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Results
Application of High-Definition Reservoir Scale Mapping-While-Drilling with Comprehensive Formation Evaluation in the Challenging Low Resistivity Contrast Environment
Wahid Ali, Nurul Athirah (Petronas Carigali Sdn. Bhd.) | Alang, Khairul Anuar (Schlumberger) | Wang, Haifeng (Schlumberger) | Goh Jin Wang, Arthur (Petronas Carigali Sdn. Bhd.) | Chuah Mei Mei, Stefanie (Petronas Carigali Sdn. Bhd.) | Sapian, Nik Fazril Ain (Petronas Carigali Sdn. Bhd.) | Bt M Zaid, Siti Nurfarhana (Petronas Carigali Sdn. Bhd.) | Rafiuddin, Nur Liyana (Petronas Carigali Sdn. Bhd.) | AL Naupa, Nagarajan (Petronas Carigali Sdn. Bhd.) | A Aziz, Khairul Ikram (Petronas Carigali Sdn. Bhd.)
Abstract The horizontal wells within the context of this case study are located offshore Malaysia, where the reservoirs vary in grain size and quality. The infill wells include 3 oil producer wells targeting S reservoir and 1 horizontal sidetrack well targeting R1-R3 subunit reservoirs. The horizontal wellsโ objective is to optimize minimum lateral length of 1,000-2,000ft MD at 1/3 vertical standoff from GOC within the target oil column. Based on recent data from offset wells, the fluid contacts (GOC and OWC) remained uncertain, hence well placement within the target oil column becomes the main challenge. The wells are expected to have low resistivity contrast between oil and water composition. In this kind of reservoir environment, the standard reservoir mapping tool may not be sufficient for differentiating reservoir fluid properties of oil and water bearing formation. For such challenging condition, an integrated real-time well placement technology, high tier triple-combo logs, Neutron Near- Far count and Formation Sigma measurements were deployed to fully achieve drilling objectives. 3 horizontal wells with 1 horizontal sidetrack well were successfully executed within the target zone, achieving objectives beyond expectation. A new generation of LWD tool including high-definition reservoir mapping-while-drilling technology with advanced inversion was deployed to fulfill geosteering requirements. The workflow presented in this project is a synergized scope of multi-domain, from both drilling and subsurface. This case study demonstrated the value of high-definition reservoir scale mapping technology. It provides an innovative and deterministic method to identify low resistivity low contrast boundaries of oil from transitional water zone which was difficult to be achieved by conventional reservoir mapping tool. At the landing section, the high-definition tool helped to reveal clearly OWC below the tool with greater confidence compared to the standard tool. The information from the high-definition tool, paired with the fluid identification offered from Neutron-Density and Neutron Near- Far count together were essential for an accurate landing. The usage of reservoir scale mapping technology in the horizontal section revealed the tilted OWC and reservoir structure at the same time, which allowed the team to achieve the required minimum production length while maintaining required standoff from the OWC. All wells were geosteered successfully with the accomplishment of placing the trajectories in optimum positions despite having a tight TVD window.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
Effective Well Engineering Approach for Completion Intervention, Stimulation and Flow Measurement to Enhance Efficiency and Production Performance
Alharbi, Ayman (Saudi Aramco) | Khan, Abdul Muqtadir (Schlumberger) | AlObaid, Hashem (Saudi Aramco) | Ashby, Scott (Saudi Aramco) | Ahmed, Danish (Schlumberger)
Abstract Well completion practices in high-temperature, high-pressure carbonates are challenging especially for long lateral horizontal wells intended for fracturing applications. An integrated approach involving intervention and fracturing design and reliable post-fracturing flow measurements is very critical to optimize the well performance. After initial intervention complexities due to wellbore accessibility in a 6,250-ft cemented lateral initially planned with 13 fracturing stages resulting in the loss of many operational days, a revamped engineering workflow was planned for Well-A. As a first step, Coiled Tubing (CT) was used for abrasive jetting perforations, cleanout, and acid squeeze functionalities with a novel bottomhole assembly (BHA). The BHA was equipped with a real-time telemetry to optimize intervention to a single run. Having real-time bottomhole parameters helped in perforating the desired zones accurately and enhanced the injectivity by creating cleaner perforation tunnels. Stages were reduced to five with an optimized perforation design based on rock typing approach, and short clusters were designed to divert the fracture fluids effectively using multimodal particulate diversion. Each fracturing stage was isolated with a mechanical plug. A novel high-frequency pressure monitoring technique that analyzes fluid entry points from water hammers was utilized during the fracturing treatments to analyze on-the-fly diversion efficiency and optimize further treatments. A multiphase flowmeter was utilized to enhance milling and flowback to minimize losses and manage the choke schedule based on actual well performance leading to better fracture cleanup and recovery. The production performance of Well-A was compared with two offset horizontal wells drilled azimuthally parallel, intersecting the same carbonate sublayer. The post-fracturing absolute production enhancement analysis showed 11 to 15% improvement, and productivity index (PI) improvement was 40 to 63% when normalized by stage count. The effective integration of multiple technologies was applied successfully on the candidate well, yielding enhanced operational efficiency with optimized production performance.
- Asia > Middle East > Saudi Arabia (0.69)
- North America > United States > Texas (0.47)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
An Integrated Approach in Pore Pressure Prediction Contributes to Drilling Success of a HPHT Wildcat Well in South China Sea
Guan, Lijun (CNOOC Shenzhen) | Wang, Xiannan (CNOOC Shenzhen) | Wang, Shanshan (Baker Hughes Company) | Zhou, Yongsheng (Baker Hughes Company) | Ong, See Hong (Baker Hughes Company) | Ghosh, Amitava (Baker Hughes Company) | Wiprut, David (Baker Hughes Company)
Abstract An accurate pore-pressure prediction plays an important role in well planning as exploration targets shift to deeper over-pressured reservoirs. Pore pressure related problems in high-pressure high-temperature (HPHT) wells include well control, lost circulation, formation breathing, differential sticking, reduced penetration rate, and reservoir damage, many of which can potentially lead to expensive sidetracks, underground blowouts and early well abandonment. An integrated approach can help with better understanding the pore pressure regimes, including generating mechanisms as well as pressure preservation and dissipation processes through geologic time. This improved understanding provides invaluable insight into the different drilling challenges and the strategy to mitigate or minimize pore pressure related problems. Once the pore pressure model is established, the in-situ stress tensor needs to be constrained following a well-developed geomechanical modeling workflow. Both the pore pressure and in-situ stress models are required for wellbore stability analyses to understand wellbore failure mechanisms as well as the design of optimum mud weights. Additional considerations include drilling through faults, which due to the field's unique structural characteristics could further complicate the already difficult drilling condition in a HPHT environment. This paper presents a case study to highlight the utilization of an integrated approach for pore pressure prediction to reduce drilling risks and costs of a HPHT well located in South China Sea. Prior to drilling, the major risk anticipated for this well, which was required to explore a deep-play at 5 Km MD, was high-pressure (1.53 sg at 4800 m TVD) and high-temperature (172 ยบC at 4800 m) with narrow margin drilling conditions. Geomechanical studies that include both pre-drill and real-time (RT) drilling components provided inputs for effective well designs and drilling operation supports. Compared to the drilling of an offset well which had to be prematurely terminated due to continuous high total gas encountered despite increased mud weights, the planned well was successfully drilled to the target zone with no issues even drilling at high rate of penetrations (ROP). This new drill was the best well ever recorded in the block. The adaptation of the integrated approach in pore pressure prediction has successfully reduced the occurrence of borehole instability related problems and the associated non-productive time (NPT). The drilling performance and well delivery efficiency of future wells will improve with additional operational experience and geomechanical understanding obtained from additional drilling. This continuous learning process will be the key aspect of this project, ultimately contributing to the overall success of the field development.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.30)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- Asia > China > South China Sea > Pearl River Mouth Basin > Huizhou Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 237 > Green Canyon 237 Field > Wang Well (0.97)
Abstract With the aid of a multiphysics simulator, we recently presented a novel utilization of a degradable fluid loss additive (DFLA) as a fracture geometry additive to reduce the pad volume while achieving the same geometry. Here we extend the advanced slurry flow modeling with production simulation to propose the optimum design strategy for fracturing, which may challenge current treatment design conventions. A novel workflow was developed with four coupled working blocks of laboratory, slurry flow modeling, production analysis, and machine learning. High-fidelity simulations were conducted with planar 3D geomechanics coupled with high-resolution material transport. Materials presence was defined in each grid cell as the mixture of proppant, polymer, and fluid loss additive (FLA) with given volume fractions. Fracture conductivity distribution was calculated using laboratory correlations for fracture damage of each material combination. The results were then transferred to a fracture productivity calculator to analyze the impact of polymer and FLA on post-fracturing productivity index (PI). First, a regression model was built with 32 multiphysics model outputs to create an equivalency for pad volume with and without FLA, which varied from 42% to 57% for different leakoff scenarios. Second, the laboratory results showed a logarithmic dependence of proppant pack conductivity on the FLA mass with almost 80% loss at an FLA/proppant ratio of 0.01. Consequently, three pump schedule categories of baseline (no FLA), FLA, and DFLA were used with multiple treatment sizes based on common field experience in each category. Pad volume design was based on the regression results, and the conductivity calculations were based on experiments. It was observed that for a smaller treatment size, lower FLA mass is required, and the loss of conductivity was negligible; hence, excess polymer caused 15% lower PI only. For larger treatments covering net pay thicknesses, the FLA and polymer damage together can decrease production up to 50%, and hence DFLA is the optimum option showing the maximum production potential. Additionally, we investigated the effect of real field ranges of reservoir permeability, reservoir pressure, and flowing bottomhole pressure for each of the above designs to present a flowchart specific to the reservoir conditions. The new digital framework proposes solutions to the limitations of current methodology. The multiphysics fracture and productivity calculator reveals the underutilized potential of degradable chemistry in fracturing treatments with minimal investment. We demonstrate that computationally coupled models enable swift, accurate, and engineered decision-making for optimum asset development.
- North America > United States (0.68)
- Asia > Middle East > UAE (0.29)
- Asia > Middle East > Oman (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Well Portfolio Optimisation: Accelerating Generation of Well Intervention Candidates with Automated Analytics and Machine Learning - A Case Study from Attaka Field, Indonesia
Siahaan, Edwin (Pertamina Hulu Kalimantan Timur) | Mamat, Irwan (Pertamina Hulu Kalimantan Timur) | Laksana, Senna Sun (Pertamina Hulu Kalimantan Timur) | Setyowibowo, Agung (Pertamina Hulu Kalimantan Timur) | Naufal, Aulia Ahmad (Schlumberger) | Wulandari, Octy Edriana (Schlumberger) | Metra, Sabrina (Schlumberger) | Nainggolan, Ardi Karta (Schlumberger) | Arinandy, Okky Idelian (Schlumberger) | Ellen, Livia (Schlumberger) | Pramita, Maharani Devira (Schlumberger) | Tjiong, Agnes (Schlumberger) | Wilian, Yus (Schlumberger) | Songchitruksa, Praprut (Schlumberger)
Abstract Advancements in technology, complemented with the abundance of static and historical data brought AI and digital automation adapted very well into the oil and gas industry. Specially to solve the challenges by the engineers in selecting well intervention candidates. In Attaka Field, a multi-layered offshore field in Indonesia, workover and well service (WOWS) have been one of the strategies to reduce production decline. With traditional workflows that absorb data from multiple unconsolidated sources and data format and resource limitation, reviewing 400+ wells that penetrates more than 200 reservoirs may take 2-3 months process with a reduced scope of review. As an addition, not all data and values are justified for the prioritization process. An intelligent automated solution termed as WEPON was developed to improve decision speed and quality in Attaka Field WOWS candidate screening. WEPON was built on top of a data science platform to ease the development, production and maintenance of the analytics engine and its data pipeline. More than 15 data sources, ranging from reservoir properties, allocated production data, up to well schematics were consumed and aggregated in this solution's flow. The main components for WEPON includes: 1. Technical analysis with analytics and ML plus multi-criteria decision-making process to identify high potential completions, both produced and virgin ones 2. Adopting from the field's old workflow, feasibility checks to surface and subsurface constraints for the proposed completions 3. Diagnosing the wells and determine the right workover/ intervention opportunities 4. Calculating each well's subsurface and surface risks, and historical success rate to be integrated with the well's NPV to produce its expected value (EV) 5. Running on-demand economic analysis accessible from the solution's UI, the engine is tied into the operator's economic analysis tool that contains the currently used calculation and scheme 6. A presentation of the results on a web-based application. As the main process is triggered to be run on a weekly basis, the automation of WEPON helps to increase Attaka Field review size to the whole fields, as well as reducing 89.7% of time from 3 days to review a well to hours of run to review the whole field, enabling engineers to spend more time on high-cognitive components of the existing workflows. Moreover, it has shifted the approach to a more data-driven one leading up to smarter decisions. The implementation of this WEPON is the pilot in the Indonesian National Oil Company, PERTAMINA. This is also the first time the solution developed on a data science platform, allowing the tool to be evergreen and extensible process. This implementation is also the first one to integrate an economic analysis tool through its API.
Enabling Multidisciplinary Collaboration in Rig Acceptance via Digital Rig Acceptance Workflow (DRAW) Solution
Azman, Rashidil Arif (Faazmiar Technology Sdn Bhd) | Meor Hashim, Meor M Hakeem (PETRONAS Carigali Sdn Bhd) | Norhashimi, Lokman (PETRONAS Carigali Sdn Bhd) | Norazman, Nor Ashraf (PETRONAS Carigali Sdn Bhd) | Arriffin, M Faris (PETRONAS Carigali Sdn Bhd) | Ghazali, Rohaizat (PETRONAS Carigali Sdn Bhd)
Abstract With the current rig acceptance workflow practiced by operators globally, the process efficiency gap has been apparent for years. Redundancy, accountability issues and resource wastages can be quite complicated. In a typical workflow, the issues encountered include lack of accountability by inspectors toward item closure, inability to generate snapshots of current status, limited access due to current update via e-mail distribution only, and inefficient process as updates have to be emailed to inspectors. Report formats are not standardized across different disciplines hence the experience is not seamless as there is no one-stop center to view aviation, marine, and HSE inspection items. In fact, some inspection items across disciplines are redundant to each other. The digitalization of rig acceptance workflow can help to overcome these pain points by having a single platform to allow multidiscipline parties to keep tabs on rig activation status and updates throughout company-wide operations globally during the rig acceptance process. The paper approaches the subject by introducing a much leaner and more seamless method for conducting rig acceptance. This can be achieved by having a web-based one-stop center for all things related to rig acceptance (i.e., marine, rig, HSE, and aviation). It grants the ability for inspectors and designated personnel (e.g., DSV) to insert comments for each finding as well as the ability for inspectors to assign and edit severity levels (P1/P2/P3) for each finding. The single platform approach allows the possibility to link up the other checklist and findings on the same system and immediately reduce the redundancy of certain items that is similar to other checklists, which can be streamlined online. Therefore, implementation of this Digital Rig Acceptance Workflow (DRAW) solution can produce a user-friendly online platform to allow inspectors, project teams, management, and rig equipment subject matter experts to access the system anywhere, anytime. DRAW allows status updates (i.e., open/ongoing/close) and clarifications to be communicated via a single platform. It utilizes data input to produce actionable insights (i.e., pie/bar charts, P1/P2/P3 status, etc.) hence generating direct business value via improving process cycle efficiency in a project well life cycle.
Abstract The company has extensive experience in holistic sand control and solid management for shallow water environment. Application to near-future marginal deepwater project called L-B cluster requires higher considerations on subsea umbilical, risers, and flowlines (SURF) integrity and long term well performance due to the high-cost environment. Representative field samples (e.g., cores, drill stem test (DST data) to study rock mechanics is scarce with limited in-situ stresses calibration information. This paper presents the workflow undertaken by team to de-risk and establish the downhole sand control design for both oil producer (OP) and water injector (WI) covering design, installation, and production operations philosophy. The workflow started with an extensive multidisciplinary analogue field study covering regional geological study on sand correlation to determine correct reservoir analogue as well as the deepwater fields sand control best practices and lesson learnt. Since the analogue field already have production, the study was extended to cover the production impairment impact trend and the implementation approach to derisk the field attainability target. Based on geological and geomechanical understanding, L-B regional deepwater formation characteristics with interbedded sand and shale formation does not suit certain types of sand completion methodology, as it introduces additional risk: Deformation of expandable sand screen due to the different expansion rate of sand and shale during depletion, creating weak points in which sand is mobilized into the screen tears resulted from deformation Uneven proppant placement in cased hole frac pack for OP Loss of active sand control for a cased hole frac pack and open hole gravel pack in WI due to proppant flushed away which can be further exacerbated by uneven placement This resulted in the following lower completion strategy: Open Hole Gravel Pack (OHGP) for OP and Open Hole Stand Alone Screen (OHSAS) for WI Allowance for backflushing in WI to remove screen plugging while managing risk of reverse flow impact Sufficient rathole and long horizontal well completion as dampener to minimize magnitude of water hammer/adverse reverse flow impact in WI. For detail design, team devised comprehensive laboratory analyses covering Particle Size Distribution (PSD) and Sand Retention Test (SRT) inclusive of geomechanics modeling work for screen sizing and estimation of fines production through screens. Result is then used to devise method to minimize and manage fines production in SURF and topside. The holistic approach of sand control workflow is compulsory for marginal deepwater development, since the environment is less forgiving during production due to the massive cost of well intervention/troubleshooting and production associated issues; flow assurance and facilities turn-down limit, therefore downhole sand control and operation should be robust enough to cater throughout the life of the field.
- Asia (0.46)
- North America > United States > Wyoming > Campbell County (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Malaysiaโs First Real-Time Fiber Optic Logging with High-Fidelity Distributed Acoustic and Temperature Survey Conveyed Via Slickline: A Solution for Uncertain Downhole Integrity Condition
Shahril, Shakri Shaifi (EnQuest Petroleum Production Malaysia Ltd) | Mohd Johan, Mohd Alham (EnQuest Petroleum Production Malaysia Ltd) | Mohd Munir, Dayang Nuriza Z. (EnQuest Petroleum Production Malaysia Ltd) | Mamat, Muhamad Aasif (EnQuest Petroleum Production Malaysia Ltd) | Paul, Benton (EnQuest Petroleum Production Malaysia Ltd) | Ahmad Azhari, Ahmad Hafiz (Neural Oilfield Service Sdn. Bhd) | Zainal Abidin, Nurbaizura (Neural Oilfield Service Sdn. Bhd) | Hashim, Haziq (Neural Oilfield Service Sdn. Bhd) | Mahue, Veronique (Silixa Ltd) | Pouladi, Behzad (Silixa Ltd) | Dawson, Peter (Silixa Ltd)
Abstract One of the challenges for brownfield operators managing over 20 year-old wells is the uncertainties of well integrity impacting the effort to access the remaining oil in place. EnQuest known as the operator of choice for maturing and underdeveloped hydrocarbon assets, sees this challenge as an opportunity to grow by exploring the best approach in the market to meet our objective. This paper presents one of EnQuestโs wells that may have a crossflow interzone between water to the oil bearing reservoir. Well โZโ is a single oil producer completed in 1997 but shut in since 2001 due to a high water cut. This well produces from three zones namely A, B and C. Zone A is expected to produce oil but well test results showed a 100% water cut. Offset well suggest the water bearing is contributed by Zone B. The High-fidelity Distributed Acoustic and Temperature Survey (โDASโ and โDTSโ) was evaluated to determine the possibility of crossflow behind the casing. The unique data solution using a combination of DAS and DTS technology based on engineered fibers, allowed for continuous and wide coverage logging of the well. Real-time data acquisition and displays of the entire wellbore led to a better understanding of the wellโs dynamic and transient behavior and ultimately to a rapid and complete well integrity assessment. The abnormal fluid movement detection during shut-in was achieved through the highly sensitive sensor array, within the low acoustic frequency range, something conventional logging techniques would have missed. This service was deployed via a normal slickline unit with additional hardware required for real-time monitoring. Twelve hours of data were recorded, under a baseline shut in condition, followed by a flowing condition and then a hard shut-in. Real-time data processing and interpretation were performed onsite during logging operations by a service providerโs experts. An unexpected result was discovered with the water contribution identified as coming from Zone B through a leaking Sliding Sleeve Door (โSSDโ) which was in a closed position, as cyclic liquid movements inside the tubing originating from Zone B and past Zone A were detected and tracked from a low frequency DAS signal. Moreover, clear acoustic activity was measured at two gas lift orifice valves during the shut-in condition; these were likely allowing the passage of the reservoir fluids into the annulus. Finally, during flowing condition, all production clearly showed that crossflow originated from Zone B to A, by both DTS and DAS measurements. This explained the water production observed at the surface. Results obtained were well received and immediate was planned action to isolate the water source resulting in 0% water produced afterwards establish movement via slow strain DAS and noise logging analysis.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.47)
A Holistic Approach to Big Data and Data Analytics for Automated Reservoir Surveillance and Analysis
Jordan, Colin Lyle (Fossilytics Engineered Solutions) | Koochak, Roozbeh (Fossilytics Engineered Solutions) | Roberts, Martin (Fossilytics Engineered Solutions) | Nalonnil, Ajay (Fossilytics Engineered Solutions) | Honeychurch, Mike (Fossilytics Engineered Solutions)
Abstract Analyses have been widely applied in production forecasting of oil/gas production in both conventional and unconventional reservoirs. In order to forecast production, traditional regression and machine learning approaches have been applied to various reservoir analysis methods. Nevertheless, these methods are still suboptimal in detecting similar production trends in different wells due to data artifacts (noise, data scatter, outliers) that obscure the reservoir signal and leading to large forecast error, or fail due to lack of data access (inadequate SCADA systems, missing or abhorrent data, and much more). Furthermore, without proper and complete integration into a data system, discipline silos still exist reducing the efficiency of automation. This paper describes a recent field trial conducted in Australia's Cooper Basin with the objective to develop a completely automated end-to-end system in which data are captured directly from the field/SCADA system, automatically imported/processed, and finally analyzed entirely in automated system using modern computing languages, modern devices incl. IoT, as well as advanced data science and machine learning methods. This was a multidisciplinary undertaking requiring expertise from petroleum, computing/programming, and data science disciplines. The back-end layer was developed using Wolfram's computation engine, run from an independent server in Australia, while the front-end graphical user interface (GUI) was developed using a combination of Wolfram Language, Java, and JavaScript โ all later switched to a Python-React combination after extensive testing. The system was designed to simultaneously capture data real-time from SCADA Historians, IIoT devices, and remote databases for automatic processing and analysis through API's. Automatic processing included "Smart Filtering" using apparent Productivity Index and similar methods. Automated analysis, including scenario analysis, was performed using customized M/L and statistical methods which are then applied to Decline curve analysis (DCA), flowing material balance analysis (FMB), and Water-Oil-Ratio (WOR). The entire procedure is automated, without need for any human intervention.
- Oceania > Australia > South Australia (0.34)
- Oceania > Australia > Queensland (0.34)
- North America > United States > Texas (0.28)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Facilities Design, Construction and Operation > Measurement and Control > SCADA (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Drilling Performance and Risk Management Optimisation in Offshore Australia: Improving Overall Safety and Efficiency of Well Construction Process
Kirthi Singam, Chandrasekhar (Schlumberger) | Hafezi, Farshid (Schlumberger) | Rebello, Clyde (Schlumberger) | Bartul, Miroslav (Schlumberger) | Ali, Anis (Schlumberger) | Naveed, Muhammad (Schlumberger)
Abstract The emergence of Real-Time Well Construction Performance Monitoring Centers has significantly improved the service delivery for Operators across numerous offshore oil fields in Australia. New technologies and workflows were implemented for 3 Australian offshore wells, with the primary objective being to improve drilling efficiency while managing the associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the Operator and highlighting areas of possible improvements. The workflows combined proven technologies, software and wellbore surveillance services, which delivered risk-free wells ahead of Authority for Expenditure (AFE), by targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management. The workflow began with a preliminary field analysis to identify the main challenges and areas that needed improvement. The key learnings were then consolidated on a comprehensive drilling road map by well section that outlined prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also identified performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the Execution Stage were developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration and connection time. The workflows enabled the flawless execution of 3 offshore wells 29.0 days ahead of AFE which saved the Operator USD 15.5M. The closed loop monitoring enabled real time interventions which aided in preventing risks such as stuck pipe, ensured efficient shoe-to-shoe drilling and avoided potential lost-in-hole (LIH) costs. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow was using existing and cost-effective technologies while capitalizing on the renewed synergy between different departments such as Drilling, Mudlogging and Well Operations analysis. The workflow was and can be customized based on different needs, by combining specific modules for monitoring, analysis and wellbore surveillance services, to increase the efficiency of any well construction.