bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

As 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

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

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

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

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

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.
Evaluation of In-Situ Generation of Nitrogen Gas for Foam Applications using Two Salt Solutions
Authors: AlYousef Zuhair , Altaq Ali , Almajid Muhammad , Almaskeen Lyla
Published: December 2021

Foams are used in many oil and gas applications including conformance control during EOR processes, fracturing, and acidizing operations. Foams are defined as dispersions of gas bubbles into a continuous liquid phase. Typically, foams are generated when an injection gas such as nitrogen, carbon dioxide, or flue gas is mixed with an injection fluid containing a foaming agent. This method, however, requires a gas source to be present for foams to be generated. The objective of this study is to evaluate a new alternative technique for foam generation using two salt solutions. Nitrogen gas is generated as a result of the reaction of the two salt solutions at specific conditions. This generated nitrogen gas is then used for foam generation in porous media.

The foam generated using the two salt solutions is tested in a microfluidic device (rock-on-a-chip) to study the gas mobility reduction in porous media. A Foam rheometer apparatus is also used to measure foam apparent viscosity when the two salt solutions are mixed with a foaming agent. The results are compared with those obtained when nitrogen gas is injected into the system independently in the absence of the two salt solutions.

Results reveal that the amount of added salts significantly impact the produced nitrogen volume. Additionally, the test conditions especially the temperature, significantly impacts the reaction rate. The rate of nitrogen gas generation is directly proportional to the temperature when tested at 25-80°C. In addition, experiments demonstrate that the foams generated using the two salt solutions reaction have almost identical characteristics as those produced when nitrogen gas is injected into the foam rheometer apparatus independently. Both methods generate the same foams with comparable foam apparent viscosity. In the microfluidic system, the foam obtained using the two salt solutions in the presence of a foaming agent shows excellent resistance to gas flow and subsequently exhibit large gas mobility reduction.

This experimental study, for the first time, confirms the ability of the two salt solutions reaction to generate nitrogen gas spontaneously upon contact under certain conditions. The generated gas is used to generate foams in the presence of a foaming agent. This newly proposed technique of foam generation could significantly impact many oil and gas operations including conformance control during EOR processes, fracturing, and acid stimulation operations.
Unlocking Ensemble History Matching Potential with Parallelism and Careful Data Management
Authors: Fighera Giorgio , Della Rossa Ernesto , Anastasi Patrizia , Aly Mohammed Amr , Diamanti Tiziano
Published: December 2021

Improvements in reservoir simulation computational time thanks to GPU-based simulators and the increasing computational power of modern HPC systems, are paving the way for a massive employment of Ensemble History Matching (EHM) techniques which are intrinsically parallel. Here we present the results of a comparative study between a newly developed EHM tool that aims at leveraging the GPU parallelism, and a commercial third-party EHM software as a benchmark. Both are tested on a real case.

The reservoir chosen for the comparison has a production history of 3 years with 15 wells between oil producers, and water and gas injectors. The EHM algorithm used is the Ensemble Smoother with Multiple Data Assimilations (ESMDA) and both tools have access to the same computational resources. The EHM problem was stated in the same way for both tools. The objective function considers well oil productions, water cuts, bottom-hole pressures, and gas-oil-ratios. Porosity and horizontal permeability are used as 3D grid parameters in the update algorithm, along with nine scalar parameters for anisotropy ratios, Corey exponents, and fault transmissibility multipliers.

Both the presented tool and the benchmark obtained a satisfactory history match quality. The benchmark tool took around 11.2 hours to complete, while the proposed tool took only 1.5 hours. The two tools performed similar updates on the scalar parameters with only minor discrepancies. Updates on the 3D grid properties instead show significant local differences. The updated ensemble for the benchmark reached extreme values for porosity and permeability which are also distributed in a heterogeneous way. These distributions are quite unlikely in some model regions given the initial geological characterization of the reservoir. The updated ensemble for the presented tool did not reach extreme values in neither porosity nor permeability. The resulting property distributions are not so far off from the ones of the initial ensemble, therefore we can conclude that we were able to successfully update the ensemble while persevering the geological characterization of the reservoir. Analysis suggests that this discrepancy is due to the different way by which our EHM code consider inactive cells in the grid update calculations compared to the benchmark highlighting the fact that statistics including inactive cells should be carefully managed to correctly preserve the geological distribution represented in the initial ensemble.

The presented EHM tool was developed from scratch to be fully parallel and to leverage on the abundantly available computational resources. Moreover, the ESMDA implementation was tweaked to improve the reservoir update by carefully managing inactive cells. A comparison against a benchmark showed that the proposed EHM tool achieved similar history match quality while improving the computation time and the geological realism of the updated ensemble.
Uncertainty and Sensitivity Analysis on Clastic Systems: Integrated Workflows for Understanding and Managing the Risk, A Case Study in Tuwayil Formation UAE
Authors: Ebeid Mahmud , Parra Humberto , Ghosh Dipankar , Kang Jeonggil , Seo Kwangwon
Published: December 2021

This study has been done on Late Cretaceous tight clastic reservoir located south west of Abu Dhabi city with the border with Saudi Arabia. The field was discovered in the 1960s and a few wells were drilled subsequently. The Tuwyail clastic reservoir is characterized as tight with average permeability below 1 mD. The trap is identified as structural trap as north south anticline with gentle dip in both sides. Total of six wells were drilled targeting Tuwyail reservoir which part is of Wasia group.

However, assessing potential of this accumulation poses a great challenge not only in terms of understanding of the depositional system which still unknown before but also in terms of quality of the legacy data like well data that impact the modeling studies. The aim of this paper is to provide an insight on integrated workflows for assessing the different uncertainties on clastic systems with limited data, focused on the most important sensitivities parameters impacting the oil in place, like reservoir proportions, free water level [FWL] and lateral distributions of the sedimentary elements within the area of interest which playing a big rules in future developing of the field.

Before moving to full field development a full uncertainty and sensitivity analyses were conducted for the Tuwayil reservoir to find the highly uncertain parameters that impacting the future development of the reservoir, in the same time the main challenges is the limited data with low quality as the wells had been drilled in 60s with limited technology at that time and the core data were left in a bad conditions since the filed was left behind.
Contribution of the ALBION Dynamic Analogue in Understanding the Diversity of Fluid Flows in Fractured Carbonate Reservoirs. The Example of the LSBB Instrumented Site
Authors: Charles Danquigny , Gérard Massonnat , Mickaël Barbier , Pierre Bouxin , Lucie Dal Soglio , Jean-Louis Lesueur
Published: December 2021

Carbonate reservoirs exhibit an extreme geological heterogeneity inducing a great diversity of fluids flows. Grasping the plurality of flows and the corresponding geological features require data scarcely available from subsurface hydrocarbons fields and even rarely acquired together on outcrop analogues.

Among the different sites of the ALBION R&D project, the LSBB underground research laboratory provides outstanding access to both fractured limestone and groundwater dynamics through several experimental areas, including a 3.8 km long tunnel, which penetrates the Barremian-Aptian Urgonian formation to a maximum depth of 519 m. This paper gives an overview of the data acquired and the different works carried out on the LSBB site. From this synthesis, it draws lessons on the characterization of outcrop analogues and some insights for the modeling of fractured carbonate reservoirs.

The quantity and diversity of the data acquired on the LSBB site allow: (i) the construction of nested multi-scale geological models, (ii) the comparison of measurements of different physical properties to better characterize the reservoir properties of the fractured rock, (iii) a multi-scale and multi-support approach to heterogeneity.

Defining a common geological framework (facies model, rock type classification, inventory of structural objects, etc.) appears to be an essential step, possibly iterative, for the coupled interpretation of the various acquisitions and the extrapolation of results. Building a common geological model as a framework for interpretation help cross-fertilisation between geoscience domains.

However, despite the huge amount of data, performing relevant and parsimonious rock typing remains a delicate exercise. This reminds us of the great uncertainties that can exist in establishing rules and concepts from limited data sets, such as those classically available for operational studies. Beyond the characterization of the depositional environment, the observations emphasize the importance of understanding the structural and diagenetic history, which leads to different rock types and current reservoir properties, to successfully define such a rock classification. Furthermore, the organization of flow paths within the fractured medium and its evolution over geologic time condition the processes of diagenesis and karstification. Hydrological processes and history must therefore be taken into account in this genetic reconstruction.
Game Changer in Dealing With Hard Scale Using a Slickline Torque Action Debris Breaker
Authors: Koriesh Mahmoud Mohamed , Elwan Mahmoud Atia , Mousa Ali ELbasyouni , El Shiekh Mahmoud Ibrahim , Vazquez Maria Leticia , Ziada Khaled
Published: December 2021

Scale deposition is a major concern in Gulf of Suez Fields, variations in water composition and operating conditions resulted in the deposition of full spectrum of scale depositions in different fields. The common practice in GOS is to prevent scale deposition by periodical scale inhibition treatment. However the field experience showed variation in efficiency of inhibition under different operating conditions which results in some cases in scale deposition. In this case we are obliged to react and do intervention to clean out these wells either with chemical dissolution or coiled tubing clean out which is sometimes becomes costly and stand clueless in front of hard scale. Typically, in offshore operating fields, rig-less solutions is the optimum.

A simple, innovative, and cost effective Torque action debris breaker tool is a new rig-less solution deployed on slick-line unit. The tool can be run at different sizes to allow for optimum scale removal. Activation is achieved via downward jarring action. The TADB tool applies a new operating concept different from milling. The tool consists of a sharp knife with a broach body. The operating mechanism uses the jarring down action in order to apply jackhammer force on the scale accumulation, which allows decreasing the bond between different layers of scale and between the scale and tubing. Another advantage is having the knife rotating after each jar action, which allows this force to be applied on different positions of scale accumulation adding more efficiency.

The tool was first deployed in Egypt in one of the challenging oil wells offshore gulf of suez, which has a historical scale deposition issues "mainly hard deposition of zinc & lead sulfides". several trials were performed to clean out the well historically using coiled tubing operations using barge assist, it took 2 months of operation to achieve partial success & the well was worked over later.

The Torque Action debris breaker was tried against the same scale type and found successful. allowing the well to be drifted with 2.7" compared with 2.25" before the job. The operation cost is by no means comparable to the previous cost of coiled tubing operations.

Following this wells three other wells were intervened using the same tool and showed much better progress of scale clean out in comparison with other slick-line tools & historical coiled tubing performance in these wells.

The implementation of this technology has generally optimized operating cost compared to lengthy and costly CT/WO operation minimizing footprint, equipment, manpower, job duration, and provide a more environmentally friendly solution.
20 Years of Horizontal Multistage Completions: A Summary of Industry Evolution in Unconventional and Conventional Plays
Authors: Casero Alberto
Published: December 2021

In the past two decades, the advent of the Shale Gas Revolution (SGR) was made possible by the visionary idea that hydrocarbons contained in ultra-low permeability source rocks could be extracted using available technology. Usually, these hydrocarbons take geological time to migrate to higher permeability reservoir rocks until the right structural conditions evolve to extract as recoverable resources. However, paradigm shifts in drilling and completion engineering have enabled unlocking resources from these ultra-tight formations.

The innovative idea at the base of this industrial revolution was the combination of horizontal well drilling and hydraulic fracturing, which allowed increasing the surface area available for hydrocarbon flow and overcame the slow and shallow hydrocarbon release from the source rock. This approach can be considered as a bridge between petroleum engineering based on radial diffusivity equation and mining engineering based on physically accessing and extracting the resource. To achieve the high number of hydraulic fractures needed for economical production, different execution techniques evolved and developed in what is known as horizontal multistage fracturing (HMSF) completions.

Although HMSF is indescribably linked to SGR, it was surprisingly applied in tight gas formation and offshore sand control applications more than 30 or 40 years ago. SGR contributed to the fast development of new innovative systems engineered and deployed at scale all over North America land operations and was subsequently exported internationally in conventional, unconventional, land, and offshore applications.

This paper will cover the most common HMSF completion systems types with a primary focus on unconventionals. It will encompass the evolution of these systems over the past several decades. It will also explore the opportunity case for conventional, and high permeability plays through a series of theoretical and real examples.
A Case History for an Integrated Asset Model with Fluid Delumping for a Complex Gas Condensate Field
Authors: Mohamed Mohamed Ibrahim , El-Menoufi Ahmed Mahmoud , Ezz El-Regal Eman Abed , Ali Ahmed Mohamed , Mansour Khaled Mohamed , Negm Mohamed Nagy , Hussein Hatem Mohamed
Published: December 2021

Field development planning of gas condensate fields using numerical simulation has many aspects to consider that may lead to a significant impact on production optimization. An important aspect is to account for the effects of network constraints and process plant operating conditions through an integrated asset model. This model should honor proper representation of the fluid within the reservoir, through the wells and up to the network and facility.

Obaiyed is one of the biggest onshore gas field in Egypt, it is a highly heterogeneous gas condensate field located in the western desert of Egypt with more than 100 wells. Three initial condensate gas ratios are existing based on early PVT samples and production testing. The initial CGR values are as following;160, 115 and 42 STB/MMSCF. With continuous pressure depletion, the produced hydrocarbon composition stream changes, causing a deviation between the design parameters and the operating parameters of the equipment within the process plant, resulting in a decrease in the recovery of liquid condensate. Therefore, the facility engineers demand a dynamic update of a detailed composition stream to optimize the system and achieve greater economic value. The best way to obtain this compositional stream is by using a fully compositional integrated asset model.

Utilizing a fully compositional model in Obaiyed is challenging, computationally expensive, and impractical, especially during the history match of the reservoir numerical model.

In this paper, a case study for Obaiyed field is presented in which we used an alternative integrated asset modeling approach comprising a modified black-oil (MBO) that results in significant timesaving in the full-field reservoir simulation model. We then used a proper de-lumping scheme to convert the modified black oil tables into as many components as required by the surface network and process plant facility. The results of proposed approach are compared with a fully compositional approach for validity check. The results clearly identified the system bottlenecks. The model enables the facility engineers to keep the conditions of the surface facility within the optimized operating envelope throughout the field's lifetime and will be used to propose new locations and optimize the tie-in location of future wells in addition to providing flow assurance indications throughout the field's life and under different network configurations.
Automated Workflow Based on Transient, Multiphase Technology Improves Well Control Planning Efficiency and Reduces Risk
Authors: Anfinsen Bjoern-Tore , Mosti Inge , Szemat-Vielma Waldemar
Published: December 2021

The use of automated workflows for engineering calculations is significantly improving the efficiency of modern well planning systems. Current automated well control solutions are at large limited to single bubble considerations. Transient, multiphase technology has proven to be more accurate and reliable for well control planning, but it has been too complex to automate and integrate into automated engineering systems.

The objective of this work is to improve well control planning efficiency by using an automated workflow that enables integration of transient multiphase technology into modern well-planning systems. The workflow is based around an advanced multiphase engine that covers all relevant physical processes in the wellbore including transient temperature and acceleration. The model has an accurate equations-of-state- (EOS) based pressure-volume-temperature (PVT) model with compositional tracking that, in combination with the transient temperature, can accurately predict the transition from dissolved to free gas - a key parameter in the development of a kick.

The workflow is based on Driller's method and has been automated with a controller network that moves the simulation through the distinct phases of the driller's first circulation without any interaction from the user. High-performance cloud computing ensures the workflow performance.

The drilling industry has focused on risk reductions after the Deepwater Horizon (BSSE 2010) accident. But the well-control risk is still high. In Norway, the reported incidents indicate a flat or increasing trend. Geological uncertainties and inaccurate mud density (static and circulating) have been identified as root causes for the majority of the reported incidents.

Transient multiphase models are reducing well-control risk by accurately modeling downhole variations in fluid pressure as a function of operational mode, fluids, influx type, geometry, water depth, and pressure and temperature conditions. Such models have been regarded as expert tools because of the complexity and numerically demanding simulations.

The automated workflow enables a well control engineer to run accurate multiphase simulations with the same user effort as single bubble kick tolerance tools. In special cases where more sensitivities are required, it is easy to transfer the project to the expert mode - where the automated simulation can be finetuned.
Insights into Oil Recovery Mechanism by Nothing-Alternating-Polymer NAP Concept
Authors: Battashi Muatasam , Farajzadeh Rouhi , Bimani Aisha , Abri Mohammed , Mjeni Rifaat , Karpan Volodimir , Fadili Ali , van Wunnik Johannes
Published: December 2021

This paper discusses the application of polymer injection in a heavy oil reservoir in the South of the Sultanate of Oman containing oil with a viscosity of 300-800cP underlain by a strong bottom-up aquifer. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, a polymer injection pilot started in 2013 with three horizontal injectors, located a few meters above the oil/water contact. Initially a polymer solution with a viscosity of 100 cP was continuously injected at high injection rates. However, it was challenging to sustain the injectivity mainly due to surface facilities, water, and polymer quality issues. This resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). This paper discusses the oil recovery mechanism from the NAP strategy. A 3D model was constructed to match the actual pilot results and capture the observed behavior. The injected polymer squeezes the cones and partly restores the barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative affect of the cones.

It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then is produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.
Calcium Alginate-Based Carbon Composite Adsorbents for Lean Methyldiethanolamine Reclamation: Laboratory to Pilot Scale Testing and Validation
Authors: Kannan Pravin , Priyabrata Pal , Banat Fawzi , Dara Satyadileep , Khan Ibrahim , AlJenaibi Eisa , AlAwlqi Marwan
Published: December 2021

Calcium alginate-based carbon composite (CAC) adsorbents have been proved to effectively remove total organic acid anions as HSS anions, metal ions, and organic degraded products from lean methyldiethanolamine (MDEA solvents) used as solvent in natural gas sweetening unit. During the material developmental phase, the CAC adsorbent was synthesized and utilized to remove various contaminants, including heat stable salts (HSS), organic degraded products, and heavy metal ions from lean MDEA using a lab-scale adsorption setup. Based on the results, a "demo-scale" fixed bed adsorption unit was designed and simulated using adsorption model to predict breakthrough behavior. In the current work, the efficiency of the CAC adsorbent in removing HSS and total organic acid anions were investigated. Analysis of treated samples demonstrated the removal efficiency of the adsorbent under plant scale conditions. Further experiments performed at lab scale indicated the effectiveness of the adsorbent in the removal of bicine from lean MDEA samples. This work provides a framework for future testing and comprehensive process performance evaluation of adsorbents for lean MDEA reclamation in actual plant conditions. A fast, simple, and reliable scale up procedure for fixed bed adsorber developed earlier was validated through this work.
A Paradigm Shift in Monitoring Pipeline Leaks - Combining Sensorless NPW with RTTM
Authors: Inbar Eran , Rowen Eitan , Motil Avi , Elkin Eitan , Tankersley Michael , Troxell Alexander
Published: December 2021

Leak detection solutions in pipelines use several known methods and technologies. However, each method and its underlying technology has their benefits and drawbacks. This article will present and evaluate a hybrid solution that combines two methods based on different physical measurements and quantities to ensure a superior detection probability, short detection time, accurate localization of faults, and minimal false alarm rates. In addition, this solution also features preventive capabilities by pointing out problematic areas in a pipeline that may need more attention.

The article presents a novel approach for pipeline monitoring using a combined solution with the strengths of real-time transient model (RTTM) technology and the power of next-generation fiber sensing geared towards leak detection. On top of acoustic sensing for leaks, it features continuous pipeline integrity monitoring where, using subtle characteristics of propagating negative pressure waves (NPW), pipeline sections signatures are tracked, aiming to detect changes that might expose pipeline integrity issues that can enable the operator to take preventive measures and plan maintenance events.

Such a hybrid solution, from AVEVA™ (RTTM) and Prisma Photonics (fiber sensing), will obtain higher levels of performance and reliability. In addition, such a hybrid approach responds to the increasing regulatory demand to have two continuously working solutions based on different physical measures to ensure leak detection and prevention of substance spillage.

This article intends to introduce such a hybrid solution with new applications in predictive maintenance for pipeline operators and shed more light on the benefits of such a solution facing further regulatory demands.
Analysis, Logic, Considerations, Mitigations, Risk Assessments and Procedure to Drill Horizontal Gas Well With Separation Factor Up to 0.6 between the Ellipses Avoiding Collision in Exploratory Field. Bio-UC Project at Abu Dhabi, United Arab Emirates
Authors: Ruiz Fernando , Nunez Ygnacio , Hammadi Mahra Al , Hamdy Ibrahim , Al Shamisi Eisa , Kumar Rakesh , Al Hendi Mohamed , Negoi Adrian , Hebish Ayman , Baruno Agung , Al Arfi Saif , Al Mutawa Ahmed , Coscia Marco , Goiran Pierre , El Yossef Bassem , Al Blooshi Abdulla , El-Hafez Hany
Published: December 2021

In a current oil & gas challenging drilling environment where the fields are becoming very congested, PAD drilling and field grid designs with close proximity wells operation is booming. Drilling challenging wells with high collision risks is common as a result of the requirement to maximize the Asset value of the oil fields. For this reason, the urge for ensuring accurate well placement is becoming critical and as a result high technology methods are required to be in place.

Developing new areas where the poor and/or inaccurate drilled wells information (most of them are vertical) affect planning and placement of new wells due to the uncertainty in existing wells trajectories, causing collision issues among the new planning and the "trajectory" of the existing wells, leaving huge quantities of reservoir volume not possible to drain. For this study case, where the reservoir has some complexity due to faults and water, such limitation is critical.

The analysis and fusion of new techniques and procedure to manage the risk for the collision were implemented. Directional tools with high level of accuracy measurements were deployed and stringent procedures are put in place.

The Analysis, Logic, Considerations, Mitigations, Risk Assessments and a New Procedure implemented to avoid collision issues while drilling horizontal wells with Separation Factor (SF) less than 2 (standard worldwide is equal or above 2 and for this case, it was 0.6). This was developed by the Biogenic / Unconventional team, Drilling Department of Abu Dhabi National Oil Company (ADNOC) Onshore with the support of drilling service company and the approval of the ADNOC Head Quarter, to take advantage of around 0.9 km2 of hydrocarbon area for future drain.

The well was drilled successfully and safely, no collision or magnetic interference issue in any trajectory survey were reported during drilling and passing close by the existing well.
Approach for Real-Time Prediction of Pipe Stuck Risk Using a Long Short-Term Memory Autoencoder Architecture
Authors: Nakagawa Yujin , Inoue Tomoya , Bilen Hakan , Mopuri Konda R. , Miyoshi Keisuke , Abe Shungo , Wada Ryota , Kuroda Kouhei , Nishi Masatoshi , Ogasawara Hiroyasu
Published: December 2021

Pipe-sticking during drilling operations causes severe difficulties, including economic losses and safety issues. Therefore, real-time stuck-pipe predictions are an important tool to preempt this problem and avoid the aforementioned troubles. In this study, we have developed a prediction technique based on artificial intelligence, in collaboration with industry, the government, and academia. This technique was developed by combining an unsupervised learning model built using an encoder-decoder, long short-term memory architecture, with a relative error function. The model was trained with the time series data of normal drilling operations and based on an important hypothesis: reconstruction errors between observed and predicted values are higher around the time of pipe sticking than during normal drilling operations. An evaluation method of stuck-pipe possibilities using a relative error function reduced false predictors caused by large variations of drilling parameters. The prediction technique was then applied to 34 actual stuck-pipe events, where it was found that reconstruction errors calculated with the relative error function increased 0.5-10 hours prior to the pipe sticking for 17 out of 34 stuck-pipe events (thereby partly confirming our hypothesis).