bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of NanoActive® Sulphur Scavenger NASS for H2S Removal in the Oil and Gas Industry
Authors: Whittaker S. L.
Published: November 2018

This paper introduces the advanced technology NanoActive® Sulphur Scavenger (NASS), a Zinc Oxide (ZnO) based nanostructured material, and examines its applications across a range of problems faced by the petroleum industry. Principally, the neutralization of hydrogen sulphide (H2S) from crude oil and gas phases, resulting in the reduction of operational risks, environmental impact and pollution, and increased productivity and profitability.

NASS is a non-toxic, non-hazardous, non-dangerous substance. It is manufactured using advanced chemistry nanotechnology processes, creating unique properties (such as increased surface areas, large porosities, unique morphology, additional surface functional groups) causing enhanced chemical reactivity and increased chemical selectivity. The inherent chemical reactivity centers on a high surface area. Due to their exceptional porosity, NanoActive® materials have demonstrated the ability to destructively adsorb a wide range of harmful chemicals and odor causing compounds.

NASS’ two-step decomposition mechanism (adsorption by physisorption, followed by nonreversible chemical decomposition) substantially enhances its detoxification abilities because decomposition is less dependent on temperature. Use of NanoActive® technology improves scavenger efficacy between 4 and 6 times, depending on feed composition.

Currently, the range at which NASS stand-alone systems are economical is up to 10,000 ppm H2S in liquid streams, and 1,000 ppm H2S at 320 m3/hr to 10,000 ppm H2S at 30 m3/hr in gas streams. At these levels, NASS reduces H2S to 0 ppm. For higher concentrations, NASS is used in combination with existing removal technologies.

NASS mode of operation

Containment. Chemicals and vapors are taken up by adsorption into the large, porous surface of the NASS molecule.

Adsorption. Chemicals and vapors bind to the surface of the NASS molecule.

Neutralization. Chemical reaction occurs to change the toxin to non-hazardous.

NASS solutions can be applied to a wide range of challenges:

The earlier in the process NASS is deployed (for example, near the wellhead), the better for the process overall, with many downstream problems eliminated altogether.

Removal or reduction of H2S in upstream production improves safety, and reduces corrosion and byproducts, thereby reducing flaring and disposal, and producing sweet gas for power.

Reacted NASS is transformed into zinc sulphide (ZnS), which, along with any surfactant and inorganic materials, is non-toxic and does not require hazardous waste disposal, except where mandated by local legislation.

With the adoption of this technology, the current philosophy of H2S "containment and control" changes to "elimination by neutralization". It delivers significant HSE benefits, and reduces operational risk. It is today's Best Available Technology Not Entailing Excessive Cost (BATNEC). It allows development where currently there are technical, regulatory or economic barriers.
Innovative People Diversity & Inclusion Program - Key PDO FDC Business Enabler
Authors: Muhiddin Junaid G , Al Adhoobi Azza , Al Shukri Ibrahim , Unal Emre , Hersby Mette , Al Hinai Hannat
Published: November 2018

Three years ago, People Survey scores on PDO Field Development Center (FDC) Diversity and Inclusion (62%) were well below Top Quartile & PDO ‘Petroleum Development Oman’ average. The FDC were determined to turn this around. D&I was made integral part of FDC's people program.

The PDO D&I vision was firmly embraced by FDC and the statement is "to promote an inclusive workplace free from discrimination, bullying and harassment which celebrates diversity & provides all with an equal opportunity to succeed".

A three prong FDC D&I strategy was developed and enforced by a newly energized FDC People Team, the 3a strategy is: awareness, absorb, action and engage staff.

Raise AWAREness by: Prioritizing group learning events within FDC hosted by in-house subject experts, acknowledging key nation/religious events of employees in FDC, introductory talks on key processes and standards related to D&I. ABSORB is the soak & reflect mechanism driven by: voluntary circulation/rotation of the FDC Family Values Trophy to colleagues exhibiting one or more of D&Ivalues, ensure ADPs/coaching plans in place & perform people capability reviews twice a year. ACTION out the values through and engage the staff through: regular coaching/mentoring sessions, organizing FDC family day out event, Leader to Employees birthday acknowledgement gifts and increase staff Engagement through sustaining ‘Lunch with leader event, ‘leader Assist Day’ and introduction of ‘Talented People coffee corner event’.

As a result of this structured approach to tackle the D&I performance. The Field Development Center achieved Top Quartile performance with noticeable improvements such as: 2017 FDC People Survey D&I score was 85% which is Top Quartile. (in comparison to 2014 score of 62%).High level of engagement (85% response rate for whole FDC on last People Survey).High level of energy in FDC community as acknowledged by line director and observed in technical and social events.
Simulation Model for Optimization of Gas Production System Through Integration of Sub-Surface and Surface Facilities
Authors: Mumtaz Yasir , Ur Rehman Awais , Junaid Shaikh Muhammad
Published: November 2018

Mari Gas Field; discovered in 1957, is one of the oldest and mature fields of Pakistan and currently the highest gas producing field of the country. Mari Field has vital role in ensuring the food security of Pakistan as it is meeting gas needs of 87% of Fertilizer Industry. Field has been developed in multiple phases with 97 producing wells and complex gas gathering network of 284 km. In recent past few years, the country's supply and demand gap for gas is on widening trend. In order to support national energy needs, MPCL management decided to take initiative of executing gas incremental and optimization drive for playing its part in meeting the crucial energy demand of country. Furtermore, it was also matter of great importance to sustain the enhanced production plateau and meeting production & revenue targets.

Multidisciplinary teams were formed for evaluation of complete system from Reservoir to delivery end. Integrated approach was adopted for assessment of system at existing state of production and targeted production rate as de-coupled models would have not served the purpose well in this particular case. This study covers the integration of sub-surface and surface facilities; linking reservoir simulator at IPR Level, through in-house simulation model developed in commercial simulator. Keeping in view the target of study i.e. incremental and sustained production, reservoir rates were constrained and hence semi-implicit approach was used instead of fully implicit modeling which saved a lot of computation time and avoided complexities. Coupled model was simulated for predicting futuristic behavior of system at enhanced production which identified bottlenecks and integrity problems in existing system and also proposed the solutions through series of sensitivities analysis. This exercise triggered the proactive approach for solving system issues and kicked-off proper surveillance of system which are mandatory to sustain the desired production plateau and ensure the mechanical integrity of system. This study further emphasized that evaluation of complete system through integrated modeling can save compression cost at by de-bottlenecking the existing infrastructure.

At present, the field is producing at 20% incremental volume over and above of initial base volume and future plans have also been formulated to sustain the production plateau as per reservoir simulator.
Use of New Wireline Conveyance Technologies on an Offshore Abu Dhabi Well Saves Significant Rig Time and Results in Improved Sonic and Nuclear Magnetic Resonance Data Quality
Authors: Brindle Frank , Rafique Maqsood , Thatha Rajesh , McCormick Stephen , Escott Samuel , Bajwa Haroon , Cocagne Michael
Published: November 2018

Drill Pipe conveyance (TLC/PCL) of wireline logging tools or Logging While Drilling (LWD) is usually required for high deviation / high differential sticking risk logging scenarios. These are costly in terms of rig time and service company costs. This paper details how a full suite of high-quality open hole log data was obtained on wireline in a high angle 16,500ft wellbore utilizing a new conveyance system and a polymer-locked high strength cable.

The new conveyance system, utilizing wheeled carriages and a holefinder with nose angled upwards, takes a holistic approach to tool conveyance, reducing drag while ensuring both correct tool orientation and optimum contact and standoff for each logging service. Management of tool centers of gravity relative to the wheel axes ensures correct orientation. The reduction in friction due to wheeled carriages vs weight and cable load is modelled before the operation in order to ensure successful runs, both into and out of the wellbore. Polymer-locked high strength cable significantly increases maximum safe pull capability and enhanced data transmission technology allows faster logging speeds, greater rig time efficiency and reduced sticking risk.

The wheeled carriage system enabled conventional logging in a high angle well, minimized stick-slip and reduced differential sticking risk. The unique holefinder prevented tool hold up during descent. The Vertical Seismic Profile (VSP) run (the only run not able to utilize the system due to tool size and design) was held up on a ledge above the lowest reservoir of interest. The high strength cable allowed safe retrieval of tools (over-pull > 6000lbs) in one particularly sticky zone.

In a world first, an array sonic tool was centralized through management of weighted and eccentralized tool sections using bespoke wheels. This eliminated the drag inherent to traditional methods of sonic centralization (centralization using powered calipers and/or spring centralizers), resulting in excellent data quality. Nuclear Magnetic Resonance logs were obtained by orienting the tool sensor with wheels which utilized tool weight to provide sensor application force. This removed the need for additional centralizers, resulting in data devoid of stick-slip artefacts (an issue in previous wells).

The formation fluid sampling run was conveyed on drill pipe, taking 6 days of rig time. There are further significant efficiency gains to be had on future operations by using the new conveyance system on sampling tools (operators have already moved in this direction in the Gulf of Mexico).
Maximizing Pipeline Flexibility with Drag Reducing Agents
Authors: Johnston Ray , Lee Yung
Published: November 2018

Drag reducing agents (DRA) have been applied to pipelines since they were first commercialized by Conoco, Inc. in 1979, and have proven to be a reliable tool for the pipeline industry. Over the past 40 years, adoption of DRA has been widespread across the globe, in a broad range of climates and in a variety of hydrocarbon fluids.

DRA are valuable tools as they can reliably provide flexibility in the operation of a pipeline. Because DRA can be applied over a range of dosage levels in the pipeline, they offer a range of options in terms of operating points at higher flow rates or lower pressures. DRA can be used to substantially increase flow rate in a capacity limited pipeline, or maintain flow rate in a derated line. They can also be used for energy savings, bypassing pump stations. DRA can bring substantial value to pipeline operations through aversion of flow loss, and through minimizing capital and energy costs.

The latest generation of DRA have demonstrated very high performance potential in terms of drag reduction performance and supply logistics. New pipelines are increasingly considering DRA usage and flexibility during the design stage, which can minimize capital and operating costs.
First Implementation of Real-Time Subsurface Monitoring for Cuttings Reinjection Offshore Abu Dhabi
Authors: Gumarov Salamat , Benelkadi Said , Bianco Eduardo , Woolf Shaun , Hardy Chris , Ido Hisataka , Tanaka Manabu , Tominaga Naohiro , Yahata Kazuhiro , Okuzawa Taker
Published: November 2018

Management of drilling wastes presents major challenges during drilling operations in environmentally protected areas. An Abu Dhabi offshore field development project selected cuttings reinjection (CRI) services as an appropriate solution for waste management.

Although CRI is a proven technology in the region, fracturing injection always inherits its own containment-related risks. To prevent all possible failures that were experienced earlier in the industry globally, a novel real-time monitoring and analysis of fracturing injections data was introduced.

A comprehensive front-end engineering design (FEED) study was performed to evaluate the feasibility of CRI techniques by selecting a suitable injection formation and designing a CRI-dedicated well, surface facilities, slurry testing, and appropriate operations execution plan.

The CRI well was drilled and completed to accommodate waste volumes. An assurance program based on industry best practices was used to support zero solids settling, fracture, or perforation plugging.

To achieve on-time intervention, the first real-time CRI data transfer through a satellite-based network to a support center staffed by global experts in Abu Dhabi was deployed to analyze fracture injection and shut-in pressure responses for early identification of possible risks and to map the fracture waste domain.

The project has been operated successfully since its inception with more than 300,000 bbl of drilled cuttings and drilling waste fluids injected since July 2016. No injectivity issues were experienced during drilling waste fluids injection. Several on-time interventions had been made to prevent well plugging and to maintain surface injection pressures within normal ranges.

Real-time data streaming has made a step-change improvement in the data delivery process, monitoring, and fracture pressure analysis. It creates a direct link between the wellsite and worldwide multidisciplinary technical expertise centralized in Abu Dhabi and provides visualization capability at any time and to any where to all personnel involved in the project.

This step change in monitoring CRI operations provides an acquisition-to-answer" integrated solution, mitigates the injection risks, and enhances the intrinsic value of CRI services.

The paper shares the experience of implementing the novel real-time CRI subsurface injection assurance program dedicated for cuttings reinjection operations. Real-time support from multidisciplinary experts provides live injection monitoring and fracture waste domain mapping for highly complex and risk-prone subsurface injection environments with stringent regulations
Edge Analytics at the Wellhead: Designing Robust Machine Learning Models for Artificial Lift Failure Detection
Authors: Boguslawski Bartosz , Boujonnier Matthieu , Bissuel-Beauvais Loryne , Saghir Fahd
Published: November 2018

This paper outlines the challenges and constraints related to deployment of Machine Learning solutions for rod pump abnormal states recognition and diagnosis at the wellhead. Those abnormal states may lead to a failure or to non-optimized production. Particular focus is on two main aspects: 1) Develop a robust Machine Learning model & IIoT architecture to predict rod pump failure directly at the wellhead, 2) Ensure high level of pump failure prediction through Machine Learning to ensure operator confidence.

To the best of our knowledge, this is the first-of-its-kind IIoT Edge Analytics solution which provides operators with the capability of automated Dynagraph Card recognition directly at the wellhead via Machine Learning models. This solution also addresses end-user requirements in terms of confidentiality and communication infrastructure.
Standalone Cased-Hole Formation Evaluation and Uncertainty Propagation to Increase Well Deliverability in Challenging Environments
Authors: Vinci Fabio , Pirrone Marco , Galli Giuseppe , Macaluso Daniela , Rocco Francois , Zarauti Roberto
Published: November 2018

In new wells with hole stability problems, which require to be cased and cemented immediately, and in old wells without a complete or reliable log dataset, a formation evaluation by means of quantitative open-hole (OH) log interpretation is not possible. Cased-hole (CH) logging can represent the only solution, despite being usually considered highly uncertain. This paper discusses the standalone use of CH logs, integrated in a probabilistic framework, for petrophysical characterization and uncertainty propagation purposes.

The approach consists of a full statistical workflow aimed at a formation evaluation with only CH logs as input, also including capture cross-sections, carbon/oxygen ratios and inelastic spectra. Several wells with complete OH petrophysical characterization have been used to define the rate of success of this methodology in different scenarios. Furthermore, a Monte Carlo framework is introduced to account for the uncertainty quantification of the CH outputs. The final outcome is the set of probability distribution functions of the petrophysical properties, the most probable scenario and the associated uncertainty.

Three real operative applications, in scenarios with no OH logs available, are presented: an old well without a complete/reliable OH log dataset (gas- and oil-bearing sandstone reservoir with variable salinity), and two new wells with hole stability problems (in a sandstone and in a carbonate oil-bearing reservoir at high formation water salinity). In the latter cases, numerical simulations are performed to correctly handle mud-filtrate invasion effects for a robust modeling also in the shallow zone investigated by CH logs. In all these challenging conditions, a complete formation evaluation has been obtained, and successfully used to select proper intervals to perforate. The increased hydrocarbon production driven by the outcomes of the standalone CH characterization further validates the efficiency of this method.

Though CH logging is a well-known technology in reservoir monitoring, its successful standalone use for reliable formation evaluation can represent an important step forward in reservoir characterization processes, in all those cases where OH data are not available or too risky to acquire. Finally, the value of uncertainty analysis has a huge relevance for appropriate production optimization and reservoir modeling strategies.
Pore-Scale Network Modeling of Petrophysical Properties in Samples with Wide Pore Size Distributions
Authors: Hakimov Nijat , Zolfaghari Arsalan , Kalantari-Dahaghi Amirmasoud , Negahban Shahin , Gunter Gary
Published: November 2018

Archie's law is commonly used for the estimation of petrophysical properties of porous media linking electrical resistivity to water saturation. Therefore, low resistivity formation is expected to have high water saturation and hence, high water production. This, however, is not the case for many reservoirs around the world, for which low resistivity pay zones have been reported with very low or none water cut.

One of the main causes of Low Resistivity Pay (LRP) phenomena, especially in carbonates, is microporosity. Due to their small pore sizes, micro-pores have much higher threshold capillary pressures than macro-pores during drainage in the water-wet samples which resembles the original state of reservoirs before oil migrations. Because of that, we often find formations in which micro pores and macro pores are saturated with brine and oil, respectively. This indicates that there is a correlation between pore fluid occupancies and pore size distributions. The existence of connected pathways through micro-pores that are fully saturated with a conductive phase (i.e., brine) creates ‘shortcuts’ for the electrical current which causes short circuit and, ultimately, lowers rock resistivity measured from log analysis.

The purpose of this work is to investigate the impact of microporosity on the electrical properties of porous media through pore-scale network modeling techniques. To achieve this, a tortuous pore network is constructed on 2D rectangular regular lattice to represent macro pores and throats in the network. Next, the macro network is modified to include micro-pores. This has been done by adding a small rectangular lattice network of micro pores and throats. Radii and lengths of each element are chosen from the pre-specified ranges. This is done carefully to ensure that all networks of different scales fit geometrically within the lattice of a given size. We are specifically interested to investigate flow and electrical properties as a function of the locations, dimensions, and orientations of the micro-porosity regions. To achieve this goal, a comprehensive set of sensitivity analyses are done to assess the impact of various parameters including number of pores, tortuosity, geometry and location of microporosity (i.e., parallel or in series, continuous or non-continuous). The results are compared against Archie's equation, which is commonly used in the industry for log interpretation. This work helps to further expand the use of this equation for field applications, specifically, for formations containing rocks with wide pore size distribution.
Talent Management Strategies, Programs and Results
Authors: Al Yaarubi Hilal Abdullah
Published: November 2018

The objective of this paper is to share Occidental Oman's Talent Management strategies, development programs, and the results achieved on the ground. The focus will be on three major pillars; (i) understanding the adopted talent management strategies/framework and the value chain as we materialize the strategies on ground, (ii) hiring strategies, and (iii) ensuring we are developing the required talent development programs to accelerate the learning and time to autonomy.

To give the audience a better understanding of our adopted talent management strategy and our sustainable nationalization program, I'll present one of the successful heavy oil projects as a business case, the Occidental Oman Block 53 Mukhaizna Project. Block 53 is a heavy-oil field (approximately 15.5 API). An oil field of such nature requires a unique set of technology and equipment to get the oil from the ground. Accordingly, Occidental Oman constructed one of the world's largest and most advanced mechanical vapor compressors, also known as MVC. Considering that Mukhaizna is the only MVC in the region, and taking into account the unique technology/equipment utilized in the project, there was an understandable lack of knowledge and expertise in the local and regional market. As a result, Occidental Oman had to develop a hiring and skills development strategy to be able to commission and operate the project to achieve the required targets.

The comprehensive framework adopted by Occidental Oman to support this project considered the three main pillars highlighted below, which resulted in supporting the business with the required workforce, as well as ensuring the development of local capabilities for the project.
A New Collaborative Workflow to Optimize Well Placement in the First Unconventional Horizontal Well in the United Arab Emirates
Authors: Fares Wael , Aki Ahmet , Essam Ramy , Vican Kresimir , Negm Ehab , Van Laer Pierre
Published: November 2018

A horizontal well was drilled in an unconventional source rock for the first time in the United Arab Emirates using advanced logging-while-drilling (LWD) high-resolution microresistivity and near-bit gamma ray imaging sensors. The well plan required locating a ±3 ft true vertical thickness (TVT) source rock sublayer; this sublayer was located within a giant undeveloped unconventional carbonate reservoir in a middle Cretaceous carbonate sequence onshore Abu Dhabi. Additional planning and drilling challenges included the absence of offset wells in this field and the associated structural geological uncertainty. Consequently, a vertical pilot hole was drilled to evaluate the local geological structure and to determine the reservoir properties.

For source rock reservoirs, a unique and collaborative approach has been developed that enabled the associated specific challenges to be addressed. This approach was built on reservoir knowledge to help determine where and how to drill, as well as where and how to fracture, to optimize each stage of the field development.

A well placement and geosteering methodology/workflow was developed and applied. This workflow used azimuthal high-resolution microresistivity and near-bit azimuthal gamma ray sensors to land and geosteer the well within the thin target layer, while maintaining the planned trajectory with minimum borehole tortuosity using real-time drilling optimization. The high-resolution microresistivity images were analyzed to classify image patterns to correlate to reservoir units for further field development and to better understand the reservoir flow units. The laterolog resistivities were also determined to be better suited for inferred Rt and Rxo measurements for petrophysical formation evaluation than the modeled electromagnetic wave resistivity inverted values.

The well was successfully drilled, and the geosteering objectives were achieved with 100% reservoir contact. The field development strategy for the horizontal drain in the undeveloped source rock is being reviewed, based on these recent data, to benchmark and optimize well placement, formation evaluation, and production technologies, to evaluate the economic potential of this unconventional reservoir.

This paper presents a case study after completing the first unconventional horizontal well in the UAE and describes the integration of fit-for-purpose geosteering technologies and optimized drilling performance to maximize reservoir contact and improve reservoir insight. Benchmarking of cost effective well placement and petrophysical data gathering requirements for the future field development program are also discussed for maximizing asset value.
Virtual Reality in D&C: A New Way for Immersion Training and Operation Simulation
Authors: Maliardi Alberto , Ferrara Paolo , Poloni Roberto , Spagnolo Salvatore , De Marchi Eliana , Grasso Tiberio , Allara Paolo
Published: November 2018

Nowadays the use of Virtual Reality is quite common in many fields of technology and consumer market. For drilling applications, it is mostly used for rig crew training on Drilling Simulators1 or virtual touring of site locations. Moving from this state of the art, Eni, in collaboration with Saipem, developed a new portable virtual system for training immersion and operation simulation in order to improve: rig & equipment knowledge and operation know-how, support and safety awareness.

A last generation semi-sub rig, for deep water drilling, was fully virtualized integrating four main characteristics: walk-through rig and equipment,operation play back,safety interaction,well simulation

The System takes advantage of a field database of more than 300 drilled wells, while well simulation is to be interfaced to dedicated command modules including a remote location driller cyber-base.

The System is accessible on PC, in dedicated 3D-rooms and with suitable virtual reality headsets. It has been initially used for enhancing the training of new drilling engineers and supervisors, with possibility to improve their safety induction as well as rig and well operation knowledge through immersive experience on various drilling events. The System also includes a collaborative environment that is useful for immersive and realistic training but that can also be used for well planning, operation preparation and field support. As a complement to global approach in conventional planning, it is possible to locally analyze and experience in advance various specific and complex drilling operations and events, with the aim to optimize them, prevent problems and enhance operation safety.
Improving Class G Cement Carbonation Resistance Using Nanoclay Particles for Geologic Carbon Sequestration Applications
Authors: Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Mahmoud Mohamed
Published: November 2018

The hydrated products of Portland cement drastically change after exposure to CO2 rich brine, compromising the cement physical properties, especially, the compressive strength. This phenomenon is known as strength retrogression which occurs when the Ca/Si ratio of the cement hydrated products is close to 2.0.

Previous studies showed that the use of silica flour enhances the cement resistance to the strength retrogression because of the formation of long silica chains. In this work, the influence of modified montmorillonite nanoclay (NC) particles which are nanoparticles of layered mineral silicates, on the strength retrogression resistance under carbonation process was evaluated.

Two cement slurries with 0% and 1.0% NC were prepared and tested for the change in their different properties of compressive and tensile strengths, porosity and permeability with the carbonation time for 20 days of reaction into 0.5 M NaCl solution at 95°C and 10 MPa. After 7 days of preparation, the properties of the samples were tested, then samples were immersed into the CO2 saturated brine, after 5, 10, 20 days of reaction some samples represent each specimen were collected and tested for the same properties mentioned earlier.

The results revealed that incorporating the NC particles enable to decrease the decline in the compressive strength from 12.62% to 2.13%, and the tensile strength reduction reduced from 8.21% for the base samples to 1.72% for the NC-based samples after 20 days of reaction. The porosity decline was also reduced to be 6.49% compared with 17.58% for the base samples (i.e. without NC), while the permeability reduction changed from 19.51% for the base cement to 8.70% for the NC-based cement.

The permeability reduction, as well as the chemistry of the NC particles which enables them to accelerate the hydration process, are the main mechanisms which enhance the cement resistance to the carbonation.
Combat Unpredictable Losses during Casing Cementation in a Compartmentalized Structure, Nong Yao Field, Gulf of Thailand
Authors: Tongkum Tossapol , McManus Ian , Abu-Jafar Feras , Thanasarnpisut Viraphon , Vargas Bermea Jorge Andres , Kaewpraphan Kingkarn , Wuttikamonchai Pakaporn
Published: November 2018

Lost circulation, while cementing, compromises the objectives of cementing an oil or gas well. Losses encountered during cementingcan cause a weak casing shoe, poor zonal isolation, early water breakthrough for an oil producer, as well as increasing the possibility of costly intervention work. Execution of primary cementing operations can be subject to unplanned circumstances; when a slurry is being pumped or displaced and losses are recorded, in most circumstances the operation switches to damage limitation by slowing down the pumping rate.

The Nong Yao field (Figure 1)is characterized with an interbedded unconsolidated sand / clay lithology within a highly compartmentalized structure, and as such, well construction operations have encountered unpredictable lost circulation during 7-in. casing cementation (but rarely during the drilling phase). Over 60% of the wells recorded losses during 7-in. cementing; it became evident that a proper loss mitigation plan was necessary to combat lost circulation and improve the probability of successful cementation execution. Although the primary objective is to achieve zonal isolation, equally as important for Nong Yao drilling operations are provision of annulus barriers, slurry compressive strength development, "gas tight" qualities, optimum slurry Thickening Time (TT) to allow for safe batch drilling operations.

Figure 1 Nong Yao field localization

To overcome the challenges, an "out of the box" approach was essentialwhich yielded two innovative solutions: i) a combination of advanced lightweight cementwith engineered reticular fiber (ERF) systems, which allows safer placement of the cement in the annulus, while minimizing the potential losses; ii) a combination of several lost circulation materials (LCM) in an optimized ratio in an engineered fiber-basedlost circulation weighted spacer package, which has an additional function of preventing and mitigating risk of losses during cementing. This approach was intended to reinforce the loss zones by using the four-step methodology; disperse, bridge, plug and sustain. The severity of lost circulation while cementing was significantly reduced without compromising the abovementioned objectives.

This paper will discuss the successful implementation of the new approach solution by integrating different technologies to overcome the challenges of unpredictable losses during cementation. Two case histories from numerous jobs will be discussed with cement post-job evaluation via playback simulations and standard cement bond logs, which validates that the new approach increases the chance of achieving well objectives. Consequently, the risk of unplanned (UNP) operations and costly remedial operations are substantially reduced.
Measurement of Temperature in Deep Reservoir Zones by Mobile Sensor Devices
Authors: Li Bodong , Gooneratne Chinthaka P. , Bassam Mohammed K. , Zhan Guodong
Published: November 2018

The second generation temperature microchips were field tested in a deep reservoir section of a well. Out of 140 microchips deployed, a total of 50 microchips with memories were recovered from the well. This was accomplished even with the well experiencing partial lost circulation during the operations. The recorded temperature profile revealed the temperature distribution at different depths and positions inside the drill string/casing. Conventional methods of accessing downhole information would risk the potential of stuck pipe, and associated non-productive time due to frequent loss circulation situations in such wells. The obtained downhole dynamic temperature can be used to optimize the cement slurry and tailor thermal activated loss circulation materials in the current as well as future wells.
Evaluation of Rudist Depositional Environment using X-ray CT Scan Late Cretaceous Cenomanian in Offshore Abu Dhabi
Authors: Yamanaka Motoyoshi , Nanjo Takashi , Taniwaki Takashi
Published: November 2018

Rudists are a group of strange shaped marine bivalves lived in the Tethys Ocean from the Late Jurassic to the Late Cretaceous. The rudist-bearing carbonates form a lot of oil and gas reservoirs in the Middle East. Therefore, the taxonomy, morphology, paleo-ecology of rudists is important to understand the rudist-bearing carbonate reservoir features for oil exploration and development. However, it is difficult to understand these characters of rudists because we can't collect whole rudist samples from the underground oil and gas reservoirs through core sample. X-ray CT is a useful method to visualize three dimensional rudist images with non-destruction of the core. Hence, X-ray CT has a potential to obtain the information of the taxonomy, morphology and depositional environment of rudists from core information. We conducted the X-ray CT scan to the reservoir formation (Formation A) of the Cenomanian age using core slab samples of Well #A and Well #B in the Abu Dhabi oil field. The some rudist fossils were observed on the cutting surfaces of slab cores in the both wells. However, the three dimensional morphology of rudists were not identified inside of the slab core. On the CT images, some autochthonous rudists were identified and it made the colony in Well #A. This rudist is standing position and suggesting original position of depositional environment from Cestari and Sartorio (1995). We demonstrated to be able to obtain the morphology from the slab cores with non-destruction using X-ray CT scan in this paper. Now we are challenging to make the high resolution 3D image modeling of rudists based on this X-ray CT result. This paper is summarized that usage method of the X-ray CT result to understand taxonomy/morphology and depositional environment from three dimensional position of rudists In addition, in the future technique, this paper suggested that combined technique between X-ray CT of core and FMI may reveal more comprehensive depositional setting such as direction of paleo ocean current and paleo wind in the future.
Impact of Seismic Acquisition and Processing Techniques in Challenging Subsurface Imaging; Block G11/48, Gulf of Thailand
Authors: Kaewprain Phansakorn
Published: November 2018

The availability of high quality seismic data is of critical importance in trying to unravel the complexities of subsurface geology. This paper illustrates how proper selection of seismic acquisition parameters and data processing techniques can successfully overcome geological difficulties and minimize uncertainties when exploring for hydrocarbons in the northern part of Block G11/48, Gulf of Thailand, without compromising safety and cost efficiency.

Fluvial and fluvio-deltaic sediments of early to mid Miocene age in low relief faulted structural traps constitute the most common hydrocarbon habitat in the area of investigation. Amplitude support in identifying potential targets is also proven by nearby discoveries. To fully evaluate the exploration potential of this area, a 3D seismic acquisition campaign was successfully carried out using a high-end seismic vessel and without HSSE incidents.

The Nong Nuch dataset was acquired using a 10 deep-flat towed 5.1 km streamer configuration with triple sources to increase cross-line resolution and reduce operational time. This long streamer length relative to the target depth provides necessary information to Full Waveform Inversion and Q-tomography in order to correct push-down effects in broadband anisotropic Pre-stack Depth migration. The dataset also helps to obtain high accuracy velocity model, de-multiple and quantitative interpretation. This acquisition and processing approach significantly improved the ability to image thin reservoirs and correct push-down effects and energy absorption due to gas clouds or unconsolidated sea floor channels.

The large streamer spread and deep tow did not create any major problems throughout the acquisition. The implementation of broadband acquisition and leading edge processing techniques resulted in good signal to noise ratio as well as high vertical and horizontal resolution with minimal acquisition footprint. In addition, long offset data acquisition contributes to successful attenuation of short and long period multiples. Channel-like features and fault plane reflections are very clearly imaged in the dataset, helping to better understand of the depositional environment and structural setting of the area. Severe push-down and abnormal amplitude absorption effects were significantly corrected and compensated by building a high resolution, Full Waveform Inversion (FWI) derived velocity model as well as application of reflection tomography and Q-tomography techniques. Thus, definition of potential traps beneath gas clouds has significantly improved.
Boosting Rock Facies Prediction: Weighted Ensemble of Machine Learning Classifiers
Authors: Shashank Sharad , Mahapatra Mahabir Prasad
Published: November 2018

Modern day challenges in geosciences are "multidimensional," and as the amount of E&P data has proliferated in recent decades, machine learning techniques to handle this data have proliferated as well. However, different algorithms may outperform each other for different data instances. Exploiting this characteristic, we propose a workflow for boosting the prediction accuracy using a weighted ensemble of multiple machine learning classification algorithms to solve the classical problem of supervised rock-facies classification from well logs.

Instead of trying to identify the perfect classifier for rock facies classification, we propose a weighted ensemble of three base level classifiers: extremely randomized trees, support vector machines, and gradient boosting algorithms for obtaining a more generalized predictor. The hyperparameters for each model are optimized using grid search, cross-validation and learning curve assessment, thus tuning the classifiers while reducing overfitting. The "best model" predictions from each classifier are then fed to a weighted-majority rule classifier for obtaining more generalized facies predictions by accentuating each model where it performs best and discrediting a model at instances of poor performances.

This approach applies a robust workflow to address the problem of identifying the interrelationship of wireline logs and core cuttings, a crucial step for predicting reservoir facies in new wells. A family of popular machine learning algorithms is trained on five well logs and two geologic indicator logs for classifying the log samples into nine discrete facies. We discuss the process for evaluating and thus ranking these algorithms on blind data. Because core data are often limited, we also propose an efficient solution to reduce the inherent bias and variance properties of these classifiers. High bias is reduced by hyperparameter tuning on cross-validation sets, and high variance is checked by plotting learning curves of training and test scores as a function of training set sizes. Extremely randomized trees, support vector machines, and gradient boosting have shown low bias, low variance, and highly correlated test predictions, which made them the perfect candidates to be fed into the second level weighted voting classifier. The voting classifier combines these similar and conceptually different classification models for facies classification via majority voting, thus balancing their individual weaknesses. The weighted classifier has been shown to have a higher prediction F1 score than individual classifiers.

This advanced workflow will be beneficial to geoscientists who must routinely solve well data classification problems. In addition to boosting facies prediction in new wells, this novel approach disseminates important machine learning concepts transferrable to other supervised classification and regression problems in exploration workflows.
Mitigating Lost Circulations for Drilling Losses-Prone Wellbores by Accurately Predicting the Fracture Gradient with an Integrated Geomechanics Approach
Authors: Fang Zhi , On Chee Khong , Zamikhan Norshah , Borah Jahnabi , Spanninga Christoffer
Published: November 2018

Lost circulation is one if the top concerns of drilling nearly 50 wells penetrating heavily depleted shallow reservoirs in a recent drilling campaign. Three of the first 5 wells observed losses with the fifth losing a hole section during drilling. A fracture gradient (FG) model developed by an integrated geomechanics approach assessed those five wells and indicated that the equivalent circulation density (ECD) was higher than the predicted FGs in the three losses wells but lower than the FGs in the two non-losses wells. The FG model guided the drilling team successfully re-drilled the lost section of the fifth well and accomplished another two wells by controlling the ECD under the predicted FGs. The sixth well had a predicted FG lower than the ECDs used in the fourth and fifth wells and could have encountered massive losses or losing a section again without the FG model. The FG model was further promoted to minimize the lost circulation risks by predicting the FG of additional 14 wells with 12 having been successfully drilled. It has saved about USD 500k per well on average with mitigating the lost circulation risks for those losses-prone wells by the integrated geomechanics approach. This approach is extended to assist managing the drilling safety and cost savings for remaining wells.
Viable Solution to Drill Through Induced Losses in Limestone Formation in Extended-Reach Wells in UAE Offshore
Authors: Doutoum Mahamat Habib Abdelkerim , Musabbeh Al Azizi Badr , Bermudez Alvarado Romulo Francisco , Eduardo Navas Luis , Popatrao Salve Bhushan , Akyabi Khalid , Kustanto Sigit , Kapoor Saurabh , Jain Bipin , El Hassan Azza , Rahhal Gilbert
Published: November 2018

Lost circulation is a widespread problem in many formations in the United Arab Emirates, including Shallow Unconsolidated, Shallow Vuguler and Limestone. To minimize losses during drilling and cementing, several types of lost circulation solutions such as bridging agents and surface-mixed and downhole-mixed solutions have been used. Still, operators lose huge volumes of mud and cement slurry and expensive rig time. Consequently, many wells also require remedial operations, which can compromise well integrity.

Loss-zone diagnosis and characterization helped to tailor the loss-circulation control solution for different requirements. Losses can occur due to unconsolidated formation (surface holes) or induced and natural fractures. Typical loss rates can vary between 150 to over 700 bbl/hr, particularly while drilling the 16-in. and 12 ¼-in. openhole sections. Thus, total losses in shallow vuguler formation require a different treatment than induced losses in shallow unconsolidated or limestone formation. Induced losses in limestone while drilling prevented increase in mud weights required to drill deeper reactive shale formation. A composite fiber-based system based on a novel four-step methodology was designed using advanced software analysis. Prior to the field trial a complete lab-scale and yard-scale testing was done to confirm superior effectiveness.

In one of the pilot wells, multiple leakoff tests (LOTs) were performed in the Limestone formation to verify the minimum stress (1.40 SG), which did not change with subsequent LOTs. The formation was then treated with the reinforced composite mat based system, and the following formation LOT showed integrity buildup to 1.51 SG. It proved to be an easy to apply solution that can be mixed and pumped through a qualified bottomhole assembly (BHA).

Zone and mechanism specific lost circulation control solutions are most effective in reducing nonproductive time (NPT). It was also demonstrated that fiber-based solutions work well for controlling losses and formation strengthening. The engineered composite fiber-blend system exhibits improved performance and robustness in terms of curing losses and even improves formation integrity.