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Claib Meinhardt, Amin Adolfo (Sensia) | Guan, Hua (One Subsea) | Lopez Cisneros, Luis Fernando (Petroleos Mexicanos PEMEX) | Perez De La Cruz, Marco Antonio (Schlumberger) | Lorenzana, Alberto (Schlumberger) | Guerra Carvallo, Claver Hugo (MI Swaco) | Ruiz Roque, Sergio Ivan (Schlumberger) | Ramirez Olarte, Hector Eric (Sensia) | Balderas Perez, Harvey David (Schlumberger)
Oil quality management is an ongoing challenge, and there are costly financial implications when the product quality falls below the required specifications for trading. Furthermore, it has been reported that upsets in the dehydration and desalting (D&D) process leading to off-specification oil quality are commonly experienced following well interventions (stimulations and cleanouts), particularly when dealing with heavy oil.
Detailed research of problems at one D&D facility was conducted, starting with the analysis of existing field data (mainly from well stimulation and cleanout jobs) and recommending and processing laboratory tests to identify the root causes. A chemical mitigation strategy was developed with the implementation of key performance indicators (KPI) and workflows in a production operations software platform, which includes a surveillance and smart alert system that displays KPIs on dashboards for chemical management, mapping for forecasting scenarios of well jobs, time to arrive to the D&D facility, and chemical injection forecasting. The production operations platform is used for input data and generating dashboards including data from SCADA and dynamic multiphase flow simulation online systems to obtain and build the gathering network locations for all jobs and the lapsed time to arrive at the D&D process, making back allocations to gathering stations.
About 30% of stimulation and cleanout jobs have affected the D&D process due to increased volume of suspended solids in the system; these act as natural emulsifiers at the water-oil interface, contributing to emulsion stabilization. When the emulsion is highly stable, the applied chemical treatment becomes ineffective downstream; the D&D process is therefore unable to effectively remove water and salt from oil. The irregularity of the demulsifier injection also adversely affects the efficiency of the process.
The completion of this work provided a clear understanding of the root causes and insights into KPI behavior. The integrated solution enabled real-time monitoring and optimization of the chemical mitigation through better data usage and interpretation using the production operations platform combined with the multiphase flow simulator online system. This enabled the operator to perform timely monitoring and to proactively take actions to reduce the impacts on heavy oil quality.
Scale deposition is one of the most common challenges encountered in oil and gas wells. Mature fields tend to have these issues, but tackling scale removal requires tedious diagnostic and intervention work due to uncertainty in determining the exact location and source of scale.
Production decline was observed in a High-Pressure High Temperature (HPHT) gas producer. Well testing was performed to assess and diagnose the production impairment. The preliminary well test data interpretation highlighted positive skin which needed to be characterized. Scale and even sand were considered as a possible cause of production impairment due to the nature of production chemistry and reservoir type, but the hypothesis lacked physical evidence in the wellbore.
A structured approach was adopted to identify, qualify and rectify the situation. High Pressure Coiled Tubing (HPCT) technology capable of providing real time down hole communication was utilized along with coiled tubing mounted downhole camera (DHC) to determine if the wellbore conditions were contributing towards the production decline resulting in a positive skin. The real time images acquired during the downhole camera run revealed astonishing details of the scale that was causing an impact in the production and the flowing wellhead pressure. The high-resolution images obtained during the well intervention clearly pin-pointed at the root cause of production loss and aided in designing a focused treatment for the challenge at hand. Given the sensitive nature of reservoir and possible interaction between the scale dissolving chemicals and reservoir, a customized treatment was formulated. The treatment design exploited the benefits of scale dissolution while preventing reservoir damage. The treatment was pumped using coiled tubing with a high-pressure jetting and rotating nozzle to ensure 360 degree wellbore coverage.
The well was opened to flow immediately after execution of the treatment. The post treatment flowback results indicated a resounding success with production almost quadrupling. A production log was subsequently performed to understand and gauge reservoir performance. The results of production logging further endorsed the fact that skin damage due to scale had been successfully removed and wellbore skin was reduced.
By minitiaturzing and ruggedizing laboratory equipment historically used for geochemical applications, it is now possible to digitize chemical attributes of molecules as they flow through the wellhead. Specifically, the number of unpaired electrons in outer-orbitals can be tracked in real-time as well as the hyperfine interaction of those electrons with spin-properties of nuclei within their associated molecules. This sounds very esoteric but in fact has a direct relationship with traditional flow assurance problems that have previously been very difficult to manage. For example, considering those electrons which correspond to free radicals within asphaltene molecules, then, in the presence of a very strong magnetic field, they will resonate at a specific microwave frequency. By exposing the well fluid to exactly that combination of magnetic and RF fields, the amplitude of the resonance is proportional to the number of asphaltene molecules. Unlike some optical and infra-red techniques, this gives a measurement of the total amount of asphaltene flowing, not just a measurement of the non-dissolved component. This measurement can be made continuously, so that gives a time-series analysis of the percentage of asphaltene that is flowing in the oil. AI-based software has also been written to extract further information from the resonance data, such as the water-cut and gas-oil ratio. Operators can use this combined information to optimize their flow-assurance strategies, for example, to give immediate feedback on the result of changing an inhibitor or dispersant.
An initial version of the tool was deployed for a field-test in Abu Dhabi in Q4, 2017. Data from the system was transmitted via the cloud to asphaltene experts remotely monitoring the data. The resolution of the device proved better than expected, which allowed the system to give a previously unseen dynamic view of asphaltene chemistry. One surprise was that the asphaltene percentage might vary significantly over the course of a few hours, even when the surface pressure and flow-rates stayed the same. Troublesome wells had the highest standard deviation which gives a new key performance indicator (KPI) for flow assurance risk. Another unexpected result was that surface asphaltene levels would drop for a few days after a xylene soak, before slowly returning back to their baseline. This indicates that a freshly-cleaned tubular is more attractive for asphaltene deposition, and stays that way until a sufficiently thick asphaltene coating has accumulated.
Based on these results, additional hardware has been delivered to Abu Dhabi to begin a long-term pilot study on the use of electron resonance data for asphaltene management. Moreover, the device opens up to the oilfield traditional laboratory uses of electron resonance such as identification of kerogen maturity and geochemical rock typing.
Gaining access to real-time production and injection data is critical for any upstream oil and gas production operation, as it greatly improves and optimizes production efficiency, while reducing costs. This paper highlights how a well-known oil and gas producer with over 800+ onshore and offshore wells used a digital flow assurance solution to improve real time injection and production knowledge by leveraging digital technologies, expertise, and an open, connected data environment (CDE) to deliver business outcomes and a competitive advantage.
The solution interfaces with other software systems to avoid unnecessary replication of data retrieval. Additionally, direct hardware interfacing to multiple systems for data retrieval and systems control were previously located in separate silos. The oil and gas producer used the flow assurance solution as a central source for managing and monitoring data from all such interfaces across a CDE. The web-enabled, real-time system is used for performance monitoring of well stimulation, treatment design, scale inhibitor squeeze performance, scale monitoring and prediction, water chemistry, monitoring chemical and corrosion, and more.
The organization's goal of using the solution was to ensure that production flowrate targets are achieved and that flow was continuous. The solution provided the user with the tools and information it needed within one central source. For example, the input data was converted into actionable information by a calculation/logic engine, enabling them to identify potential problems more efficiently and provide a faster resolution without affecting production. Summary dashboards provided real-time stimulation information as well as overall performance, which can be viewed from a regional perspective or right down at the well asset level. Scorpion charts allowed users to ascertain which stimulation jobs were the best performers and most cost efficient. Stimulation was performed on a well using varying mixtures of acid solutions to increase or restore production by improving the flow of hydrocarbons.
When a well initially exhibits low permeability, stimulation is used to start production from the reservoir. On operational wells, stimulation is used to further encourage permeability and flow from a well that has slowed down or become under productive. The reporting package within the solution is able to show which jobs are performing badly, and incurring more costs, and identify patterns or relationships that might affect similar assets, job types, geology, and regions within the project more easily for action to be taken.
The solution adopted by the user highlights the importance of flow assurance anywhere in the entire cycle as any breakdown in the process would lead to costly monetary losses to the organization due to the unscheduled downtime and loss of production that could incur. Their digital solution takes the unpredictability out of flow assurance and presents it as an effective and cost-efficient process across the company, with the focus on analysis and proactivity as opposed to data mining and reacting.
Abdallah, Dalia (ADNOC Onshore) | Punnapala, Sameer (ADNOC Onshore) | Al Daghar, Khadija (ADNOC) | Kulbrandstad, Omar (MicroSilicon Inc) | Godoy, Manuel (MicroSilicon Inc) | Lovell, John (MicroSilicon Inc) | Madem, Sai (MicroSilicon Inc) | Babakhani, Aydin (UCLA)
Asphaltene deposition has been identified as one of the top flow assurance challenges in a number of onshore fields in Abu Dhabi with over 100 wells impacted. There was no device in the industry for direct measurement of asphaltene deposition, so the national oil company sponsored an R&D project to develop a sensor that could quantify the percentage of asphaltene in the flowing oil. Current ways of identifying an asphaltene problem rely upon accessibility checks with slickline units and hence cleanup operations are reactive and are often too late. In order to detect the problem earlier, an asphaltene specific real-time sensor would be required. The sensor design selected built on the concept of Electron Paramagnetic Resonance (EPR), wherein free-radicals in the asphaltene are resonated by an external magnetic field.
Corrosion in oil and gas operations is generally caused by water, carbon dioxide (CO2) and hydrogen sulfide (H2S), and can be aggravated in downhole applications where high temperatures combination with H2S introduce other challenges related to corrosion and iron sulfide (FeS) scale formation. The repair costs from corrosion attacks are very high and associated failures have effects on plant production rates and process integrity. To overcome this existing problem in upstream, nonmetallic composite materials were introduced for drilling, tubular and completions in high risk, corrosive environments. The goal being to increase the well life cycle and minimize the effect of corrosion, scale and friction in carbon steel tubulars. The new proposed materials have light weight, high strength, and superior fatigue resistance in addition to an outstanding corrosion resistance that is able to surpass many metallic materials.
The economic analysis shows that utilization of nonmetallic tubulars and internal linings will yield substantial life cycle cost saving per well mainly due to the elimination of workover operations. However, with these advantages, composite materials pose several challenges such as single source provision, high initial cost of raw materials, the manufacturing process and the limitation of standards. As results, the polymer and composite solutions for upstream oil and gas are still very limited even in targeting low risk applications such as low temperature and pressure scenarios. Therefore, research & development (R&D) efforts are ongoing to increase the operation envelope and introduce cost effective raw materials for high-pressure, high temperature (HPHT) subsurface applications.
The present paper highlights practical examples of nonmetallic materials selection and qualification for upstream water injection/producer and hydrocarbon wells. Several future NM applications in upstream will be summarized. Challenges and R&D forward strategies are presented in order to expand the operation envelope of current materials and increase NM deployment to more complex wells, i.e., extended reach drilling (ERD).
By miniaturizing and ruggedizing equipment used for quantum paramagnetic spectroscopy, it is now possible to take a real-time chemical snapshot of molecules flowing through the wellhead or other surface fixtures. The digital time-series captures unique chemical properties of the fluid, such as the percentage of asphaltene in the oil, the oil-water ratio and gas-oil ratio. That data can be transmitted via industry-standard cloud protocols and be monitored from a global service center. 12 months of real-time data has been collected from operations around the world and the real-time monitoring has enabled prompt feedback for upgrades in both hardware and software. In a three-phase well configuration that had high rates of both water (over 90%) and gas (~1 MMSCf/day), this feedback drove some significant hardware modifications in order to optimize the consistency of asphaltene data.
The heart of the system is a microwave resonator that was designed to receive fluid at wellhead conditions with minimal reduction from wellhead pressure and temperature. The parameters of the resonator were optimized to maximize microwave intensity for typical oilfield fluids. A tailor-made set-up of fluid accumulator and control-valves upstream of the resonator ensured that the resonator could obtain samples that were mostly oil. By combining the resonator with a solenoid that created a large magnetic field across the oil, the resulting system provided spectroscopic data similar to that available in chemical laboratories but in a smaller package and one that tolerates some gas and conductive water in the oil. The combined quantum data is now provided continuously to the operator via a cloud or other communication architecture of operator choosing. It is anticipated that the resulting Internet of Things (IoT) system will make possible the optimization of chemical program and asphaltene remediation by incorporating system data with integrated flow assurance management. Qualification for offshore is ongoing with 5ksi pressure certification already achieved.
It was not obvious before installation, but once the 3-phase system was installed and the data transmitting in real-time, it became clear that software to automatically extract asphaltene information from spectral data needed to be able to cope with sudden and large changes in both asphaltene level and water-cut/gas-oil ratio which in turn required building an adaptive software model. Asphaltene percentage at one producing well was seen to vary from 0.3% to 3% in a single day. It was also discovered from the cloud-based monitoring that daily temperature variation introduced a phase variation in the shape of the sensor response. Correct derivation of spectral voltages was achieved through the combination of machine learning, model-based analysis and additional diagnostic data such as the quality factor of the resonator and its resonance frequency. As a consequence, the AI-based software could extract the not only the asphaltene percentage but the oil-water cut in the resonator and its gas-oil ratio.
For the first time, it is now possible to make a change in, say injected chemicals, look at the times-series data for the corresponding change in asphaltene and then adjust the chemicals accordingly. Such frequency of sampling (and volume of data) would be too much to handle with samples collected by hand. This device lays the platform for a multiplicity of chemical sensors to be connected to the cloud in real-time and in turn sets the stage to take the hardware offshore and eventually to subsea.