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Abstract Effective management of process safety risks while delivering flawless operational execution in an evolving oil and gas industry requires innovative applications of digital technology. Augmented Reality (AR) or Mixed Reality (MR) technologies have tremendous potential to meet these challenges by providing realworld digital landscape to intuitively interact with data, train personnel, and mitigate process safety risks. However, a major challenge with AR and MR technologies is the limited processing power and capability of available hardware. A cloud-based software platform can overcome these computational limitations of AR and MR devices, enabling interaction with significantly more complex 3D content. Additionally, enabling real-time connectivity across different hardware architectures – such as smartphones and Microsoft HoloLens devices – creating powerful new capability for remote collaboration. This unique software platform transforms consumer-grade AR and MR devices into powerful industrial tools for oil and gas applications. This paper will illustrate the application of AR/MR technology in critical risk management including the adoption of AR/MR technology for process safety operational readiness and response capability to critical risk associated with major accident hazards. Enhanced AR/MR provides full-scale virtual digital landscapes that enable practical demonstration of crew resource management including the evaluation of collaborative human performance in teamwork activities. Using gamified AR/MR techniques, allows for multiple outcomes based on user inputs to test decision-making and eliminate human errors. These enabling technologies can drive significant improvements in process safety risk management while increasing operational efficiencies across the oil and gas industry.
Laboratory testing of corrosion inhibitors under high temperature high pressure (HTHP) conditions is challenging. HTHP testing has been traditionally performed in closed systems with fixed liquid/gas volume and testing results are usually influenced/compromised by the accumulation of ferrous ions and corrosion products. The aim of the work is to optimize corrosion inhibitor testing conditions at HTHP to generate results of better reliability. The corrosion of carbon steel by CO2 at HTHP was assessed using small working electrodes of large liquid volume-to-sample surface area in autoclaves. The effect of CO2 partial pressure was also investigated. The blank and inhibited corrosion rates were monitored by linear polarization resistance (LPR) and the morphology of coupon surface was measured by vertical scanning interferometry (VSI). The testing results were deemed to be more representative of the field service environment when the amount of ferrous ions and corrosion products was reduced due to the usage of small working electrodes.
With the decline of conventional oilfields, an increasing amount of oil is being produced in deep shale reservoirs in which high temperature/high pressure (HT/HP) is usually encountered. HT/HP corrosion by CO2 represents one of the major challenges in oil production.1–5 A variety of CO2 corrosion inhibitors have been developed over the years for low temperature (<212 °F) applications, however, the development of CO2 corrosion inhibitors for HT/HP conditions (>302 °F) is still in an early stage and available products can still be improved.
HT/HP laboratory corrosion inhibitor studies under CO2 conditions are usually performed in closed systems (e.g., autoclaves) with fixed amount of fluids.6,7 During HT/HP corrosion testing, such parameters like brine chemistry, scaling tendency, pH, Fe2+ concentration, and coupon surface condition, are expected to change, particularly under HT/HP conditions. In fact, these changes can proceed quite fast. Particularly, the accumulation of Fe2+ in brine may result in the precipitation of FeCO3 on the coupon surface and decrease the corrosion rate. This effect hinders the replication of a field condition in the laboratory and the differentiation of inhibited from baseline data. The objective of this work is to optimize corrosion inhibitor testing conditions at HTHP to generate results of better reliability. The corrosion behavior was evaluated at two testing temperatures (300 and 350 °F) and with CO2 partial pressures of 50 and 250 psi.
Chochua, G. G. (Schlumberger) | Parsi, M. (National Oilwell Varco) | Zhang, Y. (Baker Hughes) | Zhang, J. (The University of Tulsa) | Sedrez, T. A. (The University of Tulsa) | Karimi, S. (The University of Tulsa) | Darihaki, F. (The University of Tulsa) | Edwards, J. (Corvid Technologies LLC) | Arabnejad, H. (The University of Tulsa / Halliburton) | Agrawal, M. (BP America) | Asgharpour, A. (The University of Tulsa) | Vieira, R. E. (The University of Tulsa) | Zahedi, P. (Bechtel Oil, Gas & Chemical Inc) | Gharaibah, E. (Baker Hughes, a GE company) | Shirazi, S. A. (The University of Tulsa)
ABSTRACT Solid particle erosion is one of the key issues affecting operational reliability and the cost of tools and equipment in the oil and gas industry. In a particular erosive environment, the extent to which erosion occurs depends on many factors, such as flow conditions, fluid properties, wall material, and particle properties. As a result, it is difficult to investigate the effects of all of these factors using experimental methods. One comprehensive alternative, however, is to use computational fluid dynamics (CFD), which can provide the analyst with a great deal of information about the phenomenon, such as where erosion occurs as well as its severity. Of course, when using any CFD-based erosion prediction method, care must be taken when selecting appropriate meshing practices, solution parameters, and sub-models. Best practices and guidelines for solid particle erosion modeling using CFD are described. In addition to discussing many parameters that should be considered when using CFD to predict solid particle erosion, the effects of many of these parameters and sub-models within the CFD codes are also discussed with several examples comparing CFD results to available experimental data. This paper can serve as a first step toward developing a comprehensive guideline for the industrial modeling of erosion phenomena and to help engineers improve the accuracy of erosion wear predictions. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. In many oil and gas wells, particles such as sand, carbonate, or other solid impurities are produced; one of the primary issues with these situations is the erosion of pipelines and fittings. There are various approaches to predicting solid particle erosion. One of the earlier guidelines was the American Petroleum Institute's Recommended Practice 14E 1, in which an "erosional threshold velocity" is compared to the actual process flow velocity. This guideline, however, does not account for many parameters that contribute to erosion. There are also empirical equations such as those developed by Salama and Venkatesh (1983) 2, the CFDbased correlation by Parsi et al. (2017) 3, and the semi-mechanistic-empirical model by Shirazi et al. (2016) 4 .
Marum, Daniela Martins (Baker Hughes, a GE company) | Afonso, Maria Diná (Universidade de Lisboa Instituto Superior Técnico, CeFEMA) | Ochoa, Brian Bernardo (Baker Hughes, a GE company)
Summary An advanced gas analysis heated system (AGAHS) analyzes the gas extracted from a water-based mud (WBM) to estimate the hydrocarbons contents in drilled rock formations. Operating conditions within the gas-extraction device (gas trap) such as the gas concentration in the mud, stirring velocity, mud-flow rate and temperature, and ditch-line flow rate and pressure are studied to maximize the gas-extraction efficiency in the gas trap. The operating conditions that most affect the gas-extraction efficiency are the stirring velocity and the mud-flow rate. The highest and most stable gas-extraction efficiencies are obtained at 1,680 rev/min and 1.0 L/min.
Marum, Daniela Martins (Baker Hughes, a GE company) | Afonso, Maria Diná (Universidade de Lisboa Instituto Superior Técnico, CeFEMA) | Ochoa, Brian Bernardo (Baker Hughes, a GE company)
An advanced gas analysis heated system (AGAHS) analyzes the gas extracted from a water-based mud (WBM) to estimate the hydrocarbons contents in drilled rock formations. Operating conditions within the gas-extraction device (gas trap) such as the gas concentration in the mud, stirring velocity, mud-flow rate and temperature, and ditch-line flow rate and pressure are studied to maximize the gas-extraction efficiency in the gas trap. The operating conditions that most affect the gas-extraction efficiency are the stirring velocity and the mud-flow rate. The highest and most stable gas-extraction efficiencies are obtained at 1,680 rev/min and 1.0 L/min.
Izadi, Ghazal (Baker Hughes, a GE company) | Mahrooqi, Shabib (Petroleum Development Oman) | Shaibani, Mahmood (Petroleum Development Oman) | Dobroskok, Anastasia (Petroleum Development Oman) | Guises, Romain (Baker Hughes, a GE company) | Barton, Colleen (Baker Hughes, a GE company) | Ghadimipour, Amir (Baker Hughes, a GE company) | Randazzo, Santi (Baker Hughes, a GE company) | Bratovich, Matt (Baker Hughes, a GE company) | Tinnin, John (Baker Hughes, a GE company) | Walles, Frank (Baker Hughes, a GE company) | Khamatdinov, Rafael (Baker Hughes, a GE company) | Franquet, Javier (Baker Hughes, a GE company) | Perumalla, Satya (Baker Hughes, a GE company) | Freitag, Hans-Christian (Baker Hughes, a GE company)
Copyright 2020, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Dhahran, Saudi Arabia, 13 - 15 January 2020. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Izadi, Ghazal (Baker Hughes, a GE company) | Guises, Romain (Baker Hughes, a GE company) | Barton, Colleen (Baker Hughes, a GE company) | Randazzo, Santi (Baker Hughes, a GE company) | Mahrooqi, Shabib (Petroleum Development Oman) | Shaibani, Mahmood (Petroleum Development Oman) | Dobroskok, Anastasia (Petroleum Development Oman)
A fit-for-purpose integrated subsurface study was carried out in a tight gas field in Oman to evaluate the stimulation process in horizontal wells. The objective is to explore the role of vertically and laterally heterogeneous in situ stress for hydraulic fracture (HF) propagation, and to quantify its effect on hydraulic fracture stimulation efficiency using a 3D fully-coupled hydraulic fracturing simulator for complex geological conditions. The use of advanced simulation tools that realistically predict the evolution of stresses in 3D allows us to explore the parameter space required to optimally design stimulations for complex tight and unconventional field development [Izadi et al. 2017; Cruz et al. 2018; Izadi et al. 2018].
The goal of this study is to test scenarios that increase production through reservoir contact by use of various fracturing techniques that improve the Stimulated Rock Volume (SRV).
The modeling scenarios include an assessment of:
The impact of high vs. low
The impact of in situ stress magnitude in near wellbore conductivity
The impact of fluid properties and landing zone on proppant transport
The effect of laminations on proppant transport
The impact of HF/natural fracture interactions on SRV
This study illustrates that for complex reservoirs where spatial heterogeneities, preexisting natural fractures, or transitional stress states are present, advanced 3D modeling provides insight critical to optimize development strategy. Through parametric stimulation modeling design, mechanisms driving drilling, completion, stimulation and productions processes can be honed to optimize and better manage the primary risks to development in tight/unconventional reservoirs [
Noufal, Abdelwahab (ADNOC Upstream) | El Wazir, Zinhom (ADNOC Onshore) | Al Madani, Noura (ADNOC Onshore) | Shinde, Ashok (Baker Hughes, a GE company) | Perumalla, Satya (Baker Hughes, a GE company) | Aldin, Munir (MetaRock) | Govindrajan, Sudarshan (MetaRock) | Gokaraju, Deepak (MetaRock)
Abstract Heterogeneous nature of the Cretaceous carbonate reservoirs in Abu Dhabi increases there complexity to attain efficient characterization and hence development. During depletion, reservoir pressure reduction results in unequal increase of vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir pore structure. At reservoir pressures below a critical value (obtained via laboratory testing or post failure field analysis), the reservoir compacts at accelerated rates. Compaction and its associated reduction in reservoir pore volume leads to rapid loss in permeability, generation of fines and wellbore stability issues (e.g., casing collapse). Assessing the magnitude of these changes require laboratory measurements of rock compressibility (grain, bulk and pore compressibilities), and concurrent evaluations of reduction of pore volume, porosity and permeability as a function of reservoir pressure needs to be appropriately simulated in-situ stress conditions. Poor appreciation of the rock compressibility mechanics and its robust dependence on stress path (e.g., hydrostatic- and/or uniaxial strain compression) in addition to depletion rate may result in substantial cost. The core intervals are selected to capture the lateral and vertical heterogeneity encountered in the studied reservoirs. The test program was designed to create a material model to capture the rock response to potential reservoir pressure changes. Single Stage Triaxial tests at multiple confining stresses were conducted to judge the shear failure. Tests recommended for evaluation and assessment of reservoir compaction are Uniaxial-strain compression (far-field compaction), triaxial compression (near wellbore), Hydrostatic (define the compaction cap) and constant stress-path. Additional tests were carried to characterize the poro-elastic response of reservoir rock and the stress-dependent permeability. A combined failure envelope (defining shear (dilatant) and compaction ("Cap") for compactable sediments) of the rock was generated by integrating the results from Single stage Triaxial tests (Shear failure envelope), hydrostatic compression tests and UPVC tests (Compaction failure envelope). For field applications, it is useful to provide a visualization of the pre-production-state in-situ stress conditions, and the possible stress path trajectories of the reservoir, as a function of reservoir depletion. Such a failure envelope was generated for all the different lithofacies encountered across the field. The characterized material model enables us to assess and predict the risk of shear/compaction deformation associated with the reservoir pressure changes (considering field stress path). Using this display, the level of depletion resulting in accelerated compaction can be identified through laboratory testing. The introduced workflow presents a comprehensive geomechanical characterization program for such complex carbonate reservoir. This utilizes a systematic approach to generate field wide understanding of rock response to depletion and injection. It can also act as a guide to address the compaction-based challenges faced in other reservoirs of Abu Dhabi.
Ali, Arfan (Brunei Shell Petroleum) | Jofri, Azimah (Brunei Shell Petroleum) | Zamikhan, Norshah (Brunei Shell Petroleum) | Borah, Jahnabi (Brunei Shell Petroleum) | Yahya, Mohd Noor (Brunei Shell Petroleum) | Van Den Heuvel, Erik (Brunei Shell Petroleum) | Kim, Igor (Shell Global Solutions International) | Hardikar, Nikhil (Baker Hughes, a GE company) | Coskun, Sefer (Baker Hughes, a GE company)
Abstract Since the advancement of Focused Sampling techniques, wireline formation fluid sampling has undergone a dramatic change. This has primarily been due to the promise of acquiring representative formation fluid samples with minimal mud filtrate contamination and large sample volumes, thereby adding value to the PVT laboratory studies as well as reducing the fluid sampling time, thus aiding significantly to the cost savings. This paper demonstrates the contribution of focused sampling technology for reservoir fluid mapping in numerous exploration and development wells in South East (SE) Asia, by optimized selection of different packer types based on varying reservoir properties. For the exploration wells, the primary objective was to determine the non-hydrocarbon (non-HC) content (CO2 and H2S in this case) of the single-phase reservoir fluid samples, which were expected to be close to the saturation pressures. Following the 3D near-wellbore simulations, an elongated and an extra-elongated focused packer were selected due to expected low permeabilities, reservoir thickness and wellbore conditions. The wells were drilled in managed pressure drilling (MPD) conditions, with overbalance ranging from 900 to 4,300 psi. The development campaign consisted of five producers with key objectives of determining fluid type and the non-HC (CO2 in this case) content along with assessing the reservoir/block connectivity. The concentration and uncertainty in CO2 distribution would have a major impact in developing the production strategy of the area. A standard focused packer was selected for the sampling jobs which were carried out on pipe due to high overbalance conditions (~2,400 psi). In the exploration wells, 30+ samples (gas, oil and water) were collected with the time-on-wall ranging between 1.5 and 7 hours. In the development campaign, 50+ samples (gas and oil) were collected with the time-on-wall ranging between 45 minutes and 2.5 hours. Given the depths and low permeabilities of the reservoirs with high overbalance, this resulted in significant time savings. The larger flow area of the elongated and extra-elongated focused packers ensured minimal contamination in the collected samples given the challenging sampling conditions, where restrictions to pressure drawdown existed. The PVT laboratory results showed ‘insignificant’ oil-based mud filtrate contamination in the samples. In addition, the large sample volumes provided flexibility for additional PVT studies and improved resource assessment. The focused sampling technology was successfully applied in both exploration and development campaigns in the SE Asia region. The pre-job simulations ensured optimal packer selection between the three focused packer types. The comparison between the actual sampling results and the 3D near-wellbore simulation would help optimize future sampling operations in the area. In addition, the two campaigns have reiterated a clear value of information in saving cost, reducing contamination in the samples and technology success in the given environments.
Heinisch, Dennis (Baker Hughes, a GE company) | Kueck, Armin (Baker Hughes, a GE company) | Herbig, Christian (Baker Hughes, a GE company) | Zuberi, Mamoon (Baker Hughes, a GE company) | Peters, Volker (Baker Hughes, a GE company) | Reckmann, Hanno (Baker Hughes, a GE company)
Abstract Self-excited torsional vibrations of the bottomhole assembly (BHA) at frequencies above 50 Hz, so-called "high-frequency torsional oscillations" (HFTO), can damage drilling tools and can increase non-productive time (NPT). A recently developed HFTO-isolation tool protects the drilling tools above this tool from these harmful vibrations. More than 200 field runs were investigated to evaluate the changes in reliability and benefits. The concept of the isolation tool works similarly to a two-mass flywheel used in automotive drive trains. The design was simulated, lab-tested and first deployed in a field run in 2018. Since then, the isolation tool was successfully used in various fields and applications in the Middle East. HFTO severity while drilling was measured and recorded below and above the isolation tool to verify functionality and to quantify reduction in torsional loads (torque, tangential acceleration) for the measurement while drilling (MWD), mud pulse telemetry (MPT), and logging while drilling (LWD) tools above the tool. In addition, HFTO-related incidents and other drilling performance indicators with and without the new tool were analyzed. Analysis of the recorded vibration data from several field runs with an additional high-frequency MWD-tool reveals that the isolation principle works consistently. As predicted by simulation, the measured torsional vibration amplitudes above the tool are significantly lower than without using it, demonstrating the effective protection for MWD-, LWD-, and MPT-tools in the BHA. The tool has proven consistent performance in more than 16,000 accumulated circulating hours. Tool failures caused by HFTO were eliminated, compared to 22 percent of all failures without the isolation tool. The results of an analysis of individual MWD- and MPT-tools used in runs with and without the isolation tool show a significant increase in distance drilled per tool deployment and re-run decisions. This directly translates to increased asset utilization, fewer trips for failure, and BHA handling operations that results in less non-productive time (NPT) and enables drilling in extremely challenging environments more efficiently.