bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing the Number of Nodes in Artificial Intelligence Neural Network Using Parallel Computing Methods
Authors: AlBar Abdullah , AlGharbi Salem , AlGoz Ahmad , Yami Abdullah
Published: November 2018

Determining the optimal configuration/ architecture for neural network could be a very time-consuming process. It includes going through big number of scenarios to simulate and validate different architecture. This paper will go over a process for intelligently automating this tedious task by providing a utility that will automatically validate the different permutation and picking the optimum configuration. This is done with maximum efficiency by utilizing parallel computing methods combined with in-memory tables to produce very fast result. The new methods enabled Exploration and Producing (E&P) data scientists to simulate and validate a big number of neural network configurations/ architectures in shorter time, allowing them to identify the optimum neural network configurations that can generate the best prediction results. Leading to more accurate Artificial Intelligent/ Machine Learning (AI/ML) models. To quantify this method, this paper approach can cut the time needed for such process from weeks to hours, especially when dealing with modeling E&P real-time problem. The process involved utilizing parallel computing methods combined with in-memory tables, not only in processing complex Artificial Intelligent/ Machine Learning (AI/ML) models, but also in developing the complex models. This approach is intended to empower data scientist in the Exploration and Producing field to quickly reach the most optimize model, leading to faster approach for safer, and more cost-effective solutions
A Success Story of Production Improvement in a Deepwater GoM Field Based on Integration of Surveillance Techniques
Authors: Gonzalez Fabio , Gonzalez Doris , Carmichael Steve , Stewart Carlos , Pietrobon Marney , Garzon Francisco
Published: November 2018

Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment.

Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis.

A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates.

This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.
Cemented Completions and Through-Tubing Coiled-Tubing Drilling Enable Significant Cost Reduction in Mature Gas Fields
Authors: Ebrahimi Arian
Published: November 2018

A novel well concept to unlock reserves from mature gas fields in Northern Germany has been developed. This concept combines cemented completions with through-tubing coiled-tubing drilling to enable significant cost reductions using ultra slim hole drilling in sour gas bearing, Upper Permian Zechstein dolomite reservoirs.

Once gas reservoirs mature, drilling of conventional infill wells can quickly become economically unattractive. Often this leaves resources untouched and it limits the economic life span of a field. To improve the economics of infill drilling in deep and mature gas fields significant cost reductions are necessary. These cost reductions can be achieved by changing the proven, yet costly, casing scheme to an ultra slim hole well concept. Besides unfavorable economics another challenge while drilling with conventional technology in mature fields can be the reduced inflow performance caused by formation damage. This challenge can be overcome by under- or at-balanced drilling, which is enabled by through-tubing coiled-tubing drilling.

Despite improved efficiencies gained from knowledge by drilling many offset wells, the estimated gas volumes are not sufficient to justify drilling of new wells with the established and conventional well design. Therefore, the operator prepared an advanced ultra slim hole well concept. The casing shoe setting depths remained unchanged, however the hole sizes are reduced significantly. The openhole reservoir section is changed from 5.875-in to 2.5-in and this section is drilled with coiled-tubing and through the installed completion. The size of the completion is selected to be 3.5-in and it is cemented in a 4.125-in hole. In this application, the cemented 3.5-in completion eliminates an entire 7-in liner that would be necessary in the conventional casing scheme. The remainder of the ultra slim hole well is drilled with a 5-in drilling liner, a 7-in intermediate casing and a 9.625-in surface casing. This needs to be compared with the conventional casing scheme comprising of an 18.625-in surface casing, a 13.375-in intermediate casing, a 9.625-in production casing and a 7-in liner. The reduction in cost is estimated to be in the order of 40%.

The presented concept can enable significant cost reductions and by applying this ultra slim hole concept further infill drilling in mature gas fields can become more economically attractive. Moreover, formation damage can be overcome by underbalanced drilling, which is enabled by drilling through-tubing with coiled-tubing. The synergies created by combining cemented completions with coiled-tubing drilling are presented in this paper.
A Method for 3D Saturation Modeling with Drainage and Imbibition Cycles
Authors: Darous Christophe , Raina Ishan
Published: November 2018

Typical saturation height modeling assumes that the migrated hydrocarbon has displaced water under primary drainage until pressure equilibrium controlled by buoyancy, pore throat size, and the position of the free water level (FWL) is reached. When leakage of the caprock or a structural tilting after migration occurs, a shallower position of the new FWL involves an imbibition cycle to represent the initial saturation distribution in a 3D reservoir model.

The methodology starts at the well level by building drainage saturation height functions (SHFs) typically from core capillary pressures (Pc) experiments, in relationship with the reservoir rock typing scheme. The following step involves the construction of the scanning curves that will revert any primary drainage saturation into an imbibition cycle. Then, considering the position of the actual FWL defined from pressure gradients, the position of the paleo-FWL (PFWL) in each well is solved to best match the water saturation profile computed from logs. The resulting PFWL is mapped to implement the saturation height modeling in 3D.

A synthetic case, of tilting after migration is used to illustrate the methodology. The rock typing scheme and the petrophysical properties from logs are coupled with the saturation height modeling defined from Pc core experiments. The typical inconsistencies between the saturation profiles computed from logs and the position of the FWL from pressure gradient that cannot be resolved with drainage SHF are described. The interpretation of the PFWL improves the understanding of the migration episodes and geological events. The implementation of the methodology in a 3D model provides a more accurate hydrocarbon in-place calculation and perspectives for improving recovery and field development strategy.

Methodologies to build 3D saturation height models in drainage consistent with reservoir rock types are common practices. The equations for modeling water saturation by including an imbibition cycle have also already been defined. The developed workflow combines both methodologies to initialize a 3D static saturation model that honors the fluid fill history associated with imbibition and is consistent with petrophysical properties of the reservoirs. The method has been fully coded into commercial software and can be readily implemented to real case studies.
Innovative Field Trial Results of Flangeless Grooved HDPE Liner Application in a Super Gigantic Field for Oil Flow Line Internal Corrosion Management
Authors: Amabipi Abby Kalio , Salem Marwan Hamad , Grandhe Siva Prasada , Gupta Tijender Kumar , Awadh Mohamed Ali , Herbig Nicholas , Schell Jeff , Compton Ted
Published: November 2018

Objectives

The ADNOC super gigantic onshore field suffered many cases of loss of containment in oil flow lines due to internal corrosion. The loss of containment caused by internal corrosion and need to determine specifications and accurate future flow line integrity management plan, led to a field trial application of Grooved and Flangeless HDPE Liner technology in 3.0km Schedule 80 API 5L Gr. B 6"flow line to eliminate this problem in the super gigantic ADNOC Onshore Field.

Methods

The field trial was initiated in June 2011 and installed in April 2012. The HDPE lined flow line was monitored for 5 years between April 2012 and December 2017. This paper presents the detailed extrusion of the HDPE material, installation, thorough monitoring program, results and integrity challenges of the technology validation in 3.5km and 3.0km pipe lines. A rolling machine reduced the OD of HDPE liner by 7% before drawing into the flow line by a pulling machine, the HDPE OD expands back to full size in the flow line. The trial was monitored closely with intensive program. An optimization process was followed (frequent monitoring of test spool vent, sample analysis, possible re-injection of any flow line vent pressure) assisted by thorough testing and analysis at the Borouge Innovation Center (BIC).

Results

This paper describes the successful 5 years field application of HDPE Liner as a cost efficient innovative method that eliminates oil flow line internal corrosion and ensures that Asset value is maximized. The results show that there is no chemical degradation after 5 years of use in oil well, few scratches were found that did not propagate into cracks. The outcome of this technology is a major breakthrough of a cost efficient technology for Company oil flow line internal corrosion management. Field validation of this technology had a positive impact on operator's flow line integrity management, giving more options for proactive flow line internal corrosion management and resulting in total cost reduction and improved HSE performance. Additionally, results from 6 spool sections of the tried oil flow line allows for extending the cost effective HDPE Liner technology to oil flow lines with less risk associated. This technology eliminates internal corrosion threats with huge Opex savings in chemical treatment programs as no chemical treatment is required.

Novel

This paper explains the value added to the company and the feasibility of using grooved/ PERT liners for high temperature and high GOR oil flow lines for maximum benefits. Finally, the paper advances knowledge in the clear impact on the internal corrosion management process that guarantee proper flow line design strategy that prevents uncontrolled release of hydrocarbons (oil) and loss of containment caused by leaks due to internal corrosion.
An Integrated Multidisciplinary Approach in the First Extended Reach Horizontal Well in an Undeveloped Reservoir: A Case History, Offshore Abu Dhabi
Authors: Al Hassani Sultan , Altameemi Ibrahim , Khan Owais , Ahmed Shafiq , Serry Amr , Fares Wael , Essam Ramy , Aki Ahmet
Published: November 2018

The undeveloped sublayers of the prolific offshore Arab reservoir were recently targeted for appraisal drilling, aligning with the ever-increasing efforts to expand production and book new reserves. The first extended reach horizontal well was drilled in this field to evaluate the economic potential of four different reservoir sublayers. Reservoir characterization and the evaluation of lateral permeability changes were the primary objectives for these low permeability layers. Maximizing reservoir contact while maintaining minimum borehole tortuosity presented substantial geosteering challenges. Another challenge is that the bottomhole assembly (BHA) must be free from radioactive chemical sources.

A well placement workflow was developed that honors the structural geological setting, based on the existing field knowledge and offset petrophysical data. The optimized BHA consists of a point-the-bit rotary steerable system (RSS) and logging-while-drilling (LWD) sensors. These LWD sensors include high-resolution microresistivity imaging, laterolog resistivity, azimuthal multipole acoustic, nuclear magnetic resonance (NMR), ultrasonic calliper, and near-bit azimuthal gamma ray sensors.

High-resolution microresistivity imaging and the near-bit azimuthal gamma ray sensor were used to geosteer in the thin reservoir subunits and to facilitate fracture identification. NMR was used to help remain in sweet zones in real time and to provide pore size distribution, based on T1 measurements for permeability evaluation. Acoustic and high-resolution image data were used to derive empirical permeabilities.

The 8,000-ft horizontal section was successfully geosteered with 100% reservoir contact, tapping into four thin reservoir sublayers. Real-time high-resolution microresistivity images, dip picks, and near-bit azimuthal gamma ray data helped to maintain the wellbore attitude parallel to the stratigraphy within each sublayer; they also facilitated a smooth transition from one sublayer to the next with minimum borehole tortuosity, aided by the point-the-bit RSS and at-bit inclination measurements.

Fracture evaluation from high-resolution images, NMR, acoustic, and image-based permeabilities are integrated with production log results to enable a better understanding of the field, to benchmark flow unit identification in these undeveloped reservoirs, and to optimize future geosteering and petrophysical data acquisition requirements.

The traditional reactive geosteering concept is challenged by placing the 8,000-ft extended reach section in four different sublayers that are as thin as 3 ft true stratigraphic thickness (TST) without penetrating any boundaries.

The multidisciplinary approach helped to assess the economic potential of these undeveloped layers within the local reservoir sector and to formulate plans for a future field development program.
Mitigating Wellbore Stability Risks through Geomechanical Solutions
Authors: Hamid Osman , Al Qahtani Adel , Alamer Sarah , El Sherbeny Wael
Published: November 2018

Geomechanical modeling is a key driver in attaining optimum wellbore stability while drilling horizontal wells in the orientation of the minimum horizontal stress (Shmin).

Although geomechanical modeling remarkably helped to obtain best estimates on minimum required mud weights for ensuring stable wellbore, these models still have uncertainties along the horizontal wellbores. Multiple factors contribute to wellbore instability such as lateral changes in rock mechanical and strength properties, formation pressure, and localized digenetic effects. An improved geomechanical workflow has been developed to manage uncertainties and enhance operational efficiency.

The proposed methodology is composed of calibrated geomechanical models for wellbore stability assessment that to be applied for upcoming planned wells during drilling operations. A number of key parameters were identified to build customizable geomechanical solutions and deliver stable wells. These key parameters include occurrence and sequence of strong/weak formation intervals and risk of differential sticking across depleted intervals. Each plan well requires a solution that includes computation of minimum required mud weight, formulation of mud system to handle multiple failure mechanisms, design of Logging-While-Drilling (LWD) Bottom Hole Assembly (BHA), and real-time geomechanical monitoring.

Upon implementation of this methodology, the horizontal well was drilled successfully in a controlled manner. In this paper, an experience is highlighted to demonstrate the effectiveness of customized geomechanical solutions. It discusses the implementation of geomechanics at a specific sub-surface condition to attain the best result. In this study, there was a high risk for wellbore instability while drilling through highly stressed formation in minimum stress direction.

The task was approached in a systematic way with a core objective of ensuring practical implementation of geomechanics findings, and follow the recommendations to mitigate wellbore stability related issues. There were two options that were been evaluated in this paper to prevent and mitigate wellbore stability, the first one is to low mud weights together with wellbore surveillance using real-time technolog, the second on is to use higher mud weights using sealing polymer and proper mud system formulation to avoid differential sticking.
What's the Difference Between Lean Construction and an Operations Science Approach to Project Delivery?
Authors: Shenoy Ramachandra
Published: November 2018

Project Management aims to address the myriad technical, human, organizational and managerial issues encountered during project execution [1]. Over the past two decades, different variants have emerged, including Lean Project Management, Agile Project Management, Scrum, Theory of Constraints and Extreme Project Management, to name a few. Lean Construction [2,36,54] utilizes concepts originally from Lean manufacturing and applies them specifically to the delivery of projects in the construction sector.

Despite the proliferation of different "flavors" of project management, major capital project outcomes in construction and in other industries remain poor [3 – 5]. Industry practitioners face a confusing array of differing methodologies, each claiming to address poor project performance. Project Production Management (PPM), based on operations science principles well-established in industrial engineering, addresses the gap between today's poor project performance and what is possible, thereby differentiating PPM from other methodologies.

Here, we focus on a comparison between PPM and Lean Construction. We trace the historical evolution of Lean Construction from its roots in Lean manufacturing, highlighting the operations science foundation underlying both Lean and PPM. Lean Construction covers aspects of project governance, organization of project stakeholders and the work activities of the organization. In contrast, PPM focuses on the organization and control of project work activities. PPM's deeper focus on the execution of work activities results in quantitative, predictive outcomes, validated by practice, that address poor project execution performance.
Advanced Logging-While-Drilling Cased Hole Sonic for Real-Time Cement Evaluation and Formation Slowness - Case Studies from West Africa
Authors: Murray Doug , Ghia Gabriele , Pouty Miguel , Blanckaert Thibault , Turner Michael , Balou Efficience
Published: November 2018

The acquisition of high-quality logging-while-drilling (LWD) cased-hole borehole sonic data in real-time (RT) and in memory (RM) dramatically improves drilling efficiency. RT sonic waveform amplitudes and slowness-time-coherency (STC) measurements enable qualitative cement evaluation either while running in hole (RIH) or when pulling-out (POOH). Operators can make appropriate decisions on cement quality to either continue drilling or perform remedial work. Data acquisition is transparent to drilling operations, removing wireline logging that can contribute to additional time and cost.

Furthermore, with RM data a quantitative cement evaluation can be performed, and when environment conditions are adequate, formation compressional slownesses through casing can be computed.

The advent of the latest LWD sonic acquisition technology and related processing techniques has significantly reduced the challenge of cased hole LWD sonic acquisition. More powerful sonic transmitters, improved receivers, altered transmitter-receiver spacings, and fundamental changes in tool design have meaningfully improved the acoustic signal-to-noise ratio. An improved understanding of LWD cased-hole borehole acoustic modes, the ability to transmit acoustic energies at more optimal frequencies, and the capability to simultaneously acquire cement evaluation information have all contributed to improved LWD cased-hole sonic logs.

Cementing is essential to well integrity, it supports casing and provides zonal isolation. Historically, quantitative cement evaluation has been acquired via wireline (WL) tools, the most common being the cement bond log (CBL), a principle based on the amplitude of casing arrivals. LWD sonics have historically been used for top of cement (TOC) logging, which shows cement presence or absence behind casing and is a quantitative cement evaluation. Contrary to WL CBL tools, LWD tools have a steel collar that permits acoustic propagation. As such with LWD tools it has been difficult to separate casing signals from those in the tool collar (Kinoshita, 2013). In poorly bonded conditions, the casing amplitude is much larger than the collar arrival. In well-bonded conditions, the casing signal is weak and can be less than the collar arrival.

From multiple cased wells in Deep Water Offshore West Africa, this paper demonstrates the application and results for the latest LWD sonic tool and processing techniques for the following; RT TOC evaluation while RIH before drilling out the casing shoeQuantitative cement evaluation from tool memory waveform dataFormation compressional slowness through casingApproximately US$450,000 saving compared to wireline runs
Integration of Penta-Combo LWD Measurements for Petrophysical and Geomechanical Feasibility
Authors: Elabsy Islam , AlTurkey Shaikha , Alhazzaa Shaimaa , Dutta Abhijit , Belhouchet Mohamed , Abba Abdessalem
Published: November 2018

Advanced levels of depletion cause unexpected reduced pore pressures and thus reduced reservoir fracture gradients, presenting considerable drilling challenges in the Burgan Field in Kuwait. This can lead to matrix damage due to mud losses and result in borehole collapse due to the relative increase of effective stress concentration in the vicinity of the borehole. The area of the study showed high levels of non-productive time (NPT) as well as increased costs due to the drilling of unplanned sidetracks in highly deviated wells. LWD Penta-combo measurements including azimuthal sonic and formation pressure have been utilized to model fracture gradient and borehole collapse gradient in real-time, and proved effective at reducing risks and rig time by allowing proactive management of these challenges.

Borehole collapse in offset wells was analyzed to predict and simulate the wellbore stability of a planned well via a pre-drill geomechanics model prior to drilling the well. The well was planned with a high deviation of 56° and oil based mud. The salinity of the water phase was recognized as an essential factor in assessing wellbore stability risk with respect to shale-dependent time failure.

The integration of real-time LWD sonic and density data with formation pressure testing data in the geomechanics model for the first time in the 12 ¼-in. section showed excellent correlation and confirmed different levels of depletion in the reservoir. Uncertainty in the modeled fracture gradient was significantly reduced and effectively eliminated with the inclusion of real-time formation pore pressure testing data. This successful combination of modeled pore-pressure curves from the real-time LWD sonic data with the real-time formation pressure test data acquired while drilling in the same run is a first in Kuwait. A total of 15 pressure points were sampled in real time while drilling, allowing for proactive mud window optimization and borehole stability geomechanical analysis.

This real-time wellbore stability technique based on advanced LWD azimuthal acoustic technology in conjunction with real-time formation pressure testing while drilling has been developed with a unique process and workflow allowing the operator to drill the well with no significant wellbore stability issues and with the optimized shape of the borehole for a safe casing run. In addition, NPT was reduced to 0 hours and overall days per well were reduced significantly.
Delivering and Sustaining Step Changes in Drilling Performance Through a Physics-Based Digital Workflow Application
Authors: Davis J. Ryan , McClain Eric E. , Al Sawafi Jamal , Al Maskari Iman
Published: November 2018

In 2015, the operator deployed a global initiative that focused on using physics-based principles to optimize various aspects of the well construction process. The initial rollout emphasized optimization of on-bottom drilling time utilizing mechanical specific energy (MSE), and this was successful in generating step changes in performance. The success of this initiative, and the internal and external marketing of that success, laid the foundation for the physics-based digital workflow developed in the operator's international business unit in Oman during the second quarter of 2017.

The drilling teams launched a proof of concept in Oman in July 2017 to test the workflow. Throughout the proof of concept, the workflow was digitized, and it evolved into a robust web-based application to serve as the framework to facilitate consistent, repeatable, and scalable execution of the physics-based workflow. The purpose of this paper is to illustrate the benefits of utilizing a physics-based workflow as well as to describe the innovative approach the operator used to execute the physics-based workflow. The workflow overview, proof of concept results, challenges, and future opportunities are discussed in detail.

During the proof of concept, which lasted from July 2017 through August 2018, field personnel from eleven drilling rigs submitted over 4,000 entries into the digital workflow application. Office-based personnel then launched 32 design projects, addressing more than 200 of the issues identified. Of those 32 projects, 17 were completed within the specified period. In one particular field, the drilling team achieved a 20% reduction in well cost and a 27% reduction in drilling days on location by using this digital workflow. Overall, both drilling teams in Oman experienced tremendous performance gains throughout the proof of concept, with one team achieving a 72% increase in footage drilled per day, and the other achieving as much as 32%. The success of the proof of concept led to the operator's decision to deploy this web-based application and digital workflow globally in the second half of 2018.
Offshore Gas Field Development Strategy and Flow Assurance Prediction and Optimization in Harsh Environment
Authors: Almohammad Humoud , Al-Derbass Abdullah , Alsubaie Abdulaziz , Bumajdad Mohammed , Al-Khamis Abdulaziz , Alshammari Abdullah , Al-Tameemi Talal
Published: November 2018

An offshore gas field located in a cold area; with an average temperature of 13 Celsius degree and −1.2 Celsius degree under sea level. The reservoir is located 200 meters under the sea floor, where the sea floor is 850-1100 meter depth and 120 Km away from shore. The objective is to develop an offshore production system for the gas field and maintain the necessary production, taking into account flow assurance, economics, and environmental effect.

The required design includes reservoir pressure forecasting, completion design, drilling strategy, and production flowline network modeling. The first step was forecasting the reservoir pressure by trial and error equation, then completion design to calculate the possible production increment from every well and calculate the cumulative produced volume to predict the changes in the fluid composition. The drilling strategy and completion design were carried out under the following assumptions: wells are having same completion design, production rate, and static reservoir pressure. The production network simulated with the designed completions using a steady-state multiphase flow simulator, with the sub-sea template and manifold strategy.

For the flowline network, polyurethane coat was used for each pipe to reduce the heat transfer from the sea water to the flowing fluids. The back-pressure equation was used to develop the IPR model and flash separation to predict the gas composition changes assuming the reservoir is an isothermal system. The base year started with eight wells, to achieve the required production per year, 70 MMSCM per day. Erosional velocity ratio kept under 1 for the designed 16 years. Pipelines coating was required to prevent flowline damage and deal the forming hydrates. A total of 30 wells to be drilled to cover the production needed for each year.

An offshore gas field study is explained in details with the simulation design procedure and pre-planning strategy for harsh cold environment flow assurance concerns and production difficulties. In addition to helpful estimation equations.
The Effect of Temperature on Estimating Free Fluid Index FFI by Nuclear Magnetic Resonance Measurement: Phase 1 Study
Authors: Kwak Hyung , Gao Jun , Harbi Ahmad , SayedAkram Nawaf
Published: November 2018

Since the initial introduction of Nuclear Magnetic Resonance (NMR) Technology into the oil and gas industry as a lithology independent porosity measurement technique, NMR well logging has been providing various valuable Petrophysical reservoir properties, such as porosity, permeability index, pore size distribution, and fluid typing, etc. To increase the reliability of these NMR log data interpretation, core-log integration, combining log and laboratory data, is necessary. For example, T2 cutoff values which determine the bulk volume of movable fluid (BVM) from NMR log data are determined from laboratory NMR measurement since it requires the measurements at 2 different saturation levels which is not possible at the reservoir with current technology. Unlike NMR logging in the field, however, most of laboratory NMR measurements are conducted at room temperature and pressure. Until recently, the temperature effect on NMR relaxation data is considered to be minimal since the surface relaxation is the dominant proton spin relaxation mechanism within confined porous media, such as reservoir rock. There have been a few experimental works during the early period of NMR technology application in well logging shows minimal temperature effect on that in reservoir rocks.

Recently, this phenomena has been re-investigated and been shown there is non-negligible temperature effect on the shift of NMR relaxation time. In the current work, the NMR T2cutoff values at various temperatures for 6 carbonate reservoir rocks with multipore system have been measured. Upon the verification of temperature dependence of NMR T2 cutoff values for reservoir rocks, further investigation of identifying elements that cause this phenomena has been initiated.
A Petroleum Systems Analysis and Characterization of the Frontier Ceduna Sub-Basin in Australia
Authors: Alghuraybi Ahmed , Al Harthi Al Muhanna , Jabry Ahlam Al
Published: November 2018

Objectives/Scope

The Ceduna Sub-basin is one of the few remaining frontier basins in Australia today. Few exploration wells have been drilled in the basin and none have encountered hydrocarbons. The current study aims to investigate the hydrocarbon prospectivity of an area of interest (AOI) within the distal part of the Ceduna Sub-basin, where no well information is available.

Methods, Procedures, Process

The study uses 3D seismic data and employs principles from geophysics, structural geology, sedimentology, sequence stratigraphy, and petroleum systems analysis in a comprehensive investigation to understand the Ceduna Sub-basin. Multiple 2D basin models were created for the AOI to test different scenarios in a detailed risk analysis of the petroleum system and its major controls. They were identified from a comprehensive literature review and after a thorough interpretation of the 3D seismic survey in the AOI.

Results, Observations, Conclusions

Results show that the best reservoir is located within the low stand systems tract (LST) deposits of the Hammerhead Sandstone (Ss) and Top Tiger Ss. The potential source rock occurs in the condensed high stand system tract (HST) deposits in the Base Tiger Ss and White Pointer Ss. 1D modeling showed that these source rocks may have generated hydrocarbons as their depth is <9 km. The critical moment during the source rock history was at 80 Ma coinciding with the deposition of the Hammerhead Ss.

Based on the regional structural framework, faults were initiated after source rock deposition. Several growth faults may pose a risk in terms of hydrocarbon leakage. Different 2D models have advanced the understanding of the petroleum systems in the AOI. The results showed that the most prospective areas are within a rollover anticline play and those areas where intra-formational seals are present. The model confirms that fault integrity represents the prime risk across the basin.

Novel/Additive Information

The current study contributes to understanding of the Ceduna Sub-basin by identifying two different plays in the AOI: rollover anticline and tilted fault block. Probability analysis of the different petroleum elements shows that the rollover anticline play has the highest geological probability of success.
Improved Imaging for Fault and Fracture Characterization: Southwest Onshore Abu Dhabi Case Study
Authors: Vargas Jose Edgardo , Shaukat Kashif , Elila Abusaa , Kumar Pankaj
Published: November 2018

The oil and gas industry has advanced over time in terms of seismic data acquisition. From conventional data acquisition to full/wide/multi-azimuth broadband data, there is an abundance of subsurface information aimed mainly at enhancing structural resolution, for improved prospect definition. Conventional seismic imaging tends towards the higher amplitude specular/continuous part of the seismic dataset for generating reflection events. During this process amplitudes or energy related to small scale features and faults can be contaminated, therefore in order to capture that information, it is essential to preserve the wavefield while imaging.
New Advanced PVT Course Helps Masters Students to Find Solutions to Real Industry Challenges
Authors: Williams John M.
Published: November 2018

This paper describes an educational case study covering the development and presentation of a new petroleum engineering master's course in advanced phase behaviour. Emphasis was placed on current industry challenges, interpretation of real data and visits to industry facilities. Special attention was given to fluid sampling experience. A variety of challenges and possible solutions are covered, and benefits to both full and part-time students, the next generation of industry professionals, are described.

The PE graduate program saw increasing numbers of students so more industry-related technical elective courses were required. Several courses were proposed and the Advanced PVT course was selected based on student preferences. The course was developed with a mix of lectures, computer laboratory classes, information group use, industry visits, presentations, and semi-obligatory attendance at local SPE meetings. Assignments included literature searches to find interesting publications about sampling, and personal project assignments. These were excellent for practising engineers who could analyse and report on field case studies.

Due to students’ various backgrounds, course content was modified to review material that is more basic. Industry students benefited from the opportunity to concentrate on specific challenges, discuss issues outside their company and learn from other participants, but had to manage the pressure of work. Full time students had more time for studies and out-of-classroom teamwork, but had little experience to share.

Choice of suitable course textbook is discussed, with details given of other supporting literature used, especially in the areas of fluid sampling and compositional analysis, where common phase behaviour texts are very limited. The course syllabus, detailed delivery techniques, example assignments and teaching tips are provided.

This is believed to be a novel case study, with no similar subject being found in SPE OnePetro publications. With continuing shortages in university PE schools, this material can help young faculty and adjunct faculty develop new courses more efficiently. Teaching at Masters level was seen to increase faculty access to students starting thesis research projects. A selection of industry participants’ recent experience in fluid sampling in the UAE is given and it is intended to incorporate it in future best practice procedures.
Gulf of Mexico Gas Export Modification Pipeline Installation – A Two Vessel Solution for PLEM Initiation Without a Pile
Authors: Samimi Mohammad , Aden Gerard , Guynn Richard Carl , Duffy Rebecca
Published: November 2018

The ∼18 km long 10" pipeline was installed by MCDERMOTT as part of a gas export modification development in the Gulf of Mexico. The pipeline was initiated with a 97 Te dual-hub PLEM at a water depth of 1535 m. The fast track nature of the project required the PLEM design and fabrication to be carried out in a short time in collaboration with the installation analysts to ensure installability. Initiation of the heavy PLEM at the end of a thin wall pipe in deep water posed considerable challenges in developing an installation methodology. After evaluation of all alternatives, employing an LCV to help with PLEM initiation in a flooded condition was deemed necessary. The LCV crane was deployed after PLEM reached a certain height over the seabed. A sequence of LCV and LV-NO105 movements, pipelay tower angle alteration, and pipe and LCV crane wire payout was followed to transfer the PLEM weight to the LCV crane and rotate it to horizontal. The rigging from a clump weight, which had been installed earlier as merely a contingency hold-back device, was then connected to the PLEM. A sequence of LCV movements, LV-NO105 movements, pipe and crane wire payout was followed to land the PLEM safely on the seabed. The crane wire was disconnected after laying a short length of pipeline on the seabed. The installation procedure was developed such that the sling between the contingency clump weight and PLEM remained slack. The PLEM weight was sufficient to provide the necessary horizontal holdback, after landing in the target box, for normal pipelay. The LCV crane operated in various modes (constant tension and active heave compensation) to ensure a smooth initiation process. Maintaining a smooth synchronization of activities shared between LCV and LV-NO105 was crucial to success of the project.
Tracking the Performance of Strategically Significant EOR Pilot: Zooming into Inter-Well Connectivity
Authors: Al-Qenae Amna , Chetri Hom , Kumar Priya Ranjan , Orjuela Jaime
Published: November 2018

North Kuwait has planned EOR activities to boost ultimate recoveries in multiple reservoirs. The reservoir with the highest priority on the EOR activity Gantt chart is Alkaline Surfactant Polymer (ASP) flood for Sabiriyah Mauddud due to significant incremental recovery estimated based on past SWCT tests. Prior to the initiation of ASP injection, slated pilot area is under intensive plumbing for insights into the inter-well connectivity. The paper proposal aims to share the actions taken up, analysis done and tracking of dynamic data for the area located within & adjacent to the EOR pilot area.

Data acquisition for the pilot area wells (4 injectors; 2 observation wells & 1 producer) has been done in two phases — (a) during the drilling of the wells, cores/ RFT pressures/ Log suites/ PVT samples have been taken and (b) during the injection of sea water into the EOR pilot injectors, time lapse pressure-production data/ surveillance information & tracer sampling/ analysis have been done to understand the inter-well connectivity; flag the uncertainties and de-risk the EOR pilot as a preparatory background for studies & ASP injection.

Connectivity between wells within the pilot & surrounding area under active water flood has been established. Pathways for quick fluid/ flux movements have been identified and calibrated with the petrophysical data. Tight zones or compartments within the pilot area have been examined. Uncertainty regarding thief zones within & outside the pilot area has been evaluated. A comprehensive data integration indicates that continuing with ASP injection will be optimal, with minimal losses/ escape to the area outside the 5-spot EOR pattern.

De-risking the upcoming ASP injection via proper data acquisition, interpretation & integration during the preliminary water flood flushing stage is one of the best industry practice.
Electrical Energy Savings in NGL Extraction Plant by Implementing ON/OFF Sequence Logic Control for Fin Fan Coolers
Authors: Bametraf Rashed
Published: November 2018

This presentation describes the efforts undertaken by ADNOC Gas Processing's Buhasa site to save electrical energy in the NGL extraction plant by minimizing fuel gas consumption in power generators. This also contributes to a reduction in flue gas emissions.

During 2017, ADNOC Gas Processing pursued actions to save electrical energy in air fin coolers by implementing a sequential ON/OFF control logic to achieve a saving of 1,265,600 kWH. The implementation did not occur any costs, as the project was realized completely with in-house resources.
Successfully Deploying & Retrieving 6,200ft of Perforating Guns Over Six Challenging HPHT Wells
Authors: Gopalan Bathmanaaban , Craig Steven , Chong See Yung , Bouzaine Cherif , Pouget Pascal
Published: November 2018

A six wells campaign to single-run perforate long completion intervals was undertaken in Brunei. The offshore field presented inherent challenges due to high pressure, temperature and long perforating intervals. A major challenge was to perforate underbalance to reduce potential permanent formation damage. The solution proposed for this high pressure and high temperature (HPHT) perforation was to use a high grade of coiled tubing (CT) with live-well gun deployment and retrieval system. The live-well gun deployment system utilizes perforating connections designed to support the gun weight, firing shock loads and ballistic transfer. The connection and break-out are facilitated via specialized rams in a dedicated BOP body in live well conditions. A 130-ksi yield strength CT string was engineered to withstand high tensile forces from running up to 1,150-ft of guns to depths of 18,000-ft in near vertical wells and provide a suitable safety margin when high collapse pressures were present. However, when perforating with long gun lengths, high dynamic shock loads will be experienced by the CT string. Thus, for all the wells, two software systems were used, traditional CT force analysis program and a gun force software for the short duration transients present during perforating. There were numerous continual improvements implemented during the duration of the campaign and one of them was maximizing the underbalance perforation up to 5,500-psi. Although such high underbalance was not a standard practice in the industry with CT, it was carried out after a comprehensive study and review to perform the operation safely and efficiently. There were no recordable safety issue throughout the two years campaign where more than 6,230-ft of guns were ran and live-well reverse deployed. The campaign was successful and operator expectations met. This paper outlines the characteristics of this campaign from the planning stage up to operational execution and efficiencies recorded over the six wells campaign. Well control mitigation practices and general contingencies will be detailed. This paper will act as a suitable reference for future operations.