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Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Gas lift is one of the most popular ways to increase oil-well production, and it is no secret that it is an underperformer. Back in 2014, ExxonMobil reported that by creating a team of roving gas-lift experts it was able to add an average of 22% more output on several hundred wells where the gas injection had been optimized. Gains were expected because "wells do not remain the same over time; they change," said Rodney Bane, global artificial-lift manager at ExxonMobil, in this JPT story covering the 2014 SPE Artificial Lift Conference and Exhibition. The problem with gas injection is that change is hard. Injection adjustment or repairs require either pulling the tubing to reach the injection mandrels or a wireline run. Those with good-producing wells, particularly offshore, need to weigh the possible gain against the cost and lost production during the job. Those managing more and more wells live with iffy data, injection systems prone to malfunction, horizontal wells prone to irregular flows, and a time-consuming process for calculating the proper injection rates. New approaches addressing those negatives have led a few big operators to try new systems designed to allow constant adjustments based on downhole data with electric control systems designed to be more reliable.
Javaheri, Mohammad (Chevron) | Tran, Minh (University of Southern California) | Buell, Richard Scot (Chevron) | Gorham, Timothy Lee (Chevron) | Sims, Jack (Chevron) | Rivas, Stephen (Chevron) | Munoz, Juan David (Chevron)
Abstract Horizontal steam injectors can improve the efficiency of thermal operations relative to vertical injectors. However, effective in-well and reservoir surveillance is needed to understand steam conformance. Uniform steam chest development improves steam-oil-ratio (SOR) in continuous steam injection and accelerates recovery in cyclic steam injection. Conformance of the injected steam can be achieved by flow control devices (FCD) deployed on either tubing or liner. A new liner-deployed FCD was used in a horizontal steam injector in the Kern River field. The liner-deployed FCD is intended to replace the tubing-deployed FCDs while reducing capital costs, surveillance costs, and well intervention costs for conformance control. Fiber optics was used for surveillance, which is the most promising method in horizontal steam injectors considering reliability, accuracy, and cost. Fiber optic data enables monitoring the performance of liner-deployed FCDs as well as estimating the flow profile along the lateral length. Multi-mode Distributed Temperature Sensing (DTS) optical fibers and single-mode Distributed Acoustic Sensing (DAS) optical fibers were installed in the well for these objectives. Algorithms for interpreting DTS were improved to include a new technique, Shape Language Modeling (SLM), and a probabilistic approach. The configuration of the FCDs was changed during a well intervention, and it was monitored by DTS and DAS. Data from both DTS and DAS confirms the open/closed position of the sliding sleeve of FCDs initially and after the intervention. The probabilistic estimates of steam outflow in several FCD configurations match well with the theoretical outflow that is expected from the critical flow of steam through chokes installed in the FCDs.
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 This paper describes how business analytics novel software tools combined with advanced data management techniques can be integrated to management workflows and decision-making processes of a Coiled Tubing Service Company (CTSC). An advanced data wrangling process (transforming and mapping data) was designed and implemented to unify current and historical coiled tubing operational data into a single data set. The latter was regularly updated with the latest operational information through an automated data querying process that eliminated the need for manually repeating the data wrangling. A Business Analytics Software (BAS) was used to accelerate the engineering of a Data Analytics (DA) process, identify correlations and trends, design data models, and create relevant Key Performance Indicators (KPI). Finally, BAS visualization tools were used to prepare and publish comprehensive cloud-based Business Intelligence (BI) dashboards and reports. The BI dashboard allows the coiled tubing company to quickly perform accurate and efficient analysis of the KPI trends of its coiled tubing units and well interventions. The cloud-based Dashboard enables the CTSC to: Effectively identify Coiled Tubing Strings utilization, costs, failures, vendors, and design performance trends based on factual data, thus enabling informed pipe management decisions. Clearly Identify high performance coiled tubing units and crews and make strategic decisions for high profile jobs. Identify equipment failures, non-productive time (NPT) trends and define, implement, and monitor maintenance and asset management strategies to tackle the failures with mayor impact on operations performance. Easily incorporate fresh operational data and detect record-breaking operations. Improve Customer Relationship Management by a quickly responding to customer inquiries for tailor-made operations performance reports. Decrease workload on repetitive processes by enabling reports generation with relevant and accurate data faster that previous methods in place. Quickly customize and create accurate documentation compiling relevant performance data in a consistent and standardized fashion. Perform well interventions technical analysis. The contemporary approach to integrate BI Software to coiled tubing operations is a step change in how service companies and operators are analyzing and monitoring performance (efficiency, safety, and quality) to differentiate from each other, optimize results and minimize costs. This paper describes an example of a simple yet sophisticated and effective way of incorporating digital tools in the oilfield services processes by utilizing in house talent and resources.
Abstract Cleanouts and milling make up most of the common coiled tubing (CT) operations around the globe. The objective of each is to remove debris from a wellbore, such as sand, scale, cement, or fracture plugs, to promote an unobstructed flow path for fluids. For decades, operators and service companies have focused heavily on methods to optimize removal of debris through the development of specialized tools, fluids, techniques, and predictive models. These are coupled with wellsite equipment digital acquisition systems to capture CT behavior, pump rates, and chemical additive rates; very little attention has been given to the rates of the fluid and solids being returned to surface. The composition and quality of fluids being pumped into the well are often well characterized, and the pump rate is recorded digitally to the second. By contrast, information on the fluid being returned is frequently limited to intermittent, manual surveys of the flowback tank fluid level that often go unrecorded. Fluid samples are rarely analyzed, even by inexact measurements, to provide feedback to the predictive model. This results in a missed opportunity to optimize the operation as well as to recognize and respond to undesirable trends and actions in real time. This paper describes a simple digital acquisition system developed and implemented in the field to digitally record, plot, and monitor critical wellsite parameters including flowback rate, solids returns, annular velocities, and downhole Reynolds numbers. The system provides a real-time visual aid to observe the direct impact that operational decisions have on cleanout efficiency and the opportunity to correct and optimize the cleanout operation. Furthermore, the system offers the opportunity to rapidly recognize and respond to unexpected trends such as a gradual or sudden loss in return rate or a decrease of solids returns which could rapidly result in serious consequences such as a stuck-pipe situation.
Pytko, Mykhailo (UkrGasVydobuvannya) | Kuchkovskyi, Pavlo (UkrGasVydobuvannya) | Abdellaitif, Ibrahim (UkrGasVydobuvannya) | Franco Delgado, Ernesto (Schlumberger) | Vyslobitsky, Andriy (Schlumberger) | Balabatyr, Yerik (Schlumberger) | Rachid Haro, Raul German (Schlumberger) | Ahmim, Nacer Ridha (Schlumberger) | Garcia Cardona, Walther (Schlumberger)
Abstract This paper describes three coiled tubing (CT) applications in depleted reservoir wells, where full circulation and precise fluid placement were achievable only by using a novel solids-free loss-control system, such as abrasive perforating applications. It also describes the preparation work, such as laboratory results and mixing procedure performed to ensure successful implementation. The analysis of Ukrainian reservoir conditions by local and global engineering teams showed that in a highly depleted well, abrasive jetting through CT was the best option to efficiently perforate the wellbore. However, this approach could lead to later impairment of the gas production if the abrasive material (sand) could not be entirely recovered. Such a risk was even higher as wells were depleted and significant losses to the formation occurred. The use of solids-free fluid-loss material that was easy to mix, pump, and remove after the operation, was, therefore, critical to the success of that approach. In Ukraine, most of the brownfields have a reservoir pressure that varies between 50% and 20% of the original reservoir pressure. This is a challenge for CT operations in general and especially for abrasive jetting, which requires full circulation to remove solids. It also complicates intervention when precise fluid placement control is required, such as spotting cement to avoid its being lost into the formation. The perforation solids-free loss-control system is a highly crosslinked Hydroxy-Ethyl Cellulose (HEC) system designed for use after perforating when high-loss situations require a low-viscosity, nondamaging, bridging agent as is normally required in sand control applications. It is supplied as gel particles that are readily dispersed in most completion brines. The particles form a low-permeability filter cake that is pliable, conforms to the formation surface, and limits fluid loss. The system produces low friction pressures, which enable its placement using CT. Introduction of that system in Ukraine allowed the full circulation of sand or cuttings to surface without inducing significant damage to the formation for first time; it was also used for balanced cement plug placements. This project was the first application of the solids-free loss-control system in combination with CT operations. It previously was used only for loss control material during the well completion phase in sand formations with the use of drilling rigs.
Hadi Keong, Azwan (Schlumberger) | Campos, Jesus (Schlumberger) | Casali, Andrei (Schlumberger) | Hansen, Anders (Schlumberger) | Vingen, Sindre (Schlumberger) | Segura, Jordi (Schlumberger) | Hofacker, Mark (Schlumberger) | Brueren, Ted (Equinor) | Fossdal, Inge (Equinor)
Abstract On the Norwegian continental shelf (NCS), coiled tubing (CT) cleanout requires small bites and frequent wiper trips to the surface due to potential sand bedding in a large and deviated completion. A real-time CT downhole measurement system is used to optimize the operation, following a dynamic workflow. Conventionally, the system is powered by downhole lithium battery, which limits CT downhole operating time. A continuous surface-powered system was needed to promote further optimization for such operation. A new hybrid electro-optical cable was introduced to enable continuous power supply from surface to the real-time downhole tool sensors. The system consists of a surface power module that sends power through a layer of low-DC-resistance conductors and optical fibers that enable data telemetry. Conventionally, only three to four trips can be completed before replacement of the downhole battery is required. Battery replacement can take up to 8 hours due to the complexity of that offshore environment. With the continuous power supply, the CT cleanout operation can continue for days without interruption of data from the downhole tool sensors. A three-well CT cleanout campaign in the NCS demonstrated the benefits of this new real-time downhole measurement system by using accurate downhole weight and torque readings to control the penetration through scale and avoid motor stalls. Sections of scale bridges were identified during the cleanout by monitoring fluctuations of downhole torque of the mill. The monitoring allows CT operators to control penetration rate and bite length during the cleanout. When the milled debris are swept, downhole weight is used to detect early signs of solids plugging around the mill. Downhole pressures complement surveillance of the sweeping of solids to the surface by giving a qualitative measurement of solids loading through conversion of the real-time bottomhole pressure reading into equivalent circulating density with changing CT depth. The process of optimizing bite length and sweeping speed is repeated without interruption thanks to continuous power supply from the surface, eventually leading to time reduction. In one of the wells, downhole tools uninterruptedly acquired data for 10 days straight. The CT managed to clean out a total of 40 908 kg of a mixture of scale and sand, with an estimated average time reduction of 25% when compared to CT cleanout without real-time downhole data. Delivery of continuous high-voltage power to downhole tools not only enables reduction in operating time, it also paves the way for extending the capabilities of CT interventions by enabling the operation of more electrically activated application tools. It allows combining multiple work scopes in a single CT run, which reduces operating cost and provides greater operational flexibility. Finally, eliminating the dependency on lithium batteries reduces the carbon footprint for a more sustainable operation.
Abstract Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough, but are considerably exaggerated in the openhole condition. A coiled tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling and early lockup. The challenge to effectively log these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed including a 2.4" bypass section. Although hydraulically powered coiled tubing tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands to pull the CT to target depth. The tractor is 100% hydraulically powered, with no electrical power allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore, and is operated by a pre-set pump rate from surface. Developed to improve the low coverage in open hole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and ran in hole. Once the coil tubing locked up, the tractor was activated and pulled the coil to cover over 90% of the open hole section delivering a pulling force of up to 3,200 lb. Real-time production logging was conducted simultaneously with the tractor activated, flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor is the world's slimmest most compact, and the first of its kind CT tractor that enables production logging operations in horizontal extended reach open hole wells. The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling extended reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must continually be developed to push the boundaries further.