breakdown

2019 ◽  
Vol 10 (3) ◽  
pp. 959-968
Author(s):  
Ahmad Zhafran Ayop ◽  
Ahmad Zafri Bahruddin ◽  
Belladonna Maulianda ◽  
Aruvin Prakasan ◽  
Shamammet Dovletov ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Polycrystalline Diamond ◽  
Poor Performance ◽  
Drilling Fluids ◽  
Drill Bit ◽  
Thermal Wear ◽  
Cutter Design ◽  
Low Performance ◽  
Geological Complexity ◽  
Drilling Bit

Abstract The unconventional reservoir geological complexity will reduce the drilling bit performance. The drill bit poor performance was the reduction in rate of penetration (ROP) due to bit balling and worn cutter and downhole vibrations that led to polycrystalline diamond compact (PDC) cutter to break prematurely. These poor performances were caused by drilling the transitional formations (interbedded formations) that could create huge imbalance of forces, causing downhole vibration which led to PDC cutter breakage and thermal wear. These consequently caused worn cutter which lowered the ROP. This low performance required necessary improvements in drill bit cutter design. This research investigates thermal–mechanical wear of three specific PDC cutters: standard chamfered, ax, and stinger on the application of heat flux and cooling effect by different drilling fluids by using FEM. Based on simulation results, the best combination to be used was chamfered cutter geometry with OBM or stinger cutter geometry with SBM. Modeling studies require experimental validation of the results.

First Multilateral Well in the Most Congested Field in Abu Dhabi, Case of Study

2021 ◽  
Author(s):  
Felix Leonardo Castillo ◽  
Mohamed Sarhan ◽  
Abd El Fattah El Saify ◽  
Victor Jose Aguilar ◽  
Roswall Enrique Bethancourt ◽  
...  
Keyword(s):  
Lessons Learned ◽  
Drilling Fluids ◽  
Screening Criteria ◽  
Technology Application ◽  
Initial Stage ◽  
Limited Entry ◽  
Study Team ◽  
Multiple Reservoir ◽  
The Cost ◽  
The Impact

Abstract This paper will highlight the first level 2 Multi-lateral well in BAB Field with permanent limited entry liner completion in the lower borehole to enhance accessibility and production. The well presents a technical milestone to the company in the development of multiple reservoir by combining two (2) wells from different reservoir and produce from both by using same surface well construction. At initial stage, the economics related to the implementation of the multilateral approach were analysed. Calculation was done by comparing the cost related to the technology application against the cost to prepare one (1) location plus completing a well up to the 7″ liner and mobilizing the rig twice. Then, it was necessary to select the candidate wells to be drilled from the same slot where synergy between Study team and drilling team was in place in order to ensure proper target alignment to make feasible the drilling and completion operations at the same time that the production targets were fulfilled. This project confirmed the feasibility of multilateral well application in a very congested field in terms of wells construction and surface facilities. In order to achieve such goal full synergy must be in place to select proper wells candidates and align targets. Cost reduction is massive considering the elimination of three (3) well phases plus avoidance of one (1) location construction and also the elimination of 1 rig move represents a big impact in terms of economics. Furthermore, the impact in terms of the risk reduction must be considered By combining two (2) wells in one (1) and eliminating three (3) phases in the standard well construction the harmful impact of location preparation, drilling fluids and cuttings on the environment is reduced by 45%, especially with oil base mud system. Geological problems can be observed during drilling each phase of a new well. However, drilling multilateral wells will reduce this occurrence. Well was completed with 7″× 4-1/2″ top packer, 4-1/2″ Slotted tubing and seven (7) swellable packers in lower borehole as well as Dual upper completion with 7″ single retrievable and 9-5/8″ dual retrievable packer and 2-7/8″ and 3-1/2″ tubing combination in both short and long string. This paper presents ADNOC Onshore first and successful experience in the deployment of new acquired technology for the Drilling multi-lateral / dual completion systems in BAB Field. The screening criteria for selecting the system as well as the benefits realized and lessons learned from this experience are also discussed together with the design simulations required to ensure the success of the well construction.

Well Cleanup Utilizing Smart Well Completion and Zero Flaring Technology

2021 ◽  
Author(s):  
Mohammed Alkhalifah ◽  
Rabih Younes
Keyword(s):  
Drilling Fluid ◽  
Petroleum Industry ◽  
Lessons Learned ◽  
Oil Field ◽  
Monitoring Systems ◽  
Drilling Fluids ◽  
Efficient Manner ◽  
Control Valves ◽  
Well Completion ◽  
Downhole Monitoring

Abstract In an oil field, openhole multilateral maximum reservoir contact (MRC) wells are drilled. These wells are typically equipped with smart well completion technologies consisting of inflow control valves and permanent downhole monitoring systems. Conventional flowback techniques consisted of flowing back the well to atmosphere while burning the hydrocarbon and drilling fluids brought to surface. In an age of economic, environmental and safety consciousness, all practices in the petroleum industry are being examined closely. As such, the conventional method of flowing back wells is frowned upon from all aspects. This gives rise to the challenge of flowing back wells in an economic manner without compromising safety and the environment; all the while ensuring excellent well deliverability. By utilizing subsurface smart well completion inflow control valves, individual laterals are flowed to a separator system whereby solid drill cuttings are captured and discharged using a solids management system. Hydrocarbons are separated using a separation vessel and measured before being sent to the production line toward the field separation facility. Permanent downhole monitoring systems are used to monitor pressure drawdown and subsequently control the rate of flow to surface to ensure reservoir integrity. Following the completion of the solids and drilling fluid flowback from the wellbore, comprehensive multi-rate measurements at different choke settings are obtained to quantify the well performance. This paper looks at the economic and environmental improvements of the adopted zero flaring cleanup technology and smart well completions flowback techniques in comparison to conventional flowback methods. This ensures that oil is being recovered during well flowback and lateral contribution to overall flow in multilateral wells. In addition, it highlights the lessons learned and key best practices implemented during the cleanup operation to complete the job in a safe and efficient manner. This technique tends to set a roadmap for a better well flowback that fulfills economic constrains and protects the environment.

Hollow Glass Spheres HGS in Drilling Fluid: Case Study of Preventing and Mitigating Total Losses

2021 ◽  
Author(s):  
Vitaly Sherishorin ◽  
Martin Rylance ◽  
Yevgeniy Tuzov ◽  
Olga Krokhaleva ◽  
Evgeny Tikhonov ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Scale Up ◽  
Cost Savings ◽  
Field Application ◽  
Lessons Learned ◽  
Drilling Fluids ◽  
Lost Circulation ◽  
Initial Application ◽  
General Plan ◽  
Effective Manner

Abstract The paper describes the first deployment of HGS in Eastern Siberia as a mud additive. The technology was utilized for reducing drilling fluid density for prevention and mitigation of losses; while drilling through a producing reservoir section with low pore pressure, unconsolidated and fractured sands. The engineering considerations, fundamentals of the approach and major risks involved were reviewed with application to the Sredneboutobinskoye Oilfield as a pilot field application for broader future plans. Key planning, delivery and execution principles of the initial application will be reported in the paper. Initially deployed on three wells, including multi-laterals (Rylance et al., 2021), the paper will walk through the engineering considerations during the planning and execution phases. Key sections include the data gathered and the many lessons learned during the incremental and stepwise deployment. The paper will also report on post drilling productivity and comparisons with the offset wells drilled with conventional mud systems, which suffered severe losses. The results of this pilot have exceeded expectations. There have been many insights and the Team are now looking to set a timetable to scale-up across the Taas-Yuryakh Neftegazodobycha (TYNGD). After many hours of laboratories study and preparation works, the general plan was to reduce the static density and ECD to mitigate fluid losses. However, the applied results showed additional effects from HGS. Data will be provided that demonstrated loss-free drilling was achieved where this had not been the case before, with a material reduction in NPT, lost circulation material (LCM) needs and costs. Much has been learned, recovered HGS material has been demonstrated to be an effective LCM pill and centralization of mud processing may offer additional cost savings and improvements. Further efficiencies are also expected to be achieved and future potential is considerable. HGS for cementing is well documented, yet application for drilling fluids has been less well reported and almost exclusively related to single wells. The TYNGD application is innovative as this is a major development with 10 active drilling rigs. The application is on multi-laterals and offset wells are available for direct comparison. The results of the approach demonstrate a new way of performing well construction in an effective manner for major field developments where losses are prevalent.

Drilling with Glass and Air: Using Hollow Glass Spheres to Address a Wide Ranging Drilling Challenge in a Safe, Efficient and Cost-Effective Manner

2021 ◽  
Author(s):  
M.. Rylance ◽  
Y.. Tuzov ◽  
V.. Sherishorin
Keyword(s):  
Scale Up ◽  
Cost Savings ◽  
Cost Effective ◽  
Lessons Learned ◽  
Successful Outcome ◽  
Drilling Fluids ◽  
Eastern Siberia ◽  
Hollow Glass ◽  
Glass Spheres ◽  
Effective Manner

Abstract A major development with multiple rigs delivering extensive multi-laterals encountered a pervasive mud-window issue within the reservoir. The resulting severe mud losses, extensive NPT and formation-damage was also deteriorating with time due to depletion. Conventional approaches to stem losses had failed and adoption of an energized mud-system with acceptable Effective Circulating Density (ECD) was not considered cost effective, pragmatic nor safe. Instead a novel application using Hollow-Glass-Spheres (HGS) was trialled, that demonstrated an effective and highly successful outcome. With 10 rigs drilling 60-70 wells per-year, each with 5,500 to 6,750m in the reservoir, quick resolution of the issue was required. For these reasons the Team at bp Russia looked carefully at alternatives that might fit the mud-window, but that offered a realistic approach for the environment and conditions in Eastern Siberia. The Team identified HGS as an approach to lighten the mud, often used for cementing ECD, application for drilling has been limited. For this approach we required an option with broad capabilities that could be scaled-up and exported to other development areas where such issues existed. This paper will report on the planning, delivery, and execution of a pilot on the Sb. field at TYNGD, in Eastern Siberia. Initially deployed on three wells, including multi-laterals, the paper will walk through the engineering considerations, during the planning and execution phases. Reporting comprehensively on the data gathered and the many lessons learned during the incremental and stepwise deployment. Data will be provided that demonstrated loss-free drilling was achieved where this had not occurred before, with a dramatic reduction in NPT, FLA needs and costs. The paper will also report on the post drilling productivity and comparison with offset wells drilled with conventional mud systems and suffering severe losses. The results of this pilot have beaten all expectations, there have been many insights and the Team are now looking to set a timetable to scale-up across the NOJV. Much has been learned, waste HGS material has been demonstrated to be an effective FLA pill in other sections of the well and centralisation of mud process may offer additional cost savings and improvements. Further efficiencies are expected to be achieved and potential across the Company portfolio could be a major game changer. HGS for cementing is well documented, application for drilling fluids has been less reported and almost exclusively applied to one-off sections/wells. The TYNGD application is novel as this is a major new development with 10 drilling rigs. Application is on multi-laterals and prior offset wells are available for direct comparison. The results of the approach demonstrate a new way of performing well construction in an effective manner for major Field Developments where losses are prevalent.

scholarly journals Improving Janitorial Contract Performance with Facility Management Performance Scorecards

2018 ◽  
Vol 2 (1) ◽  
pp. 26-34 ◽  
Author(s):  
Dhaval Gajjar ◽  
Jake Smithwick ◽  
Kenneth Sullivan
Keyword(s):  
Performance Measurement ◽  
Measurement Model ◽  
Poor Quality ◽  
Facility Management ◽  
Lessons Learned ◽  
Facility Manager ◽  
Low Performance ◽  
The Impact ◽  
A Performance

ABSTRACT Facility Manager (FM) role requires expertise in various aspects of facility maintenance. Due to the diverse job functions as an FM, outsourcing and hiring external vendors is a common practice in the industry to gain additional expertise. Since a facility manager oversees the external vendor's contract and the performance of the external vendor directly affects the quality of a facility, the FM's performance is ultimately related to the performance of the outsourcing company. Hence, it is critical to measure performance and the quality of the services provided by the outsourcing company. One of the FM's at a corporation (XYZ Corporation) was faced with a challenge of low performance and poor quality on their outsourced janitorial contract. The literature review revealed that there has been very little research done with regard to outsourcing of the janitorial contract. In order to address the challenge of XYZ Corporation a performance measurement model was implemented using performance Scorecards at XYZ Corporation for janitorial contracts. The Scorecard was developed based on the previous experience of the FM group, the researchers and the specific areas targeted by XYZ Corporation that were part of janitorial vendors responsibility. This paper presents the impact of the performance measurement model on the quality and performance of the janitorial vendor and its expansion to other outsourcing contractors based on the lessons learned from the janitorial contracts. The study revealed that the implementation of a performance measurement model resulted in an overall improvement of the performance of janitorial vendor and the contractors.

Successful Pilot of DIAL Digital & Interventionless Gas Lift Production Optimization System Offshore Malaysia

2021 ◽  
Author(s):  
Zaidi Awang@Mohamed ◽  
Jagaan Selladurai ◽  
Siti Nur Mahirah Mohd Zain ◽  
Juhari Yang ◽  
Badroel Rizwan Bahar ◽  
...  
Keyword(s):  
Real Time ◽  
Continuous Production ◽  
Gas Injection ◽  
Value Added ◽  
Lessons Learned ◽  
Production Optimization ◽  
Design Stage ◽  
Optimization System ◽  
The Impact ◽  
Gas Lift

Abstract Objectives/Scope This paper describes a pilot installation of a digital intelligent artificial lift (DIAL) gas lift production optimization system. The work was inspired by PETRONAS' upstream digitalization strategy with five single and dual-string gas lift completions planned from 2018 to 2020, offshore Malaysia. The authors evaluate the impact of the DIAL system in terms of increasing production, optimizing lift-gas injection, reducing well intervention frequency, as well as OPEX and risk reduction. Methods, Procedure, Process DIAL is a unique technology that enhances the efficiency of gas lift production. Downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention. The paper focuses on a well installed in June 2020, the first in a five well campaign. The authors will provide details of the technology, and pilot program phases: system design; pre-job preparations; run in hole and surface hook-up; commissioning and unloading; and subsequent production operations. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits. Results, Observations, Conclusions DIAL introduces a paradigm shift in the design, installation, and operation of gas lifted wells. This paper will compare the differences between this digital technology and conventional gas lift techniques. It will consider the value added from the design stage through installation operations to production optimization. The DIAL system's ability to operate at greater than 80-degree deviation enabled deeper injection while avoiding tractor interventions for GLV maintenance in the highly deviated section of the well. Built-in downhole sensors provided real-time pressure monitoring that enabled a better understanding of reservoir behaviour and triggered data-driven reservoir stimulation decisions. The technology also proved very beneficial for production optimization, with the intervention-less adjustment of gas injection rate and depth downhole, based on the observed reservoir response in real time. The variable port sizes can be manipulated by means of surface switch/control. Overcoming the completion challenges due to COVID-19 restrictions, the well was unloaded and brought online with the assistance of personnel located in Houston and Dubai using Silverwell's visualization software. The well continues to be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS' upstream digitization strategic vision. Novel/Additive Information First deployment worldwide of new and unique gas lift production optimization technology in offshore highly deviated well. The technology deployment was the result of collaborative work between a multi-discipline engineering team in PETRONAS, Silverwell, and Neural Oilfield Service.

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