SPE Annual Technical Conference and Exhibition

Conference Information
Name: SPE Annual Technical Conference and Exhibition
Date: 2021-9-21 - 2021-9-23

Latest articles from this conference

Ala AlDogail, Rahul Gajbhiye, Mustafa AlNaser, Abdullatif AlNajim
Day 2 Wed, September 22, 2021; https://doi.org/10.2118/206045-ms

This study aims to propose an intelligent operational advisory solution that guides the plant operation team to optimal HPPT/LPPT pressure settings that compensate for the variation in ambient temperature effect to maximize plant revenue. Traditional industry practice is to operate a gas-oil-separation-plant (GOSP) at fixed operating conditions ignoring the variation in the ambient temperature (Ta) leading to a loss in oil recovery and associated revenue. The variation of ambient temperature (Ta) highly affects the separation process, where ambient temperature varies greatly from summer to winter. To develop a correlation, a GOSP model was constructed by OmegaLand dynamic simulator using a typical Saudi Aramco GOSP design. Oil recovery values were determined by running the process simulation for a typical range of high-pressure production trap (HPPT), low-pressure production trap (LPPT), and ambient temperature (Ta). Then, an intelligent approach was built to determine the optimum pressure of LPPT and HPPT units for each ambient temperature condition using an artificial intelligence technique. Results show that liquid recovery decreases with an increase in ambient temperature at constant HPPT and LPPT pressures, indicating adjustment in HPPT or LPPT pressure responding to the temperature variations can improve the oil recovery. At constant LPPT pressure and ambient temperature, the oil recovery increases with an increase in HPPT pressure until it reaches the optimum value and then decreases with further increase in the HPPTpressure suggesting that there is an optimum HPPT pressure at which oil recovery is maximum. At fixed ambient temperature and fixed HPPT pressure, liquid recovery increases with increasing LPPT pressure until it reaches the optimum value, and then it decreases with further increase in the LPPT pressure suggesting that there is an optimum LPPT pressure at which oil recovery is maximum.
Hongquan Chen, Deepthi Sen, Akhil Datta-Gupta, Masahiro Nagao
Day 2 Wed, September 22, 2021; https://doi.org/10.2118/205944-ms

Routine well-wise injection and production measurements contain significant information on subsurface structure and properties. Data-driven technology that interprets surface data into subsurface structure or properties can assist operators in making informed decisions by providing a better understanding of field assets. Our machine-learning framework is built on the statistical recurrent unit (SRU) model and interprets well-based injection/production data into inter-well connectivity without relying on a geologic model. We test it on synthetic and field-scale CO2 EOR projects utilizing the water-alternating-gas (WAG) process. SRU is a special type of recurrent neural network (RNN) that allows for better characterization of temporal trends, by learning various statistics of the input at different time scales. In our application, the complete states (injection rate, pressure and cumulative injection) at injectors and pressure states at producers are fed to SRU as the input and the phase rates at producers are treated as the output. Once the SRU is trained and validated, it is then used to assess the connectivity of each injector to any producer using permutation variable importance method, wherein inputs corresponding to an injector are shuffled and the increase in prediction error at a given producer is recorded as the importance (connectivity metric) of the injector to the producer. This method is tested in both synthetic and field-scale cases. The validation of the proposed data-driven inter-well connectivity assessment is performed using synthetic data from simulation models where inter-well connectivity can be easily measured using the streamline-based flux allocation. The SRU model is shown to offer excellent prediction performance on the synthetic case. Despite significant measurement noise and frequent well shut-ins imposed in the field-scale case, the SRU model offers good prediction accuracy, the overall relative error of the phase production rates at most producers ranges from 10% to 30%. It is shown that the dominant connections identified by the data-driven method and streamline method are in close agreement. This significantly improves confidence in our data-driven procedure. The novelty of this work is that it is purely data-driven method and can directly interpret routine surface measurements to intuitive subsurface knowledge. Furthermore, the streamline-based validation procedure provides physics-based backing to the results obtained from data analytics. The study results in a reliable and efficient data analytics framework that is well-suited for large field applications.
Peter Bridle
Day 3 Thu, September 23, 2021; https://doi.org/10.2118/205858-ms

By July of 2021, it would have been 33 years since the 1988 Piper Alpha tragedy in the UK sector of the North Sea where 167 oil field workers lost their lives. Without question, the incident was a watershed event for the international oil and gas industry. And not simply because of the immediate toll in human lives lost, but also in terms of the devasting aftermath endured by countless friends, families and loved ones whose lives were forever changed on that fateful day. The tragedy also served to illustrate how much work would be needed by the oil and gas industry to fully understand and better manage those operating risks that possessed the potential for catastrophic loss in terms of business cost and reputational impact. In the wake of the public enquiry that followed and chaired by Lord Cullen of Whitekirk, one of the principal recommendations resulting from the disaster required that the international oil and gas industry do a much better job in determining both its major hazards (i.e. major operating risks) and in creating the necessary operating conditions to demonstrate that such things were being well managed. The objective being to provide tangible assurance that the likelihood of the industry ever incurring such a calamitous event again in the future had been reduced to as low as reasonably practicable (ALARP). In taking its responsibilities very seriously, the international oil and gas industry responded by raising the profile of the management of Health, Safety, and the Environment (HSE) across the wide spectrum of its global operations. By the mid-nineties, the industry had implemented comprehensive and structured systems of work within the framework of purposely built HSE Management Systems using templates designed and developed for the industry via the International Oil and Gas Producers (IOGP)*.
Ramsey White, Simone Mulas, Pier Domini, Miguel Lopez, Faris Abusittah
Day 2 Wed, September 22, 2021; https://doi.org/10.2118/205860-ms

The Modulated AC/DC Crude Desalting technology was successfully commissioned at several Saudi Aramco facilities. Enhancements to desalting performance and optimization of plant operating expenditures were realized. Benefits of the Modulated AC/DC Desalting technology, installation and operational best practices and a comparison to conventional AC technology is shared in the paper. The conventional AC desalting technology was replaced with the Modulated AC/DC Crude Desalting technology at some Saudi Aramco facilities. After the successful commissioning, the performance of the new units was tested in one of these facilities to identify operating limits, such as maximum water cut and minimum demulsifier injection at the production header, in which the stable operation is sustainable. A comparison of the performance of the technology compared to that of previous conventional AC desalting technology was conducted through analysis of grid/plate voltage stability, demulsifier injection rate, wash water rates and crude quality parameters. Some enhancements to the process were also introduced which resulted in realizing additional benefits. The technology resulted in several benefits, including: (1) A reduction in the required demulsifier injection rate during the testing period compared to the same time period from the previous year, leading to significant cost savings; (2) Ability to maintain normal operations beyond the design water cuts of the facility; (3) No major grid outages since installation; (4) Additional data that can be used to diagnose separation performance as each transformer provides a number of feedback signals to DCS that are good indicators of the separation process. Based on the observations and analysis, the Modulated AC/DC Crude Desalting Technology has several advantages over the conventional AC Crude Desalting Technology in regards to crude desalting performance and process stability. The Modulated AC/DC Crude Desalting technology at Saudi Aramco was the first installation in Saudi Arabia for Arab Light crude oil. The paper captures Saudi Aramco’s experience and best practices that other companies can find beneficial in their efforts to maintain crude quality and reduce operating expenditures.
Anjana Panchakarla, Tapan Kidambi, Ashish Sharma, Eduardo Cazeneuve, Rbn Singh, Arun Kumar Sv
Day 1 Tue, September 21, 2021; https://doi.org/10.2118/206229-ms

Drilling wells in the remote northeastern part of India has always been a tremendous challenge owing to the subsurface complexity. This paper highlights the case of an exploratory well drilled in this region primarily targeting the main hydrocarbon bearing formations. The lithology characterized by mainly shale, siltstone and claystone sequences, are known to project high variance in terms of acoustic anisotropy. Additionally some mixed lithological sequences are also noted at particular depths and have been identified at posing potential problems during drilling operations. Several issues became apparent during the course of drilling the well, the main factor being consistently poor borehole condition. An added factor potentially exacerbating the progressively worsening borehole conditions was attributed to the significant tectonic activity in the area. To address and identify these issues and to pave the way for future operations in this region, a Deep Shear Wave Imaging analysis was commissioned to identify near and far wellbore geological features, in addition to addressing the geomechanical response of these formations. In this regard, acoustic based stress profiling and acoustic anisotropy analysis was carried out to estimate borehole stability for the drilled well section and provide insights for future drilling plans. Significant losses were observed while drilling the well, in addition to secondary problems including tight spots and hold ups and consequently the well had to be back reamed multiple times. Of particular note were the losses observed while transitioning between the main formations of interest. The former consisting relatively lower density claystone/siltstone formations and the latter, somewhat shalier interlayered with sandstones, displaying a generally higher density trend. This transition zone proved to be tricky while drilling, as a high density sandstone patch was encountered further impeding the drilling ROP. Overall, both formations were characterized by significantly low rock strength moduli with the exception of the sandstones projecting characteristically higher strengths. In light of these events, analysis of integrated geological, geomechanical and advanced borehole acoustic data analyses were used to identify the nature of the anisotropy, in terms of either stress induced, or caused by the presence of fractures in the vicinity of the borehole. The extensive analysis further identified sub-seismic features impeding drillability in these lithologies. Further, the holistic approach helped characterize the pressure regimes in different formations and in parallel, based on corroboration from available data, constrained stress magnitudes, indicating a transitional faulting regime. Variances in stress settings corresponded to the depths just above the transition zone, where significant variations were observed in shear wave azimuthal trends thereby indicating the presence of potential fracture clusters, some of which were revealed to be intersecting the borehole thereby causing stress. The analysis shed light on these near well fractures- prone to shear slip, causing mud losses during drilling while drilling with high mud weights. Finally, the encompassing multiple results, an operational mud weight window was devised for the planned casing setting depths. Given the presence of numerous fractures, the upper bound of the operational mud window was constrained further to account for the presence of these fractures. In summary, an integrated approach involving a detailed DSWI study in addition to traditional geomechanics has brought about new perspectives in assessing borehole instability. By actively identifying the sub surface features, (sub seismic faults and fractures) decisions can be taken on mud weight and optimizing drilling parameters dynamically for future field development.
Konstantin Maksyutin, Anna Zalevina, Pavel Sorokin, Valeriy Rukavishnikov, Artem Boev, Polina Kharitontseva, Vasilii Solovev, Arina Portniagina, Alexey Lukin
Day 3 Thu, September 23, 2021; https://doi.org/10.2118/206130-ms

A major Russian oil company is currently carrying through an ambitious program aimed at transforming corporate E&P business model. The new model involving product-based approach to exploration and production will require young professionals with new skills and mindsets beyond regular university curricula. To proactively satisfy this demand, the company joined forces with one of its partner universities to champion Engineers of the Future, a training initiative aimed at senior students about to graduate and join the company. Engineers of the Future offer a fresh perspective and approach to training young professionals, mixing conventional training with problem-based and game-based learning to deliver a unique combination of hard and soft skills required by company's new operating paradigm. Program graduates are expected to make a great addition to corporate product teams, enabling the company to achieve its challenging strategic goals.
Mohamed Mehdi El Faidouzi
Day 1 Tue, September 21, 2021; https://doi.org/10.2118/206307-ms

Water-alternating-gas (WAG) injection, both miscible and immiscible, is a widely used enhanced oil recovery method with over 80 field cases. Despite its prevalence, the numerical modeling of the physical processes involved remains poorly understood, and existing models often lack predictability. Part of the complexity stems from the component exchange between gas and oil and the hysteretic relative permeability effects. Thus, improving the reliability of numerical models requires the calibration of the equation of state (EOS) against phase behavior data from swelling/extraction and slim-tube tests, and the calibration of the three-phase relative permeability model against WAG coreflood experiments. This paper presents the results and interpretation of a complete set of two-phase and thee-phase displacement experiments on mixed-wet carbonate rocks. The three-phase WAG experiments were conducted on the same composite core at near-miscible reservoir condition; experiments differ in the injection order and length of their injection cycles. First, the two-phase water/oil and gas/oil displacement experiments and first cycles of WAG were used to estimate the two-phase relative permeabilities. Then, a synchronized history-matching procedure over the full set of WAG experiments and cycles was carried out to tune Larsen ans Skauge WAG hysteresis model—namely the Land gas traping parameter, the gas reduction exponent, the residual oil reduction factor and three-phase water relative permeability. The second part of this paper deals with the multiphase upscaling of microscopic displacement properties from plug to coarse grid reservoir scale. The two-phase relative permeability curves and three-phase WAG parameters were upscaled using a sector model to preserve the displacement process and reservoir performance. The result of the coreflood calibration indicate that the two-phase displacement and first cycles of WAG yield a consistent set of two-phase relative permeabilities. Including the full set of WAG experiments allowed a robust calibration of the hysteresis model.
Ahmad Alfakher, David A. DiCarlo
Day 2 Wed, September 22, 2021; https://doi.org/10.2118/206278-ms

Solvent flooding is a well-established method of enhanced oil recovery (EOR), with carbon dioxide (CO2) being the most-often used solvent. As CO2 is both less viscous and less dense than the fluids it displaces, the displacement suffers from poor sweep efficiency caused by an unfavorable mobility ratio and unfavorable gravity number. Creating in-situ CO2 foam improves the sweep efficiency of CO2 floods. Another application is the injection of CO2 foam into saline aquifers for carbon capture and storage (CCS). The goal of the core flood experiments in this paper was to study the effectiveness of surface coated silica nanoparticles as an in-situ CO2 foaming agent. In each experiment, the pressure drop was measured across five separate sections in the core, as well as along the whole core. In addition, the saturation distribution in the core was calculated periodically using computed tomography (CT) scanning measurements. The experiments consisted of vertical core floods where liquid CO2 displaced brine from the top to the bottom of the core. A flood with surface coated silica nanoparticles suspended in the brine is performed in the same core and at the same conditions to a flood with no nanoparticles, and results from these floods are compared. In these experiments, breakthrough occurred 45% later with foamed CO2, and the final CO2 saturation was also 45% greater than with the unfoamed CO2. The study shows how nanoparticles stabilize the CO2 front. The results provide quantitative information on, as well as a graphical representation of, the behavior of the CO2 foam front as it advances through the core. This data can be used to upscale the behavior observed and properties calculated from the core-scale to the reservoir-scale to improve field applications of CO2 flooding.
Maged Alaa Taha, Eissa Shokier, Attia Attia, Aamer Yahia, Khaled Mansour
Day 3 Thu, September 23, 2021; https://doi.org/10.2118/206190-ms

In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce. This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out. The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%. It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.
Madhusuden Agrawal, Ahmadreza Haghnegahdar, Rahul Bharadwaj
Day 2 Wed, September 22, 2021; https://doi.org/10.2118/206122-ms

Predicting accurate erosion rate due to sand particles in oil and gas production is important for maintaining safe and reliable operations while maximizing output efficiency. Computational Fluid Dynamic (CFD) is a powerful tool for erosion prediction as it provides detailed erosion pattern in complex geometry. In an effort to improve accuracy of erosion prediction, this paper proposes an algorithm to accurately represent particle shape in CFD erosion simulation through coupling with Discrete Element Method (DEM) for non-spherical shape particles. The fluid motions are predicted by CFD and the particle movements (including particle-particle and particle-wall collisions) and fluid-particle interaction are calculated using DEM. It is widely known that sand particles are of finite volume with a non-spherical shape, accurate representation of sand particles is important in CFD modelling for accurate prediction of erosion rate. Traditional CFD approach usages lagrangian tracking of sand particles through Discrete Phase Model (DPM), where a particle is assumed as a point mass for the calculation of trajectory and particle-wall interaction. Particle impact velocity and impact angle are important parameter in determining erosion. Assumption of point mass in DPM approach, will not capture particle-wall interaction accurately especially when particles are of non-spherical in shape. In additional, DPM approach ignores particle-particle interactions. This can adversary affect the accuracy of erosion predictions. Integrating non-spherical DEM collision algorithm with CFD erosion simulation, will overcome these limitations and improve erosion predictions. Benefits of this CFD-DEM erosion modelling was demonstrated for gas-solid flow in a 2" pipework which consists of out-of-plane elbows in series and blind-tees. Experimental dataset [1] for erosion pattern on each elbow was used to validate CFD predictions. Three different erosion CFD simulations were performed, traditional DPM based CFD simulation, CFD-DEM simulation for spherical shape particles and CFD-DEM simulation for non-spherical shape particles. CFD-DEM coupled simulations clearly show an improvement on erosion predictions compared to DPM based CFD simulation. Effect of non-spherical shape on rebound angle during particle-wall collision is captured accurately in CFD-DEM simulation. CFD-DEM simulation using non-spherical particle, was able to predict erosion pattern closer to experimental observations. This paper will demonstrate an increase in accuracy of sand erosion prediction by integrating DEM collision algorithm in CFD modelling. The prediction results of elbow erosion subject to a condition of dilute gas-particle flow are validated against experimental data. Improved prediction of erosion risk will increase the safety and reliability of oil & gas operations, while maximizing output efficiency.
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