bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Evolution of Green Completion in BP Khazzan Field
Authors: Al Harrasi Sultan , Jayawickramarajah Naren , Al Shidhani Taimur , White Daniel , Najwani Mohamed 
Published: December 2021

Abstract
Well Testing is the single largest contributor of carbon emissions during well operations and the industry's aspiration to reduce carbon emissions inspired the bp Oman team to identify innovative ways to reduce emissions from activities in the Khazzan field.
Khazzan is characterized by tight reservoirs which requires hydraulic fracturing to release gas from the rock. After fracturing, the wells are tested/cleaned-up by flowing the well fluids and flaring the produced gas and condensate to the atmosphere. The testing removes contaminants – proppant, frac fluid, hydrogen sulphide – that could damage the downstream Central Processing Facility (CPF). ‘Green Completion’ was one of the opportunities that was identified by the bp's Oman team to remove these contaminants in an environmentally friendly manner.
A Green Completion is a zero flaring concept – hydrocarbons produced during well test operations are ‘cleaned’ and then routed to processing facilities for export rather than being flared. This concept has been successfully utilized in bp's onshore US operations for over a decade. The team leveraged the experience from the USA, applying this technology to suit the conditions in Oman, but it was not simple nor straight forward. In the last two years, this process has been modified and reinvented for the operations in Oman as the company seeks to strategically reduce its global carbon footprint.
In first half of 2018, the bp Wells team initiated a pilot project with the objective of developing Green Completion capability in the Khazzan field. This was the start of the journey to demonstrate bp's commitment to reducing greenhouse gas (CHG) emissions in a sustainable manner. Furthermore, bp's collaborative cross-functional aptitude allowed for expanding the use of Green Completions into the Ghazeer development, which enabled zero-emission well testing of newly drilled wells even before commissioning of the new pipeline infrastructure. Through this initiative, the region has reduced emissions and generated cash by selling the recovered hydrocarbons instead of flaring into the atmosphere during well testing operations. Since Q1 2019, the total reduction of CO2 emissions exceeded 240,000 tonnes of CO2 equivalent, which equates to taking circa 52,000 vehicles off the road for one year.
The implementation of this environmentally friendly operation also adhered to strict safety standards. The rigid bp safety process guidelines ensured that all challenges and optimization opportunities were fulfilled in a safe manner.
The purpose of this paper is to detail how the team pushed the technical envelope to introduce this technology and share the journey entailing extensive cross-disciplinary cooperation amongst operations, subsurface and wells teams to fulfill the zero emissions objective.
The Use of 5G Technologies in the Digital Transformation of the Oil/Gas Industry
Authors: Al-Jadir Sadik Jadir 
Published: December 2021

Abstract
Many oil & gas companies embarked on their Digital Transformation (DX) journeys with rapid adoption of emerging digital technologies. Successful digital transformation initiatives are necessary for Oil/Gas Companies to improve efficiencies, streamline their operations and meet pressing challenges for cost reduction, increased efficiency, and improved safety.
Oil & Gas fields and processing facilities require robust and reliable telecommunication infrastructure to support the application of much needed digital technologies. The availability of high-speed connectivity has been a challenge for many Oil/Gas companies operating in remote or hazardous locations. The latest Fifth Generation cellular technology (5 G) addresses such essential Oil/Gas requirements as increased speeds/bandwidths, very low network latencies, ultra-reliable communications, and the capacity to handle large number of users.
5G is designed around following technologies: Small (micro) cells requiring less power,Higher frequencies offering bigger data handling capacities,Cloud and Edge Computing for low network latencies and added security.
These 5G design features will enable numerous Oil/Gas applications such as Industrial Robots/Drones, Virtual/Augmented Reality, Video Surveillance with Artificial Intelligence (AI) features (Face Recognition, Object Recognition & intelligent Image processing), Remote Asset Management, Industrial IoT communication between Sensors, Gateways and Device Controllers, Pipeline Leak Detection Systems, Telemetry and SCADA. 5G is therefore poised to be a key enabler in Digital Transformation.
The UAE has an advanced telecom infrastructure that offers customers high speed fibre optic connectivity. UAE telecom operators have also been quick to deploy 5G in main cities. Etisalat for example is running a 5G pilot on Das Island with ADNOC Offshore and a major Network Supplier to test potential use cases of the technology in the O&G industry.
The push for 5G in O&G will benefit from cooperation between the O&G industry, the telecom operators and technology providers. The role of Governments and the Telecom Regulators can further accelerate adoption through allocation of frequency spectrum to enable 5G Private Network model of deployment. The private network model is crucial for the Oil & Gas industry in view of the special requirements, nature and remoteness of oil and gas installations.
New Intelligent Push-the-Bit Rotary Steerable System Helped Reducing Well Time and Maximized Directional Drilling Performance, Abu Dhabi, UAE
Authors: Al Arfi Saif , AlSowaidi Fatima , Ruiz Fernando , Hamdy Ibrahim , Tobji Yousef , Nunez Ygnacio , Ullah Ikram , Abd El-Hafez Hany , Mikhaylov Alexander , Diab Emad 
Published: December 2021

Abstract
To meet the current oil and gas market challenges, there is an industry need to optimize cost by safely drilling longer horizontal wells to maximize well productivity. Drilling challenges include the highly deviated trajectory that starts from the surface sections and wellhead, the high DogLeg Sevirity (DLS) profile with collision risks, and the thin complex geological structures, especially in new unconventional fields where numerous geological and geomechanical uncertainties are present. To mitigate for those challenges, reviewing the existing drilling techniques and technologies is necessary. To compete in the current Hi-Tech and Automation era, the main challenges for directional drilling service providers are to reduce well time, place wells accurately, and improve reliability, reducing repair and maintenance costs and helping the customer reduce time and costs for the overall project.
Offset wells analysis and risk assessments allowed identifying the main challenges and problems during directional drilling phases, which were highlighted and summarized. As a proposed solution, the new generation of intelligent fully rotating high dogleg push-the-bit rotary steerable system has been implemented in the UAE onshore oil and gas fields to improve the directional drilling control and the performance. This implementation reduced the Non-Productive time (NPT) related to the human errors as the fully automation capabilities were being utilized. The new rotary steerable system has the highest mechanical specs in the market including self-diagnosis and self-prognosis through digital electronics and sophisticated algorithms that monitor equipment health in real-time and allow for managing the tool remotely.
As a result, the new intelligent RSS was implemented in all possible complex wellbore conditions, such as wells with high DLS profile, drilling vertical, curve, and lateral sections in a single trip with high mud weight and high solid contents. Automation cruise control gave the opportunity to eliminate any well profile issues and maintain the aggressive drilling parameters. Using the Precise Near-bit Inclination and Azimuth and the At-Bit Gamma real-time data and high-frequency tool face measurements in the landing intervals where required for precise positional control to enable entering the reservoir in the correct location and with the correct attitude helping the customer's Geology and Geophysics department to place wells accurately while maintaining a high on bottom ROP.
Management of Uncertainty in Reservoir Modelling for an Onshore Carbonate Reservoir in the Middle East: A Case Study
Authors: Kamp Arjan Matheus , Alhosani Amna Khalid , Kim David Dong II , Verdière Sophie , Mohamed Hamdy Helmy 
Published: December 2021

AbstractAs part of a reservoir modelling study for an onshore oil field in the Middle East, our study implemented a workflow with the objective to evaluate the impact of uncertainty on the long-term development scenario. The presence of several geological uncertainties characterized the field: many faults with uncertainty in juxtaposition and conductivity, lateral distribution of permeability in high permeability layers, and uncertainty on the rock typing. A deterministic geological model was available. There were also many dynamic uncertainties.The workflow started with an identification of uncertain variables, both from the static and the dynamic point of view, through an integrated team approach supported by a previous reservoir synthesis (Major Field Review). Subsequently, a screening analysis allowed identifying the relative impact of uncertain variables. After selecting the uncertainties with the largest impact on recovery, use of an experimental design methodology with a space-filling design resulted in alternative history matches. Statistical analysis of forecasts yielded probability density functions and low and high estimates of ultimate recovery.Forty-five uncertain variables, including both static and dynamic uncertainties, characterized the production profiles. Screening allowed reducing these to 11 main uncertain variables. A Wootton, Sergent, Phan-Tan-Luu (WSP) space-filling design yielded 162 simulation runs. Only five out of these corresponded to acceptable history matches. This number being statistically insignificant, a reexamination of the uncertainty ranges followed by a narrowing, allowed obtaining 45 history matches (out of 198 runs). The obtained spread in the cumulative oil production was narrow, with a slightly skewed distribution around the base case (closer to P90 than to P10).The study resulted in an estimation of final uncertainty in reserves that is smaller than the typical uncertainty found in post-mortem analysis of oil field development projects. Other reservoir studies in the company and in literature, employing a similar workflow, yielded outcomes with a similar bias. To tackle this issue, as a way forward we suggest history matching of multiple geological scenarios, either with multiple deterministic cases (min, base, max) or with an ensemble history matching loop including structural model generation, in-filling, and dynamic parameter uncertainty.
New-Age Kolmogorov Full-Function Neural Network KNN Offers High-Fidelity Reservoir Predictions via Estimation of Core, Well Log, Map and Seismic Properties
Authors: Priezzhev Ivan , Danko Dmitry , Strecker Uwe 
Published: December 2021

Abstract
Instead of relying on analytical functions to approximate property relationships, this innovative hybrid neural network technique offers highly adaptive, full-function (!) predictions that can be applied to different subsurface data types ranging from (1.) core-to-log prediction (permeability), (2.) multivariate property maps (oil-saturated thickness maps), and, (3.) petrophysical properties from 3D seismic data (i.e., hydrocarbon pore volume, instantaneous velocity). For each scenario a separate example is shown. In case study 1, core measurements are used as the target array and well log data serve training. To analyze the uncertainty of predicted estimates, a second oilfield case study applies 100 iterations of log data from 350 wells to obtain P10-P50-P90 probabilities by randomly removing 40% (140 wells) for validation purposes. In a third case study elastic logs and a low-frequency model are used to predict seismic properties. KNN generates a high level of freedom operator with only one (or more) hidden layer(s). Iterative parameterization precludes that high correlation coefficients arise from overtraining. Because the key advantage of the Kolmogorov neural network (KNN) is to permit non-linear, full-function approximations of reservoir properties, the KNN approach provides a higher-fidelity solution in comparison to other linear or non-linear neural net regressions. KNN offers a fast-track alternative to classic reservoir property predictions from model-based seismic inversions by combining (a) Kolmogorov's Superposition Theorem and (b) principles of genetic inversion (Darwin's "Survival of the fittest") together with Tikhonov regularization and gradient theory. In practice, this is accomplished by minimizing an objective function on multiple and simultaneous outputs from full-function (via look-up table) Kolmogorov neural network runs. All case studies produce high correlations between actual and predicted properties when compared to other stochastic or deterministic inversions. For instance, in the log to seismic prediction better (simulated) resolution of neural network results can be discerned compared to traditional inversion results. Moreover, all blind tests match the overall shape of prominent log curve deflections with a higher degree of fidelity than from inversion. An important fringe benefit of KNN application is the observed increase in seismic resolution that by comparison falls between the seismic resolution of a model-based inversion and the simulated resolution from seismic stochastic inversion.
Transforming Water Injection Process With Real Time Automation
Authors: Zakwan Mohd Sahak Muhammad , Castillano Eugene , Amansyah Tuan Mat Tengku , Maung Myo Thant Maung 
Published: December 2021

Abstract
For mature fields, water injection is one of the widely deployed techniques to ensure continuous oil recovery from the reservoir by maintaining the reservoir pressure, oil rim and pushing the oil from injection to production wells. Thus, it is critical to ensure a continuous and reliable operation of water injection to have consistent and sustainable rate. This paper demonstrates the new approach, utilizing automation and digital technology providing operational improvement and reduction in unplanned production deferment (UPD). One of the methods to effectively manage the water injection operation is via automation of injection process, especially since most of the water injection facilities still rely heavily on manual operation. First, a discussion on typical water injection technique is discussed. Challenges and sub-optimal operation of water injection processes within the company and industry are analysed. Then, the designing of a fully automated water injection system, such as equipment availability and constraints in matching and responding to well injection requirement are demonstrated. While an immediate adoption of process automation to mature assets may be faced with challenges such as system readiness, hardware availability, capital investment and mindset change, a step-by-step approach such as guided operation and semi-auto operation is explored as preparation prior to a full automation roll-out. With the shift from manual operation reliance to automation, the response time to process changes is improved leading to reduction in near-miss and trip cases, and minimum unplanned deferment.
A Holistic Approach to Simulate the Impact of H2S on Production and Injection Surface Facilities Using an Integrated Asset Model as a Digital Twin
Authors: Altaf Basit , Allouti AbdelKader , Kedia Rachit , Abdullayev Azer , Bedewi Mahmoud 
Published: December 2021

Abstract
The presence of hydrogen sulphide (H2S) in produced reservoir fluids mandates precautions in the design and operation of the surface facilities. The toxicity and corrosive nature of H2S, and the need to prevent both plugging of reservoir formations and increasing the sulphur content of the produced oil dictates the criticality of forecasting and monitoring the volumes and concentrations of H2S flowing through the whole asset. Ensuring the concentration is within acceptable operational limits is critical to safeguard the overall asset and the integrity of the surface pipeline network.
The objective of this study was to utilize a history matched Digital Twin Integrated Asset Model (IAM) to predict the volumes and concentrations of H2S in a field located offshore Abu Dhabi by modeling the multi-stage separation, H2S removal, and re-injection facilities for gas injection and gas lifts. The field consists of multiple stacked carbonate reservoirs sharing the same surface facilities. The proposed modelling of H2S removal strategy involved a series of steps beginning with the sweetening of the produced associated gas for fuel gas requirements and mixing the extracted H2S volumes with the gas injection and gas lift streams.
The sweetening process effectively mitigated any potential asset integrity issues arising due to corrosion of the power generation system and other surface facility assets. The stripped H2S gas, re-combined with the remaining produced gas, was used for gas-lifts and reinjected into the lower reservoirs for pressure maintenance and enhanced oil recovery (EOR). A next-generation surface-subsurface coupled simulator was utilized for the modeling of this field including the full asset surface pipeline network, the H2S removal plant, bypass lines and re-injection facilities for gas injection and gas-lifts.
The Digital Twin IAM approach provided a robust method for tracking and predicting the concentration and volume of H2S in the produced gas over a period of 50 years. The simulation allowed tracking the H2S from its initial location in the reservoirs, into the production wells, then through the pipelines, all the way to the surface facilities where the sweetening of the produced is handled.
Moreover, the use of the Digital Twin allowed the verification of the disposal plan of the extracted H2S, showing that mixing it with the re-injection gas stream is a feasible option. Recommendations based on the model were provided to the production and facilities team, leading to a robust long-term field development plan that ensures asset integrity.
Downhole Steam Generation for Green Heavy Oil Recovery
Authors: Al-Mashrafi Abdulsallam , Fani Mahmood , Asfand Faisal , Amani Mahmood , Assadi Mohsen , Mosavat Nader 
Published: December 2021

Abstract
The ultimate target of heavy oil recovery is to enhance oil mobility by transferring steam's thermal energy to the oil phase, incrementing its temperature, and reducing heavy oil's viscosity. While the various types of steam floods such as Cyclic Steam Injection (CSI) and Steam-Assisted Gravity Drainage (SAGD) are widely used worldwide, they have certain limitations that need further improvements. Notably, in surface steam generation systems, downhole steam quality is around 70% which means that 30% of latent heat is lost while steam travels from the surface to the pre-determined downhole location.
Downhole steam generation (DHSG) can be a viable alternative for the surface steam injection in which steam will be generated downhole instead of on the surface. The asserted method presents significant benefits such as preventing steam quality loss, decreasing the environmental effects, and enhancing the heavy oil recovery by co-injecting the flue gas products such as CO2, and consequently, the economic outcomes will be increased.
In this research, a comprehensive techno-economic case study has been conducted on a heavy oil reservoir to evaluate the economic and technical advantages of DHSG compared to surface steam generation. Various technical expenses and revenues such as investment costs, operating costs, royalties, and taxes have been considered in a simulation model in MATLAB. This DHSG feasibility assessment has been performed using data of a heavy oil reserve currently under steam flood. Results showed that DHSG could increase up to 50% economic and technical interest than conventional steam injection projects. One of the outstanding benefits of DHSG is the reduction of heat loss. Since steam is produced in-situ, either downhole or in the reservoir, no waste of heat occurs. Typically, most heat losses happen on surface lines and wellbore during steam injection from the surface, which accounts for approximately 32%. Thus, this issue is excluded using the DHSG method.
The results of the recent effort fit well into the current industry's requirements. DHSG can (1) increase the rate of heavy oil production, (2) decrease the extra expenses, and (3) dwindle the environmental side effects of CO2 emission of surface steam generation. Compared with conventional thermal methods, in DHSG, the steam to oil ratio remains constant with depth change while the desired steam quality can be achieved at any location. The asserted benefits can ultimately optimize the steam injection with a significant reduction in UTC, hence, improved profitability.
New Automated MPD Riser System Allowed an Operator to Reduce Manual Working Hours in the Moonpool by 85% and Installation Time by 60%
Authors: Hammad Mohamed , Hernandez Julian , Hernandez Angel , Mammadli Karim , Soltanov Rustam 
Published: December 2021

Abstract
In pursuit of efficiency and well construction cost optimization, the oil and gas industry demand continuous improvements and constant evolution of the service providers’ hardware and software, including Managed Pressure Drilling (MPD) technologies. Recently deployed in the Caspian Sea, the new automated riser system enabled an operator to reduce manual working hours in the moonpool by 85% and installation time by 59%. The improved efficiencies represent an additional saving of 19.5 hours rig time compared to the previous generation MPD below tension ring (BTR) systems, which are currently used on more than 19 floaters around the world. Lessons learned over the past 10 years led to the design and release of the new automated technology that resulted in this time and cost savings. The operator currently targets deep reservoirs that cannot be drilled using conventional drilling techniques because of very narrow operating windows. This paper discusses the service delivery process, engineering, and operational challenges that culminated in the flawlessly executed first deployment of the automated MPD riser system.