bluuebunny/crossref_metadata_2025_split huggingface dataset:
GPU-Based High-End Desktop Computing, A Cost-Effective Solution to Improve Reservoir Simulation Performance
Authors: Hernandez Quintero Maria de Los Angeles , Patacchini Leonardo , Al Remeithi Khaled , Figuera Luis Alfredo , Khait Mark 
Published: October 2022

Abstract
The ever-increasing resolution of reservoir simulation models, combined with the emergence of ensemble approaches, call for the adoption of simulators running on Graphics Processing Units (GPUs), as these offer unprecedented performance on limited hardware footprint. We here discuss how the adoption of such a tool within Mubadala Petroleum allows engineers to seamlessly run partners' models on local workstations, avoiding the complications of accessing cloud computing resources (no data transfer authorizations, challenging cost-control, risk of vendor lock-in, etc.).
Adopting new business-critical tools such reservoir simulators require careful validation; not only is the performance important, but also the stability and reliability. For instance, are the results sensitive to minor changes in the model? Or some others can lead to a change in hardware? In effect, in any nonoperating holding-company, it is furthermore important to be able to masterly reproduce the documented profiles. After a review of the principles of GPU based reservoir simulation, the process undergone to perform the above-mentioned validation were presented in this paper using local workstations.
Different simulation models with different levels of complexity have been tested using the GPU computing architecture of mid-end and high-end desktop computer (MEDC and HEDC). History matching and prediction runs were carefully validated against the original benchmark results. Additional tests and the performance scalability across various configurations were also explored. The comparison of different GPU-based computer gave the appropriate results compared to a highly invested option of having multiple multi-core processors, a cluster, or a networked computer.
The use of GPU-based high-end desktop computer (HEDC) will allow to deliver recommendations in time to support final investments decision, primarily because parallel solution simulations speed up simulation time, which is especially important in carrying out prediction solutions scenarios.
From this perspective, the added value of using GPU's HEDC presented in this study shows the significance and most convenient solution for decision making as a suitable option for Mubadala Petroleum.
Monitoring Health of Minagish Reservoir Through Tracking Movement of Reservoir Fluids
Authors: Kasaraneni Pruthvi Raj , Al Rashidi Tahani , Al Zamanan Mishary , Padhy Girija Shankar , Silambuchelvan Jeevan Kumar 
Published: October 2022

Abstract
This paper describes the methodology adopted to Monitor Health of Reservoir by tracking historical movement of reservoir fluids in an Oolitic limestone reservoir in Kuwait. The reservoir has a weak aquifer support, hence Gas injection followed by Water injection was implemented to provide necessary pressure support and improve overall reservoir sweep.
Since injection is being undertaken for a long period of time, drainage radius of water injectors is estimated through streamlines and accordingly the reservoir is divided into different regions based on the injection radius. Thereafter, historical movement of reservoir fluids in each region is analyzed for a period of 60 years to understand the following, Identify the position of leading edge of water and its associated flood-front with respect to each zone & region.Capture oil saturation changes during the last 60 years and identified which regions had minimal changes in oil saturation to accelerate implantation of new infill wells to maximize recovery.Locate where is the remaining oil in the reservoir and identified on what is it causing presence of remaining oil at any given location.Capture the changes in region-wise pressure by coupling with movement of Injected water.Generate distribution of Voidage replacement ratio and injection efficiency in different regions of the reservoir.
Production Profiling of a Long Dead Well – A Prime Case Study of Operational and Technical Excellence Using Simultaneous Lifting and Logging Services
Authors: Akram Shahbaz , Yousaf Haleem , Nawaz Omar , Ashraf Zaid , Zubair Talha , Tanveer Muhammad Sohaib , Bari Abdul , Ali Hamza , Farooq Muhammad Omer , Molero Nestor , Khan Rao Shafin Ali , Naveed Muhammad Amir 
Published: October 2022

Abstract
Reservoir surveillance and production optimization will remain at the forefront of company strategies in the new post-COVID19 environment. We anticipate that companies will focus more on producing assets and go the route of production enhancement rather than exploration. Accordingly, production logging will remain an important surveillance method in evaluating and strategizing production-optimization schemes pertaining to flow-characterization from reservoir-to-wellbore. This work is culmination of operational and technical excellence that enabled the revival of a loaded-up well through simultaneous lifting-and-logging technique.
Conventionally, wireline is the preferred mode of conveyance for production-logging; however, well must be continuously flowing throughout acquisition timeframe. Kicking-off the well using nitrogen-lift and then bringing in wireline-unit for production-logging in Well A-4 was not feasible as previous attempts confirmed well to load-up in few hours post-offloading. Therefore, success of this project was heavily dependent on initial planning stage, which accounted for all available data including production-history, well-events, intervention-details, fluid analysis and well load-up behavior. Next, a multi-domain approach was adopted while bringing-out each domain from its silos and strategize collectively to simultaneously kickoff the well with nitrogen and acquire real-time downhole production-logging data through smart-coiled-tubing (CT). This was first implementation of concurrent lifting and logging operation in Pakistan.
By deploying the approach mentioned above through smart CT (using optical-telemetry-link inside the CT-string coupled with downhole-assembly), synchronized lifting-and-logging operation was carried-out successfully. Well was observed to swiftly go back to load-up conditions post-kickoff; however, continuous well dynamics monitoring downhole enabled us to log perforated interval across multiple time domains. Well was activated through CT nitrogen-injection but depicted continuous loading tendency, which was captured downhole in form of flow-transients. Real-time job optimization ensured vigilant monitoring and selection of right-time to acquire meaningful zonal-contribution data for evaluation and diagnostic solutions. Finally, operational excellence was complemented through technical data analysis and interpretation, integrating passes data with transients and stationary measurements. Ultimately, acquired data analyzed using an integrated lens involving fluid velocities, downhole density, temperature, and water hold up data. Consequently, enabling us to decipher gas and water-entries on a zonal-basis across perforated sandstone reservoir.
An Integrated Solution for Reservoir Model Initialization with Areal and Vertical Composition Variation in the Presence of Tilted Contacts
Authors: Ghorayeb Kassem , Tahir Sofiane , Su Shi , El-Droubi Nour , Assaf Georges , Ramatullayev Samat , Kada Kloucha Chakib , Mustapha Hussein 
Published: October 2022

Abstract
Capturing fluid composition variation and distribution in the reservoir is an essential first step for reservoir modeling. Vertical fluid composition variation is commonly considered. However, fluid samples taken from wells in different areas of a reservoir can highlight significant areal variation in the composition to be modeled. Fluid contacts may be tilted, and despite many studies on the subject, the setup is not straightforward. The combination of all three makes the initialization challenging and time consuming.
In this paper we describe an automated workflow that integrates fluid sample data and petrophysical data to generate an initial fluid composition distribution that captures vertical and areal composition variations and accurately computes the initial fluid distribution to represent tilted contact configurations and their associated transition zones.
Fluid sample data such as composition, pressure, temperature, and sampling depth are provided to an engine that computes composition variation with depth for each sample based on the equation of state (EOS) that characterizes the fluid behavior of the reservoir. The generated composition variation with depth for each sample is spatially distributed at their associated wells and is used to compute the areal composition distribution between the wells in the reservoir. This results in a tridimensional distribution of each fluid component representing the fluid model that captures both vertical and areal composition variations.
In parallel, saturation height functions and hysteresis models are used to automatically generate drainage capillary pressure data and associated imbibition and scanning curves used to capture the drainage and imbibition processes responsible for the paleo and current water saturation distribution in the reservoir.
The fully automated reservoir initialization process accounts for all available pressure-volume-temperature (PVT) samples. The solution is portable, significantly faster, and accurately captures complex reservoir geology and reservoir history. We present field examples of the proposed approach and illustrate its flexibility and associated comprehensiveness and efficiency.
The complete automation of complex initialization methods considering areal and vertical composition variation, combined with tilted contacts modeling, is helping to resolve significant challenges faced across the industry.
Commingled Well Test Analysis (CWTA) and its Application to Assess Health of Multiphase Flow Meters (MPFM) for Deep Water Conventional Assets
Authors: Patra Susobhan , Kedia Kushal , Gollu Divakar , Gantt Justin , Long Ted 
Published: October 2022

Abstract
Historically well production flow surveillance has been attracting attention from reservoir engineers. The accurate estimation of individual well contribution, Has profound impact on reservoir management. Often production allocation suffers from multiple issues such as quality of available production data and production rate estimation in case of inaccurate and uneconomical measurements. These issues can be mitigated if the well has accurate, calibrated Multiphase Flow Meters (MPFMs) and Virtual Flow Meters (VFMs). Reliability of digital meters is primarily dependent on regular well testing to keep the model updated and tuned to latest reservoir characteristics.
As an industry wide common practice, well tests are performed in a timely manner to ensure to allocate production accurately to each well. But performing solo well tests for subsea wells is not trivial as it may seem. Differed production due to downtime associated with flowing subsea wells to a test separator and inability of mature wells to flow to the test separator result in additional challenges. Under such situations, commingled well tests are performed to estimate well rates. Individual well rates can be estimated using test by difference (TBD) method. The apparent simplicity of the TBD method often results in incorrect estimation of allocation rates as the test conditions and production conditions differs significantly. As a result, the credibility of the forecast and the ability to optimize production are compromised.
In this paper a novel application called Commingled Well Test Analysis (CWTA) is reviewed which addresses these aforementioned issues. This integrated application comprises of data loading interface, data visualization interface, core optimization engine and an interactive user interface. To demonstrate the capability, three wells from a deep water conventional wells are analyzed using commingled well tests and well performance parameters (PI, WCUT and GOR) are obtained. Based on the tuned parameters, well rates are predicted and compared against rates obtained from sales meter and MPFM meters. As per the comparison, well allocation rates are validated and health of MPFM meters are assessed. As an additional benefit, proper designing of commingled well tests enable in 25-30% time savings of well testing.
A New Strategy to Minimize the Surfactant Adsorption on Saudi Carbonate
Authors: Kalam Shams , Abu-Khamsin Sidqi A. , Kamal Muhammad Shahzad , Patil Shirish , Hussain Syed Muhammad Shakil , Al Shalabi Emad W. , Hassan Anas Mohammed 
Published: October 2022

Abstract
Surfactants play a vital role in chemical enhanced oil recovery (cEOR) to improve oil production by lowering the oil-water interfacial tension and/or altering the rock wettability. However, surfactant adsorption has been a great challenge. The quantity of surfactant loss by adsorption on a rock directly influences a cEOR project’s economics. Therefore, surfactant adsorption minimization is an important area of interest, which is investigated in this paper. Saudi carbonate rock (outcrop) was tested with a novel in-house synthesized cationic Gemini surfactant to quantify surfactant adsorption. This novel surfactant is compatible with high salinity and high-temperature environment. Rock characterization was performed first using XRD and SEM analyses, while the point of zero charge of Saudi carbonate was found using the pH drift method. Static adsorption tests were conducted using powdered rock sample and run for 24 hours to achieve the equilibration time. The material balance method was used to determine surfactant adsorption. High-performance liquid chromatography along with an evaporative light scattering detector was utilized to quantify the remaining surfactant concentration post-adsorption. Adsorption isotherm modeling was also performed to investigate the adsorption mechanism.
Rock characterization results showed that Saudi carbonate contains mainly dolomite along with some impurities like quartz and clay minerals. The point of zero charge of Saudi carbonate determined using the pH drift method was around 10. The static adsorption tests were conducted on both pure and Saudi dolomites to investigate the influence of impurities. It was found that the presence of quartz and clay particles significantly impacts the degree of surfactant adsorption on Saudi carbonates. A high adsorption of the novel Gemini surfactant used was obtained on Saudi carbonate (8.2 mg/g-rock). A powerful chelating agent made from natural, biodegradable, and renewable material was added to the surfactant solution to check its impact. The surfactant adsorption was significantly decreased using low pH chelating agent (5.8 mg/g-rock). It is proposed that low pH chelating agent renders the overall rock surface more positive and results in electrostatic repulsion between like charges of rock and surfactant. Therefore, the addition of a small quantity of the investigated chelating agent to the surfactant solution helps in reducing the cationic Gemini surfactant adsorption on Saudi carbonate. This study reports a novel strategy to minimize surfactant adsorption on Saudi carbonate through the use of an environmentally friendly and low-cost chelating agent, which will help in designing future chemical EOR projects.
A Polymer Flood Pilot with Autonomous Outflow Control Device Technology and Resilient Cost Management from South Sultanate of Oman
Authors: Al Harrasi Ameera , Badi Salim , Urdaneta Gerardo , Ramli Mohammed , Kindi Said , Sinani Yousuf , Harthy Khalfan 
Published: October 2022

Abstract
This paper summarizes the integrated technical learnings from the successful implementation of a polymer flood pattern and the benefits of installing Autonomous Outflow Control Device Technology (AOCD) in new long horizontal polymer injector well. It shows the result of extending this technology to unlock a pragmatic full field development, and highlight the associated benefits from a project’s perspective, leading towards huge savings and flexible operating conditions.
The polymer flood pattern consists of 3 Horizontal Polymer injectors placed in between and below 4 oil producers. The middle polymer injector was completed with Fiber optic along the well trajectory to monitor injection conformance. AOCD was deployed in the same well as part of the well completion to control and limit the flow of injected fluids into high permeable zones and improve injection conformance. The other two injectors were monitored by running Memory production Logging Tool. Following the clear observations of good conformance in AOCD well and good production gain in oil producing wells, the polymer pilot project with AOCD technology has been concluded as successful.
The Polymer flood started with a pattern in a smaller selected part of the field. Multiple surveillance techniques were implemented to ensure continuous monitoring of this. Chemical tracer sampling was done in all injectors. Memory production Logging Tool were run in 2 injectors. The AOCD technology in the middle injector showed good result where multiple Distributed Temperature Sensor surveys confirmed a good conformance and uniform sweeping in both water and polymer phases. Nearby producers showed good oil gain after injection and that supported the good sweep efficiency from implementing the AOCD technology. Also bypass valves were installed as part of this technology to enable stimulation by bullheading instead of using coiled tubing unit (CTU) which is very expensive (saving more than 150k $ per well).
The results from this pilot were very positive, with good oil gains of approximately 23 m3/day from 4 oil producers. It had been concluded that the application of the technology is successful and planned to be deployed as a baseline in all future horizontal polymer injector wells drilled for polymer fields. This paper discusses the observation of this pilot and the benefits pending the success of the AOCD Technology.
The authors have summarized the results from the polymer Pilot and presented it as a practice worth replication in a similar fields environment, due its many benefits in optimizing field development. AOCD Technology is recommended to be installed in all future polymer injectors in our field. It will be a game changer in all field to reduce the cost of stimulation and PLT, enable good sweep efficiency and support to have a continues monitoring for injectors performance.
First-Contact Miscibility Development in a High-Temperature, Ultra-Sour Reservoir Fluid System Offshore Abu Dhabi
Authors: Mogensen Kristian , Goryachev Sergey 
Published: October 2022

Abstract
First-contact miscibility (FCM) occurs when an original injection gas is miscible with a reservoir oil regardless of the mixing ratio. As a consequence, the displacement will remain single-phase and the microscopic displacement efficiency will be 100%. For the vast majority of field applications, FCM requires a pressure, which is prohibitively high. Some notable exceptions include ultra-sour fluids, such as the fluid system encountered in this reservoir, offshore Abu Dhabi. The exceptionally favorable miscibility conditions may help unlock further value from this challenging, ultra-sour, high-temperature, offshore field.
The swelling experiment provides a key source of information for inferring the FCM pressure. The swelling pressure curve exhibits a maximum versus the volume of injected gas and this maximum pressure is the FCM pressure. Typically, most lab experiments are terminated once the transition point from a bubble-point system to a dew-point system is observed, but for this application, much larger gas volumes were added to the system to reduce uncertainty on the inflection point. We performed equation of state (EOS) predictions to guide the experimental design in terms of the selection of gas additions. We then used the EOS formulation to conduct numerical simulations to compare the efficiency of a first-contact miscible displacement against a multi-contact miscible displacement, which can take place at lower pressures.
With numerical simulation, we show that a first-contact miscible displacement yields higher recovery compared to a multi-contact miscible displacement. We attribute this difference to the development of the compositional transition zone observed during multi-contact miscible displacement which gives rise to a gas-oil interfacial tension and a bending of the gas-oil relative permeability curves for that zone. The impact of IFT on relative permeability would depend on model parameters in the simulator. The gas utilization factor, however, reaches its minimum if gas re-injection is delayed by a couple of years, as a result of the impact of pressure on formation volume factor of reservoir oil and injection gas, respectively.
An Algorithm for Calculating Incremental Production in an Integrated Asset Model
Authors: Cunningham Peter Richard Paul , Yapp Su Huan , Leegte Hendrik Kornelis Willem , Taher Daryan Salah 
Published: October 2022

AbstractBrunei Shell Petroleum (BSP) needs to evaluate project economics on 100+ further development projects for its existing, very complex production system. BSP uses a fast network-solver integrated asset model (IAM) of the entire system (900+ wells) to evaluate the effects of facility and pipeline constraints. In order to avoid time-consuming and error-prone spreadsheet-based post-processing, it was decided to extend the IAM software to include the calculation of the incremental sales profiles required for proper project economics.There were three steps in constructing the project incremental sales calculations. The first step was calculation of physical sales profiles i.e. flows to the various sales points (export, domestic power generations) after removal of fuel and flare. The second step was defining a suitable sequence of forecasts, each adding a tranche of projects to the previous forecast. The difference in sales between a forecast and its predecessor is then the incremental sales profile for the tranche of projects new to the forecast. The final step (required because having one forecast per project would have given excessively long calculation times) is to share out the incremental sales profile amongst all the projects in the tranche. This final step required many attempts before a suitable algorithm was found.The incremental sales profile rates were initially shared out in proportion to well-head rates. However, this gave some anomalous results. If a project required a major shut-down, then the resultant large negative rates could be assigned to a small project already in production. Consequently, one project could have an incremental sales ultimate recovery (UR) much lower than its well-head UR, while another project within the same tranche had nearly equal incremental sales and well-head URs. This problem is avoided if, instead of sharing out incremental sales rates in proportion to well-head rates, incremental sales cumulatives are shared out in proportion to well-head cumulatives. This algorithm has now been successfully in use for more than a year within BSP and other operators.This algorithm makes it possible to calculate incremental sales profiles in a systematic and automatic way, without the need for any manual adjustments. This is one of the key steps (together with a fast network-solver) in making it possible for a shared integrated asset model to be used as a general-purpose forecasting system for a wide range of business processes, such as business planning, development planning, reserves, and operational planning.