bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Low-Cost Process for Sour Gas Sweetening and NGL Recovery
Authors: Rafati Navid
Published: November 2019

Greater than 40% of global natural gas reserves are sour, with hydrogen sulfide concentrations that make processing that gas uneconomic in most cases. Furthermore, it is desirable to economically sequester acid gas contaminants from these resources due to growing environmental concerns. Current conventional technologies such as amine, cryogenic, and membrane systems typically fail to achieve the aforementioned objectives. Thus, there is a need to develop new technologies for sour gas processing.

In this work, a new low temperature process for sweetening and fractionation of highly-sour natural gas is presented. The process, called "TarT", is capable of separating CO2 and H2S contaminants from the sales gas as high-purity, high-pressure streams while also recovering the NGL content of the feed gas.

It is shown that the TarT process consumes about 37% less energy as compared to conventional MDEA sweetening and NGL recovery processes to produce sales gas, C4, C4+ NGL blend and high-pressure CO2 and H2S contaminant streams. The TarT process introduces a new and highly economically advantaged approach to fractionate highly-sour natural gas and sequester the resulting acidic gases.
Managed Pressure Drilling Tackles Pore Pressure Uncertainty While Drilling, Running Liner, and Cementing Across Multiple and Heterogonic Layered Reservoirs for the First Time in the United Arab Emirates
Authors: Al Shehhi Maha , Al Ameri Saleh , Hadj-Moussa Ayoub , Saleh Mujahed
Published: November 2019

This paper presents the novel approach used in drilling, running liner and cementing a development well across multiple reservoir with high pore pressure heterogeneity that has historically caused drilling hazards like differential stuck pipe, losses, well control and slow rate of penetrations.

Having depleted reservoirs and high-pressure reservoirs in the same hole section of well-A dictates that the mud weight must be higher than the higher reservoir pressure, which puts high differential pressure on the depleted reservoir and causes differential stuck pipe and losses. The uncertainty in determining the pore pressure adds another challenge as the mud weight must be higher than the expected pore pressure. Managed Pressure Drilling (MPD) addresses these challenges by enabling determining the pore pressure while drilling and adjusting the Equivalent Circulation Density (ECD) to be with the minimum overbalance.

MPD allowed drilling the section with (12.0 ppg) mud weight instead of the conventional mud weight (15.7 ppg). This has reduced the differential pressure between the depleted formation and the other formations significantly and enhanced the rate of penetration while balancing the well. It also proved that verifying the well's prognosis for pressure is essential in avoiding drilling hazards. Constant Bottom Hole Pressure (CBHP) mode of MPD was used to maintain the same ECD while drilling and connection to avoid well influx during pumps off events by compensating the annular friction pressure loss by surface back pressure. MPD was utilized too in running the 7″ liner and cementing it as a guarantee if the mud weight was too low to stabilize the well. The operation was carried out without safety or quality issue. The MPD system performance was with zero nonproductive time and the hole section was drilled shoe-to-shoe without any change the Rotating Control Device (RCD). This application showed an alternative preventive solution to differentially stuck pipe instead of the reactive one.

The approach explained in this paper is the first of its kind in ADNOC Onshore field. It involved altering the mud weight program strategically for more adaptive approach in dealing with drilling hazards like differential stuck pipe, losses and well control. The scheme involving MPD for running liner and cementing is the first ever in United Arab Emirates.
Acquisition of an Ultra High Density 3d Seismic Survey Using New Nimble Nodes, Onshore Abu Dhabi
Authors: Nehaid Hani , Ourabah Amine , Cowell James , Brooks Chris , Stone Johnathan , Dieulangard Damien , Crosby Alistair , Naranjo John , Mahgoub Mohamed , Al Mesaabi Saif , Ablyazina Dinara , Manning Edward , Popham Mike , Tough Kenneth , Vasile Cosmin , Quigley John , O'Connell Kevin
Published: November 2019

The benefits of using autonomous nodes in a desert environment to efficiently achieve very high trace density seismic surveys with reduced HSSE risk and improved operational efficiency are increasingly being recognised by the industry. ADNOC, in partnership with BP, Rosneft and WesternGeco recently deployed 50,000 newly-developed ultra-light nodes (Manning et al, 2018) with simultaneous vibroseis source technology to acquire the densest ever seismic survey on land. The survey covered an area of 81km2 containing significant surface infrastructure and sand dunes.

The field trial had two main goals: first demonstrate the readiness of this new nodal system to acquire high quality seismic at full scale in a production-like setting; and second, to compare the data recorded by this new system to legacy data acquired by a conventional array geophone system and demonstrate the benefits of the former in terms of safety, operational efficiency and ability to image fine stratigraphic details at the reservoir.
The Digital Directional Drilling Evolution
Authors: Stepnov Alexey , Chatar Crispin , El Hawy Ahmed , Cassel Justin , Abouassi Basem , Khader Celine
Published: November 2019

Digital technologies are changing the way we work and are empowering the world. The oilfield is no different. Directional drilling is no longer challenged by distance or harsh environments. One oilfield service company began an innovative digital approach to directional drilling and logging while drilling (LWD) over a decade ago. Recently, technology and infrastructure enabled the industry to drill directional wells without engineers physically at the wellsite and independent of technical complexity. Digitalization is a complicated task for any service company. It requires a complete change of all workflows and implementation of cutting-edge technologies to drive the change. The current infrastructure includes a worldwide network of digitally connected operation centers (DCOCs) that provide advanced services to ensure operations are delivered efficiently and can be easily implemented. Even in the case of unforeseen circumstances when field engineers cannot go physically to the wellsite, operations can continue normally with some management of the change. As a result, multiple locations are currently drilling various well types, including horizontal wells with zero or minimal personnel at the wellsite.

It is evident, with ongoing digitalization in many forward-thinking industries that eventually drilling will take the neccessary steps. This is understandable due to the cost and operational norms of the industry but applying the technology in an efficient and cost-effective manner will yield gains for even the most discerning high-volume markets and, at the same time, improving key performance indicators. Directional drilling digitalization is still not a widely accepted concept for drilling everywhere on the planet. Companies continue work with full crews on location in most operations. The conservative approach of delivering directional and LWD services with the engineering teams located at the wellsite was restricting operators, so complicated well profiles in many areas, including some areas in the Middle East, were avoided. This paper is intended to lift the veil of uncertainty from digital directional drilling and show what is possible today and in the future. This paper will highlight the history of digital directional drilling operations, measurable benefits, lessons learned, and what is done today, and finally focus on the next steps in the digital evolution of drilling. Several new enabling technologies, innovative processes, and analysis of results will be discussed in the context of this new way of working.
Deepwater Pipelines Installation Risks and Challenges
Authors: Sinha Nitesh , Kumar Singh Nawin
Published: November 2019

With the advent of next cycle of stabilization and steady increment of oil and gas prices, the deepwater blocks which were marginalized due to high development cost, are beginning to appear as a lucrative proposition again. Globally new oil and gas production is focused in remote locations which are also challenging to operate. Deepwater, ultra-deepwater, tight oil and shale gas are great examples of this. In last two decades, exploration & production players have made rapid progress in pushing the depth of subsea production. The on-going development of new hydrocarbon discoveries in different deepwater regions creates significant opportunities for the pipeline industry. Also, the need of the ‘oil & gas markets’ to get well connected with the ‘oil & gas producers’ is leading its way to the announcements of long distance deepwater pipelines in a record water depth of up to 3500 m in the recent past.

Gearing up for this challenge, this paper broadly elucidates the deepwater pipeline installation risks and challenges, such as selection of the line pipe to sustain high external over-pressure and tensile stresses generated due to installation forces, selection of external coating system, capability requirement of installation vessels with high tensioner capacity to hold the long catenary of thick-walled pipe, pipeline configuration control and prevention against accidental flooding while laying, challenges in touch-down point monitoring and buckle detection, seabed intervention requirement & methodologies and new evolving testing & commissioning philosophies required for ensuring the integrity of the deepwater pipelines after installation. This paper also covers the findings of installation analysis, for S-lay configuration, performed for deepwater pipelines with varying water depths.

This paper intends to bring awareness among the "oil and gas fraternity" regarding challenges involved in ultra-deepwater pipelines and discusses the technical advancements made in this segment and the need of further works for bringing the installation of pipelines in ultra-deepwater one step closer.
Operational Excellence Review through Self-Assessment
Authors: Badithela Srinivas , Al-Haddadi Mohamed Ali
Published: November 2019

Oil and Gas, Petroleum Refining Industry is undergroing through significant Business Challenges, Transformation and Consolidation. Refinery Business Economics has been encountering increased challenges due to significant variations in the market dynamics. Refining Optimization has acquired renewed importance in the past decade and optimization of the existing facilities has become a key component in the overall Business Strategy. Operational Excellence forms the necessary attribute for Optimal Business Performance of the Progressive Companies. Operational Excellence and Business Excellence are the key focus areas for Petroleum Refining Industry in the Middle East and Other Regions. Operational Excellence and Business Excellence requires best in class performance in all the functional areas of relevance to the Business. Operational Excellence and Business Excellence are closely inter- related and complement one another towards superior Business Performance. Operational Excellence Groups in the company deal with activities that would help to inculcate culture of excellence and help in the effective implementation of continuous improvement activities across the company facilities. Periodic Assessment of Operational Excellence is extremely important for identifying the status and take necessary corrective measures /additional measures towards continuous improvement. ADNOC Refining has been involved in Operational Excellence activities and Business Excellence activities for the past two decades with and without the involvement of external consultants. This paper deals with key aspects of Operational Excellence review and methodology of systematic implementation, key challenges, and experiences of first of its kind simultaneous implementation across ADNOC Refining Operating Facilities.
Design of Foam Gas Shut-Off Pilot for a Giant High-Temperature, High-Salinity Carbonate Reservoir
Authors: Elhassan Mohamed , Keshtta Osama Mohamed , Berrim Ahmed , Draoui Elyes , Mogensen Kristian , Levitt David
Published: November 2019

This paper describes preparations and planning for a campaign of foam gas shut-off pilot operations in a large carbonate reservoir located offshore Abu Dhabi containing an oil column in equilibrium with a large gas cap. Throughout the field history and due to the heterogeneity (permeability ranges from 5 mD to 1 D), the major challenge to produce the oil rim independently from the gas cap was how to control premature gas breakthrough in the oil producers. Mechanical interventions in high gas-oil ratio wells are particularly complicated due to the risk of losing oil potential and are generally unsuccessful.

Injection of foam for gas shut-off (FGSO) is a near-wellbore treatment, which has been trialed elsewhere in the industry with some success. Foam can act as an auto-selective agent to shut-off confined gas inflow through a gravity-controlled source like coning or cusping, while oil breaks the foam, resulting in preferential oil flow and reduction in gas-oil ratio. In addition, this type of operation has been identified as an EOR enabler, because it can help prepare for the technical and logistical challenges of using EOR chemicals in the field, generate data useful for the modeling of surfactant and polymer under reservoir conditions, and mitigate early gas breakthrough in the case of gas-based EOR developments.

For the reservoir in question, a key complicating factor was to identify a surfactant, which could generate strong foam in-situ (mobility reduction factor of 50) at harsh reservoir conditions (temperature of 220-230 °F and water salinity above 200,000 ppm, including 20,000 ppm divalents), with an acceptable level of adsorption. The candidate selection process took into consideration overall behavior of the reservoir as well as performance of the individual high-GOR wells. Target well selection criteria included homogeneity of permeability, an understanding of gas sources and their movement, and observation of a rate- or draw-down-dependent GOR.

The experimental lab program involved testing several surfactant formulations in bulk as well as in corefloods with and without the presence of reservoir oil to evaluate foaming ability and level of gas flow reduction. One formulation showed the right level of in-situ mobility reduction, in addition to stability and moderate adsorption at the prevailing reservoir conditions, and was therefore selected for a pilot test involving four wells.
Mitigation of Scaling Potential of Seawater in High Temperature Environment Using Phosphonate Scale Inhibitor
Authors: Yamak Raafat M. , Nasr-El-Din Hisham A. , Rahim Sabiq , Taleb Moussa
Published: November 2019

Laboratory analysis was conducted in order to study the effect of a phosphonate scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high temperature/high pressure (HT/HP) applications. The objective of this study was to identify the minimum scale inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. Development of such a product would aid in the utilization of seawater-based fracturing fluids by controlling the scaling tendencies of the system, especially when exposed to formation waters. Utilizing a scaling software, various types of scales were modeled by testing different seawater/formation water ratios at temperatures ranging from 270 – 330°F. A dynamic scale loop was used which allowed seawater and formation water to be pumped into the system, thereby generating differential pressure data. The exponential increase in pressure would indicate scale formation. Various concentrations of scale inhibitor were then introduced to the mixtures and tested to determine the minimum scale inhibitor required for scale mitigation. Compatibility tests were also conducted to test for the efficacy of the scale inhibitor.

Based on the scaling software, barite was identified as the primary scale generated. Barite scale has a low solubility of 2 mg/L and is one of the most difficult scales to mitigate. The highest concentration of barite scale occurred in a 50/50 ratio mixture of formation water and seawater. For all the temperatures tested, the scale loop was run at the concentration with the most barium sulfate present. The results for this research concluded that at 270°F and 300°F, the minimum scale inhibitor concentration was 2000 ppm and 1500 ppm, respectively. Both treatments successfully mitigated the following types of scales: barium sulfate, calcium sulfate(s), and strontium sulfate. At 330°F, the minimum scale inhibitor concentration was lower. This decreasing trend in scale inhibitor concentration as temperature was increased is attributed to the temperature constraint of phosphonate scale inhibitors. As a result, adding the phosphonate scale inhibitor contributed to the formation of calcium phosphonate complexes that led to the rise in pressure in the scale loop test. This hindered the efficiency of the treatment and portrayed the dramatic effects of temperature and inhibitor concentration on scale mitigation. This research pushes the thermal constraints of a phosphonate scale inhibitor up to 330°F to test its efficiency and overall treatment integrity. There are also fracturing fluid applications introduced utilizing a seawater source with one of the highest total dissolved solids (TDS) concentrations in the world. Barium sulfate and other scales were successfully mitigated at various high-temperature applications for these systems utilizing a phosphate scale inhibitor.
Advanced Survey Management Techniques Allow Zonal Isolation through Successful Well Intersection in Order to Complete a Well as per Original Plan in a Giant Mature Field offshore Abu Dhabi
Authors: Abdelkarim Islam , Jadallah Haitham , Ness Knut , AL ALI Salim , Alzaabi Mohamed , Amer Reem , Diaz Nerwing , Gjertsen Morten
Published: November 2019

After completing the drilling phase of the 8½″ section for a well in a giant mature field offshore Abu Dhabi, due to geomechanical challenges it was not possible to run the 7″ liner in a shale formation which was open for a long period of time due to rig repairs (top drive failure in open hole), exposing all reservoirs and compromising the field development strategy. After several unsuccessful attempts to run the liner and leaving a drilling BHA in the hole during one of the cleanout runs, it was decided to sidetrack around the fish to intersect the original 8½″ open hole section in order to recover the original hole and isolate the reservoir flow units from each other, which was critical for the field development since more than five reservoir layers were opened with water and oil bearings increasing the risk of damaging the reservoir integrity due to potential cross flow.

Detailed measurement-while-drilling (MWD) survey analysis was conducted for the original hole in order to enhance surveys accuracy and minimize positional uncertainty. Typical survey management practices were implemented for Sag and Drilling String Interference; other techniques such as Dual Inclination, In-Field Referencing, and Multi Station Analysis were also applied. The implementation of these different survey management practices and their respective results are covered in detailed in the current article. Comprehensive planning was carried out, the sidetrack was accomplished and the original hole was successfully intersected at the first attempt.

The advanced applied survey management techniques were crucial, particularly in the absence of magnetic ranging as the interval to intersect was open hole. The outcome of these corrections resulted in a shift of 8ft to the final well position, ensuring the correct direction and position for a successful attempt to intersect the well. This intersection was particularly challenging as the original hole had a 3D profile, thus it was critical to minimize both vertical and azimuthal uncertainties. Intersection was achieved with an RSS BHA, and the success of this intersection without magnetic ranging capability was only based on following a planned well trajectory that intersected the original hole surveys, clear validation of the accuracy of the surveys for both original and sidetrack holes. Achieving this challenging directional drilling goal allowed the completion of the well as per original plan, which was critical for the field development plan of these reservoirs.

Based on the fact that there is very limited existing literature covering similar cases to the one presented, this current case represents a solid successful reference to be replicated in similar cases in the future covering these challenging applications of advanced survey management techniques.
The First Application of a Novel Cased Hole Selective Multi-Zone Sand Control Completion in Gulf of Thailand
Authors: Khunmek Thanudcha , Chigbo Ikenna , Sreeroch Asaduwut , Abu-Jafar Feras
Published: November 2019

This paper will discuss completion design and the deployment method of sand control for multi-zone completion wells in the Nong Yao field. The discussion will cover sand control and completion techniques from given reservoir characteristics, in combination with the production strategy. Operational challenges from offset wells will be discussed.

The Production strategy for the field required careful consideration for the unconsolidated nature of the reservoirs. An effective drawdown strategy is required as Electrical Submersible Pumps (ESPs) are deployed for artificial lift. The teams designed and implemented a cost effective multi-zone completion (MZC) with selectivity and sand control. The completion was designed to fit in a 7" 23# casing and is comprised of a lower and an upper completion. The complexity of the lower completion; 4" sand screen as outer string, internal 2-3/8" tubing with sliding side doors (SSDs), seal bores and packers, made deployment a challenge with a hydraulic workover unit due to the limitations of stroke length and gin pole.

The completion equipment were selected based on workover operations pipe handling constraint, i.e. stroke length, gin poling hanging weight.

As the workover stroke length is only 10 ft., R2 range screen and blank pipe was selected instead of the typical R3 range to prevent screen damage when passing through the stationary slip of the workover unit. Moreover, the total screen length combined with blank pipe has to be designed to meet the sand control objectives and stay within the gin pole hanging weight limitation. The lower completion was completed for selective production zone by zone, and was followed by an upper completion (Y-Tool and ESPs) to produce the hydrocarbons.

The first well completed as a MZC with selective sand control has been on production for more than six months with no sand checking the base sediment and water (BS&W), even though the well has produced at high water cut and at relatively high rates. This observation shows that the implemented completion design along with production start-up strategy is working well. This same strategy is being applied in future wells.
Auxiliary Boilers Energy Performance Benchmarking
Authors: Al Ktebi Waneya Abdulla , Sajjad Saqib , Al Jenaibi Eisa Salem
Published: November 2019

ADNOC Gas Processing, in its journey towards energy excellence, has adopted a novel in-house methodology for energy performance benchmarking. This methodology is primarily focused to unit & equipment level performance comparison, to identify gaps and highlight opportunities for improvement following the best international practices. Benchmarking is an evaluation of any aspect by comparing it with a standard or any other reference at different levels and scales. Generally, in an Oil & Gas Industry, auxiliary boilers mainly consume natural gas to produce steam for process heating. Energy performance of boilers is susceptible to decline due to several reasons and results in reduced efficiency. Owing to the significance of auxiliary boilers energy performance in the overall energy efficiency of gas processing, ADNOC Gas Processing conducted an in-house energy performance benchmarking of auxiliary boilers installed at its multiple sites.

Energy performance of total twenty five (25) auxiliary boilers was analyzed and evaluated in terms of different indices, to examine their current performance and benchmark it with other boilers for potential improvements. Benchmarking also assessed overall steam and condensate systems. Opportunities for improvement were observed in areas of process optimization, best practices and CAPEX based energy efficiency initiatives. Benchmarking exercise revealed energy savings opportunities in flue gases excess oxygen optimization, make-up water management, energy recovery from pressure letdown stations, waste heat recovery and steam traps audits. Study also highlighted areas of improvement in performance monitoring encompassing metering, sustained optimization and continual improvement.
Non Routine Flaring in Upstream Oil and Gas Industry Root Causes and Mitigations
Authors: Al Kamali Maryam Mohammed , Houache Omar , Hasan Hasan Abdellatif , Abdul-Wahab Sabah Ahmed , Agrawal Harshit
Published: November 2019

This study is deep diving in non-routine flaring issues. It focuses on data collection and analysis of non-routine flaring incidents that happened in six (6) different production stations located across Oman in order to define the bad actors that contributed to the frequent equipment failures. These stations have been chosen because they have high flaring frequency and volume compared with other stations located in other parts of Oman. Moreover, risk assessment matrix (RAM) and root causes analysis (RCA) were carried out to help in establishing the bad actors. In addition, for the sake of analysis, comparison between three years is conducted to determine which year has much more representative.

It was found that the main three bad actors are the chiller compressor, gas recovery compressor, and gas injection compressor. Moreover, risk assessment and root cause analysis shows that all bad actors fall under high risk cases, which indicates the criticality of failure of this equipment.
An Integrated Wells to Process Facility Model for Greater Burgan Oilfield
Authors: Desai Sameer Faisal , Al Jadi Issa , Al-Ghanim Wafaa , Franco Francy Milena , Khor Siew Hiang , Zhang Qiong Michael
Published: November 2019

This paper discusses the development of a truly integrated asset model for the Greater Burgan oilfield in Kuwait linking multiple wells, pipelines networks, and process facilities for achieving integrated operational excellence in the South and East Kuwait asset of Kuwait Oil Company. A water handling facility model comprising of two effluent water disposal plants, a crude oil export pipeline network and a water injection network model are also incorporated into this integrated asset model. The main objective behind the development of this integrated asset model is to enable better asset management, faster and more precise decision making and enhancing the hydrocarbon flow path all the way from the reservoir till the export point.

The new integrated asset model was developed from a model centric approach involving construction and calibration of over 1500 well models. All wells were then linked to their network models comprising of pipelines totaling more than 10,000 km. The well and network models were integrated with the respective process facility models of the 14 gathering centers located in the field and finally tied to the crude export, water disposal and water injection systems. The results of the integrated wells to process facility models such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production network can be plotted or visualized on the Geographic Information System (GIS) map.

Integration of the vast number of wells and network models with the 14 crude processing facilities in a single IAM platform provides comprehensive understanding of flowing paths spread across the giant Burgan field and proves its utility as an effective flow assurance tool. The IAM platform also provides engineers and management an effective tool for analyzing well potential, identifying under-performing wells, spotting clusters of high water cut wells, singling out back pressure effected wells and locating system constraints. Thereby the proven IAM provides valuable information for effective production optimization and long-term surface facility development plans.

The IAM platform is designed for use by Reservoir, Production, and Process Engineers as well as Operations, Business Development, and Asset Management teams. Engineers can evaluate various scenarios to improve production and operation performance such as choke increase or decrease, re-routing wells between manifolds, adding new wells into the system, and decision on slots for connecting new wells to the plant headers. The IAM also enables asset teams to forecast injection rates, review the impact on the entire injection network in terms of pressure distribution, and conduct "what if" scenarios leading towards complete asset optimization.
Starting with the End in Mind: The Path to Realising Digital Value
Authors: McLachlan Duncan
Published: November 2019

In this paper we will set out how we maximise the value created by the digital revolution through the use Systems Thinking and Agile techniques to establish a FEL 0-1 Digital Twin, we will then describe how we use a BIM approach to evolve this Digital Twin through the project lifecycle; fostering collaboration, breaking down siloes, creating and protecting value as we do so. Two case studies, one an offshore gas compression project and the other a normally unmanned wellhead installation, will be presented to demonstrate the application and effectiveness of this approach.
Flowback Analysis of Complex Fracture Networks in the Unconventional Reservoir Using Finite Element Method with Coupled Flow and Geomechanics
Authors: Li Jun , Liu Yuetian , Xue Liang , Cheng Ziyan , Kong Xiangming , Li Songqi
Published: November 2019

After fracture treatment in unconventional reservoirs, the in-situ stress and fluid pressure are greatly changed in the reservoir because of the generation of fracture networks. In order to get high production, efforts are made to get close fracture spacing and long fracture length in-situ field, which in turn make fracture distribution become complicated as the range of fractures size and density is widespread.

In this work, the finite element method is used to analysis flowback around hydraulic fracture among complex fractures networks, which consider the coupled effects of flow and geomechanics.

The reservoir is assumed to be a 3-D poroelastic medium. According to the fracture sizes, the fracture is divided into three types. These small natural fractures are treated as SRV regions, hydraulic fractures, natural fracture in middle and large sizes are explicitly represented using LGR. Finite element method simulates fracture deformation and the two-phase fluid flow in the reservoir during flowback stage. The physical properties are altered by the coupled flow and geomechanics in the reservoir.

The fluid pressure, stress and flowback production over time around these fractures are recorded. The results show that during the flowback period, the production experience a sharp decrease. The porosity and permeability in the reservoir are greatly reduced because of the coupled effects. These explicit natural fractures influence the hydraulic fractures. As the hydraulic fracture spacing reduced, the stress shadow effects become more serious and the flowback production decreases.

This work helps understand the flowback analysis with coupled geomechanics and flow effects in the complex fracture networks in the unconventional reservoirs and physical properties effects in different reservoir conditions.
A Top - Down View of Field Development Plans, Integrated Reservoir Performance and Production Sustainability Assurance
Authors: Tahir Sofiane , Al Kindi Salem , Ghorayeb Kassem , Haryanto Elin , Shah Abdur Rahman , Yersaiyn Saltanat , Su Shi , Ali Samad
Published: November 2019

Maturing giant and super giant fields have, typically, an extensive data set ranging from seismic data to time lapse surveillance data. The data set, associated studies and models together with driving values defined by ADNOC form the foundations of long-term plans, field development plans, business plans, reservoir management plans and production optimization plans. Ensuring the adequacy and optimality of the plans and their capability to meet their prescribed objectives is a very challenging task that requires unique assessment workflows. ADNOC is undertaking multiple fast-tracked Integrated Reservoir Performance and Production Sustainability Assurance (IPR) projects with the above objectives in mind. In this paper we will share the experience gained through the execution of such projects and the way this experience helped refining the workflows and the associated value.

We designed and applied unique workflows that combine "Bottom up" approaches by technical discipline with the "Top down" focusing on those factors that have the largest impact on the scope of the plans and the ability to deliver the expected outcomes. The identified issues and opportunities are presented in terms of their impact on volumes in place, reserves, facility, drilling plans, surveillance plans, modeling, etc. and are associated urgency indicators to help prioritizing actions.

The adopted integrated methodology and workflows helped in identifying and ranking various issues related to the reservoir models (static and dynamic) and many recommendations on how to tackle these issues in the new generation models were provided. Advanced reservoir management workflows were generated towards optimal production and injection balancing as well as to better manage the water flood and identify the most offending injectors. Many scenarios were explored to check the different elements of the full field development plan and ongoing projects, considering all the identified uncertainties. Many recommendations were provided, accordingly, concerning infill drilling and future gas lift program. Specific workflows were generated to optimize the performance of the existing gas lift wells and to identify and rank the future wells that will need gas lift according to their urgency, hence confirm the gas lift compression capacity that was subject of an ongoing project.

Key enabler to complete the project in the planed time frame was the use of cutting-edge modeling technology which has a drastic impact on the project and the team's capability to explore a comprehensive set of scenarios with associated sensitivities and uncertainty analysis providing unique insights towards more optimal decisions and clearer way forward.
Integrated Approach of Evolving Petrophysical and Formation Testing Measurements Improves Hydrocarbon Reserves of Laminated Clastic Formations in Kuwait
Authors: Chen Chao , Sassi Khaled , Ayyad Hazim
Published: November 2019

The characterization of the clastic Zubair reservoir is challenging because of the high lamination and the oil properties change making the conventional saturation technique uncertain. A new workflow has been recently established in the newly appraised wells which has involved advanced petrophysical measurements along with the fluid sampling. The new technique has led to identify new HC layers that were overlooked by the previous techniques, thus adding more reserves to the KOC asset.

Because of the high lamination of clastic Zubair formation and the change of the oil properties, the dielectric dispersion measurement was integrated along with the diffusion-based NMR to identify new oil zones that has been initially masked by the resistivity-based approach. The new approach has also provided details on the oil movability and the characterization of its property. As the newly identified layers were identified for the 1st time across the field, the fluid sampling was conducted to confirm the new findings.

The advent of a new logging technology from a multi-frequency dielectric technique deployed over the formation has independently pinned down the HC pays over the Zubair interval, including a new zone below the water column. The zone was initially identified as heavy Tar zone. The advanced diffusion-based NMR was thus conducted and integrated with Dielectrics which has demonstrated the movability of HC using the diffusion-based NMR approach over the newly identified zone. A fluid sampling was later performed which has confirmed the new finding. The new identified zone was initially overlooked by the previous interpretation and extensive modeling over the entire field. The seal mechanism was also explained by taking advantage of the high-resolution dielectric dispersion measurement (mainly the low frequency), which has been also supported by the Images interpretation. This new approach has added an incremental oil storage over the field.
A Generic Method For Acoustic Processing Using Deep Learning
Authors: Kisra Saad , Khadhraoui Bassem , Sable Sebastien , Lu Duc Duong Lam
Published: November 2019

A new method based on deep learning enables the extraction of formation compressional and shear slownesses from raw waveforms acquired by an acoustic tool regardless of its conveyance system or of its hardware configuration (number of axial receivers, waveform sampling rate, or number of time samples). The proposed approach is very fast, fully automated, and suitable for real-time processing workflows at the wellsite.

Over the years, a large collection of acoustic waveforms has been recorded and processed by experts in a variety of environments. In the proposed method, we apply a convolutional neural network (also known as ConvNet or CNN) to learn from previously processed data to estimate acoustic slownesses from raw waveforms. Because we use an algorithm that is originally designed for visual recognition, we transform the raw waveforms into images with enhanced characteristics that are directly associated with the acoustic slownesses that we are aiming to predict. For monopole waveforms, we were able to improve the prediction results using a short-term average/long-term average (STA/LTA) technique that enhances the main arrivals. We then train a CNN model with both the input images and the expected outputs (i.e., slowness values) on a large variety of data covering the main rock environments of interest. The CNN-trained model is subsequently used to estimate the slowness values from unprocessed waveforms never seen by the CNN model.

To test our method on real data, we gathered a collection of acoustic waveforms recorded by several acoustic tools in 20 wells, drilled in different fields across the world. The wells were drilled with different bit sizes (varying from 6 to 17.5 in.), and the compressional slownesses were ranging from 50 to 165 μs/ft and shear slowness ranging from 80 to 600 μs/ft. In total, we used 96,011 data points where each data point consists of a pair of a waveform array and the associated slowness value calculated by an acoustics expert. We then applied the CNN-trained model to a set of waveforms from validation wells, i.e. wells that were not part of the training dataset.

In these wells, previously unseen by the ConvNet model, the average absolute error between the slowness estimated using the CNN-trained model and the slowness calculated by an expert was less than 3 μs/ft, which is comparable to the error associated with state-of-the-art processing techniques for slowness estimation. We also discuss how our method can be extended to estimate shear slowness from dipole data using the same ConvNet. The deep-learning-based technique for slowness estimation that we describe can run extremely fast after the ConvNet training process is completed and provides good slowness results without prior information about the tool configuration or the environment in which waveforms are recorded. Because our technique is fully automated, it can also be used as an automatic quality control (QC) flag for wellsite processing and real-time operations.
Towards a Self-Serving Big Data Analytics Platform for Oil and Gas
Authors: Ocampo Alexis , Farah Gabriel , Gutiérrez Ernesto
Published: November 2019

Organizations today, especially in the oil and gas sector, are swimming in data [1] but most of them manage to analyze only a fraction of what they collect. To help build a stronger data-driven culture, many organizations, starting with technology companies, are adopting a new approach called self-service analytics. In this paper, we present our big data and analytics architecture that has enabled our in-house and outsourced engineering, and data science teams, to develop self-serving AI models and data pipelines. Our architecture is presented to the reader in such a way that he/she can apply it using the cloud provider of their choice by translating the concepts presented here, either to native cloud PaaS or using open source products.
Integration of Geophysics and Geology in a Complex Area, Gulf of Suez
Authors: de Vincenzi Luca , Ellen Helby , Khamis Anaam , van Dijk Johannes Petrus , Sabetian Raffaela
Published: November 2019

Dragon Oil (ENOC Group) is operator with 100 % of interest in the exploration East Zeit Bay (EZB) block, which covers a surface of 93 km2 in an area where producing oil fields are nearby; e.g.: East Zeit, Hilal, Ashrafi, Ashrafi SW, and Zeit Bay fields. The license commitment consists of a seismic acquisition and processing and the drilling of two exploration wells before September 18th, 2019, which corresponds to the end of the extension of the first exploration period. The EZB block is located in the Gulf of Suez (GoS) in an area characterized by very shallow waters, where two coral reef islands emerge during low tide and several obstacles are present, i.e.: an oil terminal, mooring buoys, a waiting area for tankers and fishing and touristic activity. In the period 1969-1984, some 240 km of 2D seismic were acquired within the block using different acquisition parameter sets and processed with inhomogeneous flow-charts generating a sparse 2D seismic grid of variable data quality. Some of these data were reprocessed even in PSTM and PSDM, but without any sensible improvement. Furthermore, 3D seismic surveys were also acquired in 1996/1997 and almost cover the entire surface of the EZB block: The Ashrafi Deep Water (DW) survey, obtained towing a streamer, has been recorded in the north-eastern part of the block and the central and western parts have been surveyed by the West Ashrafi campaign in Ocean Bottom Cable (OBC) mode. But this 3D is of very poor quality due to the screening effect of coral covering the sea bottom on the geophone component of the recording.

During the last four years, extensive multidisciplinary analyses integrating reprocessing of existing magnetic data with new acquired gravity data and new and reprocessed 2D and 3D seismic data, well log and dipmeter analyses were carried out by Dragon Oil to delineate drillable prospects. Key of the success in generating a valid interpretation was the idea to combine a well site survey, compulsory for rig location, with a 2D seismic survey in an area with restricted vessel maneuverability.
Ushering Operational Excellence Through Development and Operationalization of Closed Loop Action Tracking System
Authors: Choudhuri Amit , B. Mohd Jainal Mohd Saifunazim , B. Adenan Mustafa , Thanerajah Vivege Rajah
Published: November 2019

At all Field Operation Centers of PETRONAS Carigali Sdn Bhd (PCSB), multiple meetings are conducted on a daily basis and also on a periodic basis, based on the laid down standardized meeting Terms of Reference (TOR). Many short and medium term actions, opportunities and risks are identified during these meetings. Further, through continuous real time surveillance and routine reviews as well as detailed analytic exercises, multiple actions leading to opportunities for production gain and better managing risks are identified. These actions are assigned to various discipline focals with an understanding that they would be completed within an expected time duration. As has been the practice, logging and registering of these actions are being made through different means, using documentation process that are not standardized, and which leads to difficulty in effectively following up on these actions until their closure.

To ensure that all such actions are tracked and effectively closed within the target date as well as to enable a readily accessible "Lessons Learnt" data bank, a centralized and standardized closed loop action tracking web-based system was deployed by Operational Excellence department in collaboration with all Assets.
Waste Heat to Power System in Oil and Gas Industry Improves Plant Power Efficiency
Authors: Agahi Reza
Published: November 2019

Waste heat is the by-product of industrial energy usage. Approximately one-third of the energy consumed by the oil and gas industry is discharged as thermal losses into the environment or via cooling systems. And the main reasons for waste heat discharge are process inefficiencies and technology limitations in the conversion of thermal to mechanical energy. Nevertheless, because the oil and gas industry demands large amounts of thermal, electrical and mechanical energy, a huge amount of waste heat is subsequently available.

Organic Rankine Cycle (ORC) technology has made economical utilization of lower temperature heat sources possible. ORC's efficiency percentage for waste heat recovery varies between single digit to the mid-20s, depending on the waste heat source temperature and the cooling medium. Even the recovery of a few MW of thermal energy with a single-digit cycle efficiency for a plant consuming an average of 100 MW (134 102 hp) thermal energy is a considerable efficiency improvement. Studies by the Oakridge National Laboratory (USA) show that 75% of waste heat comes with sufficiently high temperatures (> 150°C, or > 302°F). This report projects a 2-5-year return of investment for ORC-based waste heat to power plant systems, which represents an attractive financial payback.

The recovery of waste heat from oil and gas operations remains mostly underutilized. Furthermore, economically feasible power generation from waste heat has been limited to medium- to high- temperature waste heat resources. This paper will explore technical solutions to these challenges facing the oil and gas industry

In this paper, three cases of waste heat from a gas turbine's exhaust flue gas are presented. The turbines have nominal output of 7.5, 15, and 25 MW (10 057, 20 115 and 33 525 hp) electrical power at an ambient air temperature of 15°C (59°F). A heat recovery unit (HRU) can recover thermal energy from exhaust flue gas. The heat recovery loop (HRL) could exchange thermal power with an ORC system, which in turn has the potential to produce electrical power. It will be demonstrated that this configuration has a HRL/ORC cycle efficiency of approximately 10% when the ambient air temperature is about 30°C (86°F).