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Collaborating Authors
Petronas Carigali Sdn Bhd
Major Greehouse Gas Reduction from Flare Verification
Mohamad Nor Azli, Mohamad Farizal Bin (Petronas Carigali Sdn Bhd) | Seah, Shi Ming (Petronas Carigali Sdn Bhd)
Abstract Membranes are utilized in Acid Gas Removal System (AGRS) at offshore platform to remove carbon dioxide (CO2) from sour gas reservoirs. CO2 selectively permeates the membrane compared to methane and the CO2 rich stream is sent to flare system as permeate flare. This permeate flare is measured by an Ultrasonic Flowmeter (USM) installed as permeate flare meter in 2020. When verification exercises was done, it was first observed that there was a huge discrepancy in mass balance values with the mass output being significantly higher than mass input by 10 to 20%. Upon verification of the inputs from permeate flare meter to Distributed Control System (DCS), it was initially hypothesized that standard density input assumptions of 0.714kg/Sm is unrepresentative of the density values of the supposedly CO2 rich permeate flare. This has caused a large overestimation of permeate flare values. Operations crew at offshore platform utilized CO2 sampling tubes as a solution for quick sampling of permeate flare and sampling results yielded CO2 compositions of 40 mol% which was the maximum limit of the tubes. Using a conservative approach of assuming the remaining composition of permeate flare to be methane, the permeate flare standard density was then estimated to be at 1.156kg/Sm. Applying these setting to the input at DCS then yielded an initial 39% decrease to permeate flare values. Meanwhile, third party analysis of permeate flare compositions are conducted on a later date with density values from permeate flare compositional analysis and differing. The team studied further into the capabilities of the permeate flare meter on live density calculation and proceed to set up trending for calculated density from the meter. The density values calculated by the permeate flare meter were comparable to sampling results. Furthermore, the mass balance between input and output has significantly been improved to be within 3% to 5% of each other. As a result, the team has successfully achieved reduction in reported permeate figure by 4.81 mmscf/d annualized or 97034.26 tCO2e.
Fenex: Enhancing Wells Field Development Plan Via Online One-Stop Centre Integrated Platform
Abd Hamid, Khairul Jafni (Petronas Carigali Sdn Bhd) | Norhashimi, Lokman (Petronas Carigali Sdn Bhd) | Omar, Ahmad Faiz (Petronas Carigali Sdn Bhd) | Khalid, M Zulfarid (Petronas Carigali Sdn Bhd) | Meor Hashim, Meor M Hakeem (Petronas Carigali Sdn Bhd) | Idris, M Ramdan (Petronas Carigali Sdn Bhd) | Yusoff, M Haniff (Petronas Carigali Sdn Bhd) | Ooi, Zhon Wei (Petronas Carigali Sdn Bhd) | Ghazali, Rohaizat (Petronas Carigali Sdn Bhd) | Sy Idrus, Sy Dzafeer (AEM Energy Solution) | Mhd Yusoff, Mohd Khairul Ikhwan (AEM Energy Solution) | Abdul Rahman, Mohd Redzuan b (AEM Energy Solution) | Garg, Rachit (AEM Energy Solution) | Tengku Abd Aziz, Tengku Zharif (Halliburton) | N Vivegananthan, Divya (Halliburton)
Abstract The Wells Front-End Loading (FEL) workflow is a critical phase in the planning and design of oil well projects, enabling efficient cost optimization and decision-making before project execution. However, the current FEL workflow suffers from inefficiencies caused by manual registration, localized record-keeping, repetitive iterations, and dynamic stakeholder expectations influenced by oil price uncertainties. Furthermore, fragmented data connectivity and the unavailability of legacy data hinder seamless data flow and digital adoption throughout the well life cycle. To address these challenges, this paper introduces Wells Front End Engineering Nexus (FENEX), a centralized web-based workflow platform that digitalizes the FEL workflow and offers anywhere and anytime accessibility. The FENEX application is supported by the Well Planning Suite (WPS) as the orchestrator to enable the execution of FEL workflow, perform detailed engineering design and ensure a smooth handover to the execution team. This manuscript presents FENEX as a comprehensive solution for improving the FEL workflow. It highlights the FENEX dashboard, critical roles of WPS and some enhancement features, i.e. introduction of features of "Campaign", workflow integration & approval process amongst the Field Development Plan (FDP) team & Technical Assurers (TA), guided workflow for well engineering and input for efficient project tracking & monitoring via FENEX. In the effort to realize FENEX, this paper will also discuss the key challenges in managing the segmented well databases between well design planning and well operational records which could impair the seamless data connectivity throughout the whole well life cycle. As such, a drastic reshaping of the data landscape was required to mitigate this where all data are consolidated into one Cloud database, wellSCAPE promoting a single source of truth for all well design, planning and operational records data. The implementation of FENEX addresses the limitations of the current FEL workflow, streamlining processes, enhancing efficiency, and reducing costs. By centralizing project data and promoting seamless data connectivity, FENEX overcomes the challenges of localized record keeping, fragmented data landscape, and the absence of legacy data. The platform empowers stakeholders to make informed decisions, optimize value extraction, and drive digital adoption in the oil and gas industry. The introduction of FENEX represents a significant step towards efficient collaboration, optimized value extraction, and enhanced evaluation efficiency. The findings of this study provide valuable insights for industry professionals seeking to streamline the FEL workflow and leverage digital tools to achieve project success in a rapidly changing energy landscape.
- Asia (1.00)
- North America > United States > Texas > Dawson County (0.40)
- Well Drilling > Well Planning (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.89)
Enhancing Well Control Safety with Dynamic Well Control Cloud Solutions: Case Studies of Successful Deep Transient Test in Southeast Asia
Abu Talib, M Ashraf (Petronas Carigali Sdn Bhd) | Ahmad Kassim, M Shahril (Petronas Carigali Sdn Bhd) | Marzuki, Izral Izarruddin (Petronas Carigali Sdn Bhd) | Azwan Azid, Aidil Aznan Azwan (Petronas Carigali Sdn Bhd) | Teaga Rajan, Santa Kumar (Petronas Carigali Sdn Bhd) | Fadzil, Muhammad Redha Bin (Petronas Carigali Sdn Bhd) | Motaei, Eghbal (Petronas Carigali Sdn Bhd) | Chua, Choon Ling (Petronas Carigali Sdn Bhd) | Jaua, Raymond Dayan Pius (Petronas Carigali Sdn Bhd) | Jamaldin, Fadzril Syafiq (Petronas Carigali Sdn Bhd) | Ting, Shui Zuan (SLB) | Daungkaew, Saifon (SLB) | Gisolf, Adriaan (SLB) | Chen, Li (SLB) | Mutina, Albina (SLB) | Yang, Jiankun (SLB) | Hademi, Noor Rohaellizza (SLB) | Nandakumal, Ravinkumar (SLB) | Wattanapornmongkol, Sawit (SLB)
Abstract The objective of this paper is to address the challenges related to well control and highlight the successful implementation of deep transient tests (DTT) operations in an offshore well located in Southeast Asia that was carried out by PETRONAS with the help of a dynamic well control simulation platform. The paper aims to provide insights into the pre-job simulation process, which ensured a safer operation from a well control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation will be presented. The latest DTT technology enables a higher volume of gas or hydrocarbon to be pumped into wellbore compared to formation tester (FT) operation. During the DTT operation, the pumped formation fluids are mixed with mud that is pumped from surface through a circulation sub into the annulus, and the mixture of fluids is then circulated out from annulus simultaneously to the surface during the drawdown period. To ensure well control safety, it is crucial to have a comprehensive understanding of the processes involved. Therefore, a dynamic multiphase flow simulator that takes into account the interactions between downhole pumped hydrocarbon and drilling fluids is important to better simulate the pressure downhole throughout the DTT operation. In this case study, simulations were conducted prior to the job execution, considering several sensitivities, to ensure that the operation stayed within a safe operating mud weight window while meeting the surface gas handling limits. During DTT execution, real time downhole measurements were sent to a cloud-based platform, where they were plotted on a graph alongside the simulation data for monitoring purposes. Any changes in observed formation fluid, downhole flow rates and mud circulation rates during the DTT operation were quickly reflected in the simulation, this enabled effective communication between the PETRONAS project and execution teams ensuring a safe well control condition throughout the operation. As a result, the DTT operation was conducted successfully and safely, with the measured data aligning well with the simulations. The accurate wellbore dynamics simulator allowed for quantification of changes in drilling fluid design, circulating rates, hydrocarbon composition, downhole pump rates, and pump duration for various formation testing design sequences. It also facilitated predictions of downhole well pressure, free-gas distribution along the well geometry, and gas rate on the surface. This valuable insight provides PETRONAS with more flexibility in understanding and planning advanced FT operations, while enabling larger volumes of hydrocarbons to be pumped downhole. Furthermore, adopting an advanced pressure transient testing method like DTT is in line with both industry and PETRONAS's efforts to reduce carbon dioxide emissions.
- Asia > Malaysia (0.95)
- Asia > Middle East > UAE (0.28)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.85)
Unlocking High CO2 Wells - Strategy for Achieving Optimum Gas Blending Ratio
Mohd Fauzi, Nurul Adlina (Petronas Carigali Sdn Bhd) | A. Rahim, Nurul Afiqah (Petronas Carigali Sdn Bhd) | Gazali, Muhammad Yusri (Petronas Carigali Sdn Bhd) | Giri, Emelia (Petronas Carigali Sdn Bhd) | Mohd Nawi, Mohd Shakir (Petronas Carigali Sdn Bhd) | Raja Azman, Raja M. Rafiyudeen (Petronas Carigali Sdn Bhd)
Abstract Platform X has four (4) Non-Associated Gas (NAG) wells with total production rate of 75 MMscfd. Due to their high CO2 content ~ 10-13 mol%, NAG production were capped at production operating philosophy of 30 MMscfd. They were produced thru blending them with Associated Gas (AG) wells (ratio 50:50) to meet 8 mol% CO2 limit at pipeline from Platform X to gas processing hub (Platform Y). In a normal production, only two (2) NAG wells flowing, two (2) NAG wells remain idle causing a loss in production opportunity. The study was conducted to further unlock NAG potential by revisiting the blending NAG:AG ratio. Few steps were outlined for the study workflow; surface facilities readiness, data collection on-site CO2 gas sampling and flaring monitoring, data analysis thru Aspen HYSYS model simulation for theoretical and sensitivity data, and risk assessment for revised blending ratio. From the study, Platform X gas production can be optimized up to 55 NAG: 45 AG blending ratio. Actual on-site sampling dictates CO2 mol% at pipeline from Platform X to Platform Y to be around 7.5 mol%. It is comparable to Aspen HYSYS simulation result indicating a good model tuning. Sensitivity analysis generated from the model implies that the higher AG production, the higher NAG production as more gas can be blended with low CO2 content of AG well. Risk assessment stated overall risk-rating is low. Platform X is allowed to flow continuously with the revised blending ratio provided that wells flow rates not exceed the blended CO2 limit. Additional gas yielded is 7 to 8 MMscfd, daily estimated revenue ranges from RM 188,000 to RM 215,000. Flaring is able to sustain ~0.4 MMscfd, below Platform X limit of 1 MMscfd.
- Facilities Design, Construction and Operation > Processing Systems and Design > Process simulation (0.97)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (0.73)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.71)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.70)
Abstract Very high concentrations of CO2 have been encountered in solution as carbonic acid in hydrocarbon reservoirs in parts of the Greater Sarawak Basin, offshore Borneo, Malaysia. Concentrations can exceed 80%. Anomalous features in 3D seismic data also are found in areas with high CO2 concentrations. These features appear as halos around reservoirs, cutting across stratigraphy and indicating a hardening of the nonreservoir rocks within the envelope of the halo. These halos can extend for hundreds of meters above and below a reservoir. Elastic log data from wells that pass through and adjacent to these seismic anomalies indicate that mudrocks within the anomalies have higher densities and velocities than would be predicted from locally derived compaction trends. Combinable magnetic resonance measurements indicate that the anomalous properties are the result of lower-than-expected capillary-bound microporosities. It is proposed that carbonic acid in the reservoir fluids diffuses into the bounding rocks, causing a loss of porosity. The amount of porosity lost depends on the clay content of the mudrock and the initial level of compaction, with shallower, more clay-rich shales able to lose more porosity. The anomalous seismic signatures result from a sharp transition (over approximately 5 m) at the diagenetic front between normal and altered rocks. The alteration can significantly change the amplitude variation with offset response of the reservoirs and therefore the ability to correctly predict fluid phase and reservoir quality. No anomalies are observed when the concentration of CO2 in the reservoir is less than 10% but always present when CO2 exceeds 20%. Therefore, it is possible to map the general distribution of high CO2 concentration from seismic data. There is no indication that the scale, amplitude, or shape of the anomalies gives an indication of the concentration of CO2.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.53)
A Novel Conveyance Technology, Allied with an Analytical Approach, Unlocks Significant Reserves
Mokhtar, M. Khaidir B. M. (Petronas Carigali Sdn Bhd) | Leong, C. H. (Petronas Carigali Sdn Bhd) | Intang, E. D. (Petronas Carigali Sdn Bhd) | Chii Seen, H. (Petronas Carigali Sdn Bhd) | Ho, Y. Y. (Petronas Carigali Sdn Bhd) | Angelis, Y. (G A R&D Ltd) | Mitchell, D. (G A R&D Ltd) | Carroll, V. R. (Hadari Eng Services Sdn Bhd) | Carroll, B. (Hadari Eng Services Sdn Bhd)
Abstract Intervening in wells with challenging geometry is costly, often to the point that marginal producing wells may be prematurely shut-in. This paper details a novel, cost-effective approach taken when planning to intervene in a highly challenging well with the objective of bringing it back on-line after an extended shut-in period. The methods used for conveying intervention tool string into oil and gas wells have developed significantly during the last forty years. As well geometry became ever-more-complex due to the adoption of directional drilling, it became apparent there very few options available in a toolbox to ensure delivery of intervention tool string to Target Depth (TD) in a cost-effective manner. In response to this emerging challenge, a host of well service techniques and technologies have been introduced. One methodology that has delivered a real step-change, in terms of reducing well intervention expenditure and risk, has been the use of gravity-deploy mechanical roller systems. This lighter well intervention technique is now widely adopted by Industry and proven to reduce the use of more costly solutions such as wireline tractor and coiled tubing for pure conveyance reasons. The paper details the impact of selecting a ‘next-generation’ gravity-deployed mechanical roller technology to undertake a remedial sand control well-intervention programme in a particularly challenging, highly deviated, dual oil producing well using slickline. The well had been shut-in for two-and-a half years with recent attempts to intervene using conventional roller tools proving unsuccessful. The paper will inform the reader of technology selection based on the ability of a highly efficient rolling system to convey toolstring to target dept, containing no fastners, therefore reducing overall risk to asset. Other critical factors included pre-job conveyance modelling, tool string design and a highly-successful collaboration between well owner, service company and technology provider through their regional partner. As well as significant challenges that were overcome to convey tool string to the high-deviation target, critical impact force was also delivered when in-situ, to ensure successful setting of sand screen assembly. Key to success was a willingness to rapidly adjust the well intervention plan by adopting industry best practice through lessons learned on a run-by-run basis. This resulted in successful setting of thru’ tubing sand screens in a cost-effective manner, ensuring that a valuable well was brought back on to production once again, delivering significant addition to recoverable field reserves. The success of this intervention programme has led to wider adoption of next-generation conveyance technology using slickline methodology, before considering the use of wireline tractor or coiled tubing to undertake the same programme of work.
- Asia (0.47)
- North America > United States > Montana > Sheridan County (0.24)
Restoration of High-Temperature Well Integrity via Real-Time Coiled Tubing Patch Application
Karpaya, Shaturrvetan (Petronas Carigali Sdn Bhd) | James Berok, Sylvia Mavis (Petronas Carigali Sdn Bhd) | John Peter, Brandon Joseph (Petronas Carigali Sdn Bhd) | Muchalis Utta, Arie (Petronas Carigali Sdn Bhd) | Barat, Junnyaruin (Petronas Carigali Sdn Bhd) | Ellen Lidwin, Sharon (Petronas Carigali Sdn Bhd) | Abdul Rahman, Hazrina (Petronas Carigali Sdn Bhd) | Maluan, Lilihani (Petronas Carigali Sdn Bhd) | Sidek, Sulaiman (Petronas Carigali Sdn Bhd) | Mustika Purwitaningtyas, Imania (Schlumberger) | Chin Pui Ling, Jennie (Schlumberger) | Albouy, Charles (Schlumberger)
Abstract A prolific gas producer in Sarawak waters was shut-in and idle due to a tubing leak resulting in a significant decline in the total hub production. The well remained idle and required immediate remedial action to meet the contractual sales target. Hence, an expandable tubing patch was proposed to isolate the leak and reactivate the well faster. This paper presents data gathered to identify leak location, tubing patch design, and installation using real-time coil tubing. Several logging surveys were performed to detect leak depth including caliper log, leak detection log (LDL), and downhole camera run; since no pressure build-up was observed post bleed-off tubing and casing, while SCSSV was in closed-state. Running caliper log could not indicate severe metal loss of 7-inch tubing, hypothesizing that the leak could be of a smaller dimension. Therefore, LDL was conducted, indicating temperature gradient and acoustic energy changes at a single depth location of 247 ft.THF, above SCSSV. Utilizing the leak depth marker from acoustic log, a downhole camera was staged to verify geometry of tubing leak. Root cause failure analysis (RCFA) was carried out for this tubing anomaly using diagnostics data to determine the possibility of UHP-17Cr-110 tubing failure. The likelihood of tubing failure is attributed to two main causes namely oxygen corrosion cracking and stress corrosion cracking. Based on RCFA outcome, Hastelloy C276, a nickel-molybdenum-chromium superalloy with the addition of tungsten was selected for the patch material, which is V0 rated, internal gas-tight qualification for temperatures up to 150 degrees Celsius and 5,000 psi. Moreover, this patch material satisfies the well conditions at approximately 20% CO2, 200 ppm H2S, 1000 mg/L salinity, and varying Hg concentrations from 800-2,000 ug/Nm3. The design of patch has been improved by adding AFLAS elastomer for the whole exterior of patch to eliminate contacts between the two metals: reducing the risk of galvanic corrosion. Real-time coiled tubing application was selected for setting the patch to ensure accurate depth-sensing control. Additionally, patch is a rig less intervention technique that will not disrupt the production from the existing wells sharing the same drilling platform. Generally, for high-rate gas wells, economic indicators seem lucrative with tubing patch application, where the payout can be achieved within a month of continuous production. The first step in ensuring the success of tubing patch is by running right diagnostics tools such as leak detection logging and downhole camera run, since multi-finger caliper analysis alone would not locate the leak depth and the leak geometry precisely. Valid design inputs are quintessential for the fitting recommendation of tubing patch design which includes accurate reservoir and fluid properties to ensure sustainability of the expandable tubing patch application.
- Asia > Middle East > UAE (0.28)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (4 more...)
Holistic Performance Review of Through-Tubing Sand Screen as Remedial Sand Control: Best Practices and Lesson Learnt from Past Installations in Offshore East Malaysia Oil Fields
Tang, Catherine, Ye Lin (Petronas Carigali Sdn Bhd) | Yeap, Wei Jian (Petronas Carigali Sdn Bhd) | Zulkifli, M Zin (Petronas Carigali Sdn Bhd) | Bt M Jeffry, Suzanna Juyanty (Petronas Carigali Sdn Bhd) | Minggu, Nur’ain (Petronas Carigali Sdn Bhd) | Chin, Alvin, Zhi Siang (Petronas Carigali Sdn Bhd) | Kong, Randy, Zheng Chen (Petronas Carigali Sdn Bhd) | M Yusof, Aqil (Petronas Carigali Sdn Bhd) | Liew, Paul Lyan (Petronas Carigali Sdn Bhd) | Azman, Muhamad Syazwan (Petronas Carigali Sdn Bhd) | Praveen, Kumar (Petronas Carigali Sdn Bhd) | Yusnawannie, Ilyas (Petronas Carigali Sdn Bhd) | Fahmi Amni, Mustafaal Bakeri (Petronas Carigali Sdn Bhd) | B Zainul, Zaimi (Petronas Carigali Sdn Bhd)
Abstract Low oil prices, coupled with operational challenges in offshore environment due to COVID-19 restrictions, have driven oil and gas operators to implement low-cost technological solutions to optimize fields’ production. For mature oil fields in offshore East Malaysia, sand production has become one of the onerous challenges that requires this approach. Sand production is known to adversely affect the well deliverability and it also contributes to safety concerns due to surface flowline leak and equipment failure. Hence, it is of upmost importance for operators to address the sand production downhole. To achieve this, through-tubing sand screens (TTSS) installation is opted due to its ease of installation and low-cost slickline operation. Although there have been many TTSS installations to date, there is still limited understanding of the factors that affect TTSS lifespan, and this has led to frequent TTSS changeout. Based on the operator's experience, TTSS lifespan can vary significantly across different wells ranging from just a few days to years of production. To improve the understanding of TTSS performance with the aim to increase TTSS longevity, a comprehensive study on potential contributing factors has been conducted by analyzing the past TTSS installations. Over the years, there were more than 75 TTSS installations performed in oil fields offshore East Malaysia. Lookback analysis was conducted to evaluate the effectiveness of TTSS as remedial downhole sand control and investigate the factors affecting TTSS performance such as TTSS type, well production rates, TTSS deployment method, installation depth relative to perforation interval and well interruption frequency. Several criteria identified as the key performance indicators have been investigated to evaluate the performance of each TTSS installation, including the well flowing parameters, production uptime and sand production trend. Thorough study across different TTSS installations has concluded that TTSS lifespan varies according to well properties and well operating parameters. This paper presents best practices and lessons learnt from past installations to predict and improve the mean time between failures (MTBF) for TTSS. Case studies for several wells have been scrutinized to highlight the learnings for further enhancement of TTSS lifespan. Additionally, recommendations for further research and development of erosion resistant TTSS technology are also discussed.
- Well Completion > Sand Control > Screen selection (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Cost Effective Plug And Abandonment Operations Through Acoustics Based Hydraulic Isolation Diagnostics
Troup, Duncan John (Archer) | Khalid, Muhammad Idham (Petronas Carigali Sdn Bhd) | Ismail, Syahezat (Petronas Carigali Sdn Bhd) | Batulemai, Sathish Kumar (Archer Well Company, M Sdn Bhd)
Abstract Presence of undesired and unplanned fluid movement in the wellbore is a major concern for operators through-out a well's life cycle. This happens when the barrier system of the well fails to provide the required isolation. Cemented sections are important barrier systems where failure of isolation can cause numerous issues such as emission to surface, undesired water production, depletion of gas drive mechanism, loss of production to the neighboring zones, contamination of freshwater sands and reservoir damage. Priorities are often given to ensure cement integrity during the plug and abandonment (P&A) phase to eliminate uncontrolled emission to surface post P&A. Deployment of two new generation acoustics technologies will enable operators to comprehensively identify these undesired/unplanned fluid movement in the wellbore and also indicate cement quality in annulus by running in tubing prior to P&A campaign in rig-less mode. The technology responsible to determine hydraulic seal consists of full-spectrum acoustics sensors that accurately identifies downhole leak or flow behind pipe through industry leading sensitivity & broadest frequency bandwidth sensors. The cement sheath quality meanwhile can be determined through deployment of multi-string isolation logging technology that provides multi-layer cement bond quality measurement. Unlike conventional cement bond logs and ultrasonic imaging logs which requires prior removal of production tubing from the wells, the multi string isolation logging technology diagnoses the cement sheath quality without the need to pull the tubing. Both of this technology can be deployed in the same run. The accurate assessment of cement bond and isolation conditions in multi-layered configurations not only reduces unnecessary costs, but significantly simplifies the traditional P&A process altogether. While many P&A operations can run as high as $500,000 per day, new generations acoustics based downhole leak and flow detection technology coupled with multi-layer cement bond quality measurement technology drastically reduces overall expenditure and ensures the most efficient operation process. It also paves the way in innovation for a wider range of rigless P&A solutions. The proposed technology are unique products of Archer and Probe. The combination run also indicate the value that can be generated from collaboration within technology providers in the industry.
Successful Delivery of Slim Well Design Concept for Future Marginal Fields
Abu Bakar, Nurul Nadia Ezzatty (Petronas Carigali Sdn Bhd) | Hod, M Aizat Haidi (Petronas Carigali Sdn Bhd) | Abitalhah, M Abiabhar (Petronas Carigali Sdn Bhd) | Omar, Ahmad Faiz (Petronas Carigali Sdn Bhd) | Abdul Hakim, Hazlan (Petronas Carigali Sdn Bhd)
Abstract This paper will discuss the key focus areas in successfully delivering a slim well design as a Proof Of Concept (POC) for marginal fields and well cost optimization. Well Tall-A is a Near Field Exploration (NFE) well targeting marginal reservoir which utilize the slim well concept; a 2-hole section well with 9-5/8" as the conductor. For a successful well execution, three (3) key focus areas were identified which are successful operation of 9-5/8" Casing While Drilling (CWD) to section TD, sustainability of 9-5/8" casing as conductor for the whole well life cycle and achievement of well objectives. Tall-A recorded the longest and successful 9-5/8" CWD Level 2 (non-directional) for Asia Pacific with 1168m drilled footage as of year 2020. Lessons learnt from previous PCSB 9-5/8" CWD operation were incorporated for casing bit selection hence a heavy-set casing bit (8 bladed) which has been proven in drilling long hole interval in the Middle East (>1000m) was utilized. Continuous monitoring during execution is essential in ensuring the casing is set at the desired setting depth. Sustainability of the 9-5/8" casing as conductor for the whole well life cycle is critical for a slim well design concept. Several studies and extensive discussions between multiple parties has been incorporated to enable utilization of the 9-5/8" as conductor with required sufficient tension to sustain the exploration well lifecycle. A conductor study was performed which incorporated the Metocean data, rig data and connection Stress Concentration Fatigue (SCF) to qualify the 9-5/8" as conductor. To meet the primary and secondary targets; the 8-1/2" hole needs to be kicked-off early and build up to maximum 44 deg before maintain tangent to final TD at 2752m MDDF. Due to the long open hole (1475m) and well inclination within the avalanche hole cleaning regime (30 to 60 deg), the well is prone to hole cleaning problem and wellbore instability. Hence, it is critical to have good drilling practices and precise mud weight selection to ensure no hole problem encountered. The well was successfully drilled to TD, completed the well testing and P&A. In summary, well Tall-A successfully maneuvered all challenges to deliver the well safely that resulted in Best In Class (BIC) performance. The slim well design concept has been proven achievable and serve as base design for future marginal wells.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Well Drilling > Drilling Operations > Running and setting casing (1.00)