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In the last quarter of 2019, the world experienced a dramatic change in the way daily activities happen: A completely new and unknown virus (COVID-19) appeared, forcing many nations and societies to implement several restrictions in an effort to minimize contagion and deaths. In this article, some SPE African sections share their experience on how to conduct activities during the global pandemic, so other SPE sections can implement similar events to benefit their members. "[The lockdown] has strongly affected membership drive, sponsorship of events, and most importantly the conviviality that we used to have during most SPE in person events. We should know and agree that there is a paradigm change in the way we do things. Most guidelines and by-laws must be reviewed along COVID-19 protocols. Also, [we need to] ensure there is an updated methodology of reaching out to members and sponsors. We should be careful of too many virtual events/programs to avoid stress-related issues to our members. I also think we should start trying out hybrid events."
The onset of erosion of coiled tubing (CT) strings may be difficult to predict in annular fracturing operations. The complete paper describes a methodology of verifying that CT strings have not been subject to erosion caused by annular fracturing operations. An exploration of pumping rates used on these strings in operations also provides field-tested practical guidelines for avoiding erosion when performing annular fracturing jobs. A CT string may be exposed to erosion in the outer surface during CT annular fracturing operations. The critical parameters that may influence the magnitude of erosion include fracturing pump rate, sand concentration, fluid rheology, wellbore geometry, and the grade of CT string.
Abstract Short radius wells typically incorporate build rates between 35deg per 100ft and 70deg per 100ft. These wells are typically drilled to minimize exposure of a problematic zone above the target or to reduce geological uncertainty. This paper will discuss best practices and equipment developed specifically for delivering these wells in the Middle East. Case histories will illustrate the close collaboration with the operator resulting in performance step change for short radius drilling. The approach is based on a rigorous Drilling Engineering process. Such process is divided in four major steps; design, execute, evaluate and optimize. One of the first key steps is to perform a diligent risk assessment ensuring the customer objectives are achieved. This resulted in the development and implementation of technological innovations on downhole motors and Measurements While Drilling (MWD) tools to achieve the required high build rates safely and consistently. Proper communication was crucial for flawless execution, and meticulous documentation enabled proper evaluation and optimization of the art of short radius drilling. For over 10 years, multiple short radius wells have been consistently delivered meeting their objectives; from successful sidetracking operations, accurate curve landing, optimum geo-steering, valuable Logging While Drilling (LWD) data collection, to extending the life of the wells by maximizing their production. The last two steps of the Drilling Engineering cycle (evaluate and optimize) have been the foundation of the continuous improvement process; targeting adequate equipment maintenance, Bottom Hole Assembly (BHA) design and operational practices to ensure consistent results. The paper will recap the drilling engineering cycle for wells drilled recently. The discussed best practices have enabled master the art of short radius drilling. Such distinctive knowledge should be shared with the entire oil and gas industry. The paper captures the engineering approach to tackle the traditional challenges of drilling short radius wells. It also discusses the reliable solution for drilling short radius wells in Middle East which are planned to access new reserves from an existing infrastructure, while minimizing drilling and geological risks.
Nzoutchoua, Degaul Nana (Schlumberger) | Johnson, Carl R. (Schlumberger) | Mounguele, Armelle Boukoulou (Schlumberger) | Onyia, Chibuzor (Eni) | Rizza, Giovanni (Eni) | Sinibaldi, Giuliano (Eni) | Gravante, Elpidio (Eni)
Abstract A 1575m [4922-ft] offshore horizontal 4-½-in. liner cemented using a mud-sealing cement system (MSCS) resulted in an outstanding cement bond log result. The decision to use the MSCS was taken after realizing that four offset liners, previously cemented using conventional cement systems, did not yield acceptable cement bond log results despite following oil and gas cementing industry best practices, including pipe rotation. This paper documents a comparison of six offset horizontal liners, focusing on the impact of the MSCS technology. The paper focuses on several 4-½-in. liners in the same field. The wells were drilled by a similar rig and had similar well profiles. The drilling bit, directional drilling tool, drilling fluids system, logging tool, centralizer type and pumping sequences were comparable across all wells. In addition, the logging company performing the cement bond log evaluation was not the same company performing the cementing service. After the first MSCS-cemented well, the subsequent well used a conventional cement system to isolate the 4-½-in. liner and tighten the cementing best practices. This was initiated to irrefutably confirm the impact of MSCS technology on the quality of cement bond log recorded on the earlier well. The cement bond log recorded from the well isolated with MSCS is easily identified among the six comparison wells even though the cementing operation faced several well challenges, includinga single dart liner system implementation (for all liners), which can promote the intermixing of slurry with fluid ahead while travelling down the pipe mud losses in the drilling phase, which resulted in a reduction of the displacement rate to control ECD during cement placement. The bond log results of the other wells were qualified as poor or fair, even though significant precautions were taken to optimize zonal isolation. These efforts included batch mixing the spacer and slurry, using more than one centralizer per casing joint, and implementing pipe rotation during pre-job circulation and job execution when the torque limit allowed. This multi-well comparison based on field results brings solid evidence of the MSCS technology interacting with the residual layer of nonaqueous fluid (NAF) when well conditions reach or exceed the practical normative limitations for mud removal. This in-situ interaction generates a viscous paste that positively impacts the bond log response and bolsters the isolation between zones of interest. The result has yielded a step forward in the provision of a dedicated barrier technology for horizontal or highly deviated sections.
Antillon Moreira, Rodrigo (ADNOC Offshore) | Jeughale, Ramanujan (ADNOC Offshore) | Takahiro, Toki (ADNOC Offshore) | Motohiro, Toma (ADNOC Offshore) | Andrews, Kerron (ADNOC Offshore) | Fujinaga, Ryota (ADNOC Offshore) | Al Ali, Salim Abdalla (ADNOC Offshore) | Alzaabi, Mohamed Abdulrahman (ADNOC Offshore)
Abstract Reservoir sections in MRC (Maximum Reservoir Contact) & ERD (Extended Reach Drilling) wells are mainly designed to drill 8 ½" hole, because of drilling limitations with smaller hole size. However, slim hole sizes offer opportunities to revitalize existing wells using re-entry drilling techniques in association with MRC and ERD designs. This paper discusses the best practices to be implemented in order to mitigate risk, reduce complexity and ensure improved drilling performance. Re-Entry wells in the field have a risk of well integrity issues such as corroded 9 5/8" casing. In order to mitigate this risk, the corroded 9 5/8" casing should be covered by 7" liner & tied-back to surface before drilling reservoir section. In this situation up to 18,000 ft of 4" DP is used in the wells to drill 6" hole and run 4 ½" lower completion. Offset well analysis, whip stock selection criteria, BHA design, drilling fluid selection, drilling and tripping practices based on torque & drag and hydraulics calculations are most important to achieve the well objective. The Slim hole MRC well was completed without any issues and achieved good drilling performance. It was observed that the actual drilling parameters such as torque, drag and stand pipe pressure were less than simulated parameters. NAF was selected in the section to reduce the friction factor, while motorized RSS and a reamer stabilizer were used in the BHA to reduce torque, drag and ensure a smooth well profile. A back reaming practice was implemented in hole section to reduce dog leg severity and the open hole was eventually displaced to viscosified brine to minimize the friction factor for running the 4 ½' lower completion. 8500 ft of 6" hole section was drilled and TD was reached at +/- 19,000ft within 50 days including recovering the existing completion, drilling 8 ½" & 6" hole and running completion. This paper aims to contribute to the oilfield industry by sharing the successfully implemented engineering design and operation execution methodology to overcome the complexities present in Re Entry Wells MRC/ERD wells required to be drilled with slim hole conditions under an optimal cost, time effectiveness and low risk.
Equality, openness, and belonging are core indicators of the inclusion matrix. Companies face numerous challenges in creating work environments that are diverse, open, and free from bias. As workplaces have become increasingly remote after the COVID-19 pandemic, this challenge has only aggravated. Inclusion matters, as it not only helps in viewing business problems from unique perspectives but also provides a platform to the voices that otherwise may go unheard. The case for inclusion is also supported by compelling research that reveals inclusive teams make better decisions 87% of the time and drive decision making two times faster with half the meetings.
Rosli, Azlesham (PETRONAS Carigali Sdn Bhd) | Mak, Whye Jin (PETRONAS Carigali Sdn Bhd) | Richard, Bobbywadi (PETRONAS Carigali Sdn Bhd) | Meor Hashim, Meor M (PETRONAS Carigali Sdn Bhd) | Arriffin, M Faris (PETRONAS Carigali Sdn Bhd) | Mohamad, Azlan (PETRONAS Carigali Sdn Bhd)
Abstract The execution phase of the wells technical assurance process is a critical procedure where the drilling operation commences and the well planning program is implemented. During drilling operations, the real-time drilling data are streamed to a real-time centre where it is constantly monitored by a dedicated team of monitoring specialists. If any potential issues or possible opportunities arise, the team will communicate with the operation team on rig for an intervention. This workflow is further enhanced by digital initiatives via big data analytics implementation in PETRONAS. The Digital Standing Instruction to Driller (Digital SID) is a drilling operational procedures documentation tool meant to improve the current process by digitalizing information exchange between office and rig site. Boasting multi-operation usage, it is made fit to context and despite its automated generation, this tool allows flexibility for the operation team to customize the content and more importantly, monitor the execution in real-time. Another tool used in the real-time monitoring platform is the dynamic monitoring drilling system where it allows real-time drilling data to be more intuitive and gives the benefit of foresight. The dynamic nature of the system means that it will update existing roadmaps with extensive real-time data as they come in, hence improving its accuracy as we drill further. Furthermore, an automated drilling key performance indicator (KPI) and performance benchmarking system measures drilling performance to uncover areas of improvement. This will serve as the benchmark for further optimization. On top of that, an artificial intelligence (AI) driven Wells Augmented Stuck Pipe Indicator (WASP) is deployed in the real-time monitoring platform to improve the capability of monitoring specialists to identify stuck pipe symptoms way earlier before the occurrence of the incident. This proactive approach is an improvement to the current process workflow which is less timely and possibly missing the intervention opportunity. These four tools are integrated seamlessly with the real-time monitoring platform hence improving the project management efficiency during the execution phase. The tools are envisioned to offer an agile and efficient process workflow by integrating and tapering down multiple applications in different environments into a single web-based platform which enables better collaboration and faster decision making.
Abstract Because of recent advancements in the field of natural language processing (NLP) and machine learning, there is potential to ingest decades of field history and heterogeneous production records. This paper proposes an analytics workflow that leverages artificial intelligence to process thousands of historical workover reports (handwritten and electronic), extract important information, learn patterns in production activity, and train machines to quantify workover impact and derive best practices for field operations. Natural language processing libraries were developed to ingest and catalog gigabytes of field data, identify rich sources of workover information, and extract workover and cost information from unstructured reports. A machine learning (ML) model was developed and trained to predict well intervention categories based on free text describing workovers found in reports. This ML model learnt pattern and context of repeating words pertaining to a workover type (e.g. Artificial Lift, Well Integrity, etc.) and to classify reports accordingly. Statistical models were built to determine return on investment from workovers and rank them based on production improvement and payout time. Today, 80% of an oilfield expert's time can be spent manually organizing data. When processing decades of historical oilfield production data spread across both structured (production timeseries) and unstructured records (e.g., workover reports), experts often face two major challenges: 1) How to rapidly analyze field data with thousands of historical records. 2) How to use the rich historical information to generate effective insights to optimize production. In this paper, we analyzed multiple field datasets in a heterogeneous file environment with 20 different file formats (PDF, Excel, and other formats), 2,000+ files and production history spanning 50+ years across and 2000+ producing wells. Libraries were developed to extract workover files from complex folder hierarchies through an intelligent automated search. Information from reports was extracted through Python libraries and optical character recognition technology to build master data source with production history, workover, and cost information. A neural network model was trained to predict workover class for each report with >85% accuracy. The rich dataset was then used to analyze episodic workover activity by well and compute key performance indicators (KPIs) to identify well candidates for production enhancement. The building blocks included quantifying production upside and calculating return of investment for various workover classes. O&G companies have vast volumes of unstructured data and use less than 1% of it to uncover meaningful insights about field operations. Our workflow describes methodology to ingest both structured and unstructured documents, capture knowledge, quantify production upside, understand capital spending, and learn best practices in workover operations through an automated process. This process helps optimize forward operating expense (OPEX) plan with focus on cost reduction and shortens turnaround time for decision making.
HSE--or health, safety, and environment--is commonly used as shorthand for HSSES (health, safety, environment, security, and social economics) and is also known as SHE or EHS. An alternative term for it is occupational safety and health (OSH). Some organizations include security and social economics under the HSE umbrella. Titling it HSSES becomes cumbersome, so the abbreviation HSE is typically used include safety and security. Safety, health, environmental, security, and social economics are separate disciplines, each with its own technology; however, these disciplines are often combined in the same functional groups within exploration and production (E&P) organizations.
Methane emissions should be a priority for the oil and gas industry, but incentives are necessary for that to happen, according to a panel of experts discussing the issue. The panel discussion, presented by the Society of Petroleum Engineers (SPE) as part of its Gaia Talks series, was held live on LinkedIn. The panel--consisting of Darcy Spady, chief executive for Carbon Connect and 2018 SPE president; Tim Gould, head of division for Energy Supply Outlooks and Investment for the International Energy Agency (IEA); Wendy Brown, environmental director for the International Association of Oil and Gas Producers; and Julien Perez, vice president of strategy and policy for the Oil and Gas Climate Initiative, and moderated by Trey Shaffer, senior partner at Environmental Resources Management--laid out why methane emissions should be a priority and how to make that happen. Raising awareness and creating incentives to reduce emissions will be key to bringing about the necessary change, the panel agreed. The amount of methane emitted by the industry overall may not be the largest hurdle.