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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
Dooply, Mohammed (Schlumberger) | Schupbach, Michael (Murphy Exploration & Production Co) | Hampshire, Kenneth (Murphy Exploration & Production Co) | Contreras, Jose (Schlumberger) | Flamant, Nicolas (Schlumberger)
Summary Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum job results of a primary cementing job, measuring annular return rates and comparing them with simulated data in real time will provide a better understanding of job signatures and result in the best possible top of cement (TOC) estimation prior to running any cement evaluation log or making a decision to continue drilling the next section of the well. The return rate job signature along with the wellhead pressure is essential to understanding the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical. Historically, the cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flowmeter installed on the annulus return line, and a simple verification of mud tanks volume vs. pumped volume, as reported by drillers or mud loggers, more often than not results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in and flow rate out). In this paper, we will review a solution developed to mitigate the lack of a direct flow-rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.
Lafond, Aurore (Schlumberger) | Ringer, Maurice (Schlumberger) | Le Blay, Florian (Schlumberger) | Liu, Jiaxu (Schlumberger) | Millan, Ekaterina (Schlumberger) | Ba, Samba (Schlumberger) | Chao, Mu (Schlumberger)
Abstract Abnormal surface pressure is typically the first indicator of a number of problematic events, including kicks, losses, washouts and stuck pipe. These events account for 60–70% of all drilling-related nonproductive time, so their early and accurate detection has the potential to save the industry billions of dollars. Detecting these events today requires an expert user watching multiple curves, which can be costly, and subject to human errors. The solution presented in this paper is aiming at augmenting traditional models with new machine learning techniques, which enable to detect these events automatically and help the monitoring of the drilling well. Today’s real-time monitoring systems employ complex physical models to estimate surface standpipe pressure while drilling. These require many inputs and are difficult to calibrate. Machine learning is an alternative method to predict pump pressure, but this alone needs significant labelled training data, which is often lacking in the drilling world. The new system combines these approaches: a machine learning framework is used to enable automated learning while the physical models work to compensate any gaps in the training data. The system uses only standard surface measurements, is fully automated, and is continuously retrained while drilling to ensure the most accurate pressure prediction. In addition, a stochastic (Bayesian) machine learning technique is used, which enables not only a prediction of the pressure, but also the uncertainty and confidence of this prediction. Last, the new system includes a data quality control workflow. It discards periods of low data quality for the pressure anomaly detection and enables to have a smarter real-time events analysis. The new system has been tested on historical wells using a new test and validation framework. The framework runs the system automatically on large volumes of both historical and simulated data, to enable cross-referencing the results with observations. In this paper, we show the results of the automated test framework as well as the capabilities of the new system in two specific case studies, one on land and another offshore. Moreover, large scale statistics enlighten the reliability and the efficiency of this new detection workflow. The new system builds on the trend in our industry to better capture and utilize digital data for optimizing drilling.
Coiled-tubing drilling (CTD) can be very effective in certain situations. Its application is growing as experience defines what it takes to be successful. Coiled-tubing drilling (CTD) has a rather extensive history and received a large amount of press and hype from the 1990s to date, a significant amount being less than positive. There have been numerous highly successful applications of CTD technology in such regions as Alaska and the United Arab Emirates, yet CTD is still considered an immature new technology. One example of exaggerated expectations is CTD's reputation for offering certain advantages, including small footprint, high mobility, and quick operations. However, when more complex CTD services are planned, including directional drilling and cased completions, these advantages may no longer apply. These materials are typically not required for conventional CT services. When including the additional separators and nitrogen-pumping equipment required for underbalanced drilling (UBD), the advantages related to small footprint and high mobility may no longer be the case. Numerous truckloads of equipment can take days to rig up in preparation to drill with CT. Figure 1 shows a purpose-built CTD rig working in Oman.
The understanding of decision-making processes is critical in ensuring project success and safety. Project failures--and disasters--can result from the lack of understanding or implementation of sound principles. Various decision-making processes have been presented previously in this column. In this discussion, I reviewed two books related to group decision making, Disastrous Decisions by Andrew Hopkins and Managing the Unexpected by Karl Weick and Kathleen Sutcliffe. Hopkins presents a compelling analysis of why the Macondo blowout in the Gulf of Mexico in 2010 happened.
Teo, Choon Hoong (Sarawak Shell Berhad) | Bakri, Faiz (Sarawak Shell Berhad) | Koh, Qianhui (Sarawak Shell Berhad) | Mat Jusoh, Muhammad Faizol (Sarawak Shell Berhad) | Bin Alias, Saiful Hisham (Archer Well Company) | Othman, Azmi (Archer Well Company) | Idris, Syahiran (Halliburton Energy Services) | Thien, Ronny (Halliburton Energy Services)
Abstract Following the successful proof of concept of the closed system dual casing perforate, wash and cement for environmental plug application in 2018 (SPE-193989-MS), the same system was optimized for 2 subsea wells to isolate a gas sand behind 2 casings (9-5/8" × 13-3/8" × 16" open hole). Learning from recent operations, it was discovered that there is significant improvement achievable with specialized gun system, and refined washing and cementing parameters. Such improvement was critical to the success of the annular remediation and thus, the long-term isolation of the gas sand. The first successful closed system dual casing perforate, wash and cement for annular isolation is discussed and evaluated in this paper.
Ruiz, Fernando (ADNOC Onshore) | Al Hadidy, Khaled (ADNOC Onshore) | El Yossef, Bassem (ADNOC HQ) | Hebish, Ayman (ADNOC Onshore) | Negoi, Adrian (ADNOC Onshore) | Hamdy, Ibrahim (ADNOC Onshore) | Al Shamisi, Eisa (ADNOC Onshore) | Al Samahi, Musabbeh (ADNOC Onshore) | Kumar, Rakesh (ADNOC Onshore) | Mizukami, Akio (ADNOC Onshore) | Mandal, Vivekananda (ADNOC Onshore) | Ibrahim, Ahmed (ADNOC Onshore) | Wakka, Turky (ADNOC Onshore) | Al Soliman, Abdulkareem (ADNOC Onshore) | Nunez, Ygnacio (ADNOC Onshore) | Amorocho, Alexander (ADNOC Onshore) | Al Hendi, Mohamed (ADNOC Onshore) | Al Mutawa, Ahmed (ADNOC Onshore)
The proposal of this paper is to share the knowledge learned in this new procedure and techniques implemented in HP/HT Unconventional wells, created by the Unconventional (UC) Drilling Department at Abu Dhabi which involve around ten different services, where each has a high importance and contribution for the collective success of the well at the moment to frac and hence the feasibility of the project.
In order to assure the integrity and accessibility of the Frac String during Plug and Perf hydraulic fracturing operations of one of the toughest rock in Unconventional business worldwide, one procedure has been developed for running operations best practices. Pressure testing the Frac String (FS) during running in hole in stages while in vertical section to sure safe and successful Wireline setting and retrieving nipples plug with more than 30% solids in the system (high mud weight) to guarantee no leak in the string prior reaching total depth (TD). Hanging and testing cross over (XO), assuring compatibility with the wellhead connections. Cementing up to18.7 ppg. Flexible and expandable slurries, cement inside previous casing and apply pressure on surface to avoid gas percolation during the cement setting period. Cleaning out with Coiled tubing (CT) to ensure no obstruction and using different completion fluids for future accessibility. And finally, Pressure testing the Frac string up to 14ksi all are new practices and proven mitigation measures for all assessed risks for hydraulic fracturing operations.
This paper is about sharing this new procedure in Abu Dhabi for having a cemented FS in UC wells High Pressure / High Temperature (HP/HT) with 100% integrity and internal accessibility to run plugs, perforations, logs and be able to apply high surface pressure to frac the tight reservoir in the planned zone, creating the desired permeability for future production.
In this paper, we introduce pumpdown diagnostics, an economical process in which cement sheath integrity, perforation cluster spacing, and fracturing (frac) plug integrity can be assessed for every fracturing stage, potentially leading to improvements in stimulation, completion, cementing, and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pumpdown and perforating operation and correlating the results among multiple fracturing stages and wells in a field or play. A special requirement is that the ball check is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited hydrochloric (HCl) acid coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity.
Reviews of pumpdown diagnostics field cases from several unconventional plays provide the following insights. Pumpdown diagnostics are time efficient and economical, requiring approximately 15 minutes per fracturing stage. Evaluating communication to the previous fracturing stage can serve as a key performance indicator for treatment control or cement sheath integrity. Pumpdown diagnostic results can be more reliable than cement bond log evaluation, and stage isolation characteristics can be strongly affected by cluster spacing.
The Influx Management Envelope (IME) is a tool for operational decision making when managing influxes in Managed Pressure Drilling (MPD) operations. There have been numerous developments to the IME in recent years, and it is gaining traction over the MPD Operating Matrix (MOM). Calculation of the IME can be done in different ways. The original approach of calculating an IME described in (
Dooply, Mohammed (Schlumberger) | Schupbach, Michael (Murphy Exploration & Production Co.) | Hampshire, Kenneth (Murphy Exploration & Production Co.) | Contreras, Jose (Schlumberger) | Flamant, Nicolas (Schlumberger)
Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well.
The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical.
Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out).
This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.