bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of an Extended Delayed Oil Swell Packer for Deployment in Extended Reach Drilling Oil Wells
Authors: Mitchell Campbell , Urquhart Niall
Published: November 2017

This development, predominantly from four artificial islands, of a giant offshore field in the United Arab Emirates (UAE) requires lateral compartmentalization with open hole packers of the 6 5/8" horizontal lower completions with lateral lengths greater than 16,000ft and total well lengths greater than 30,000ft MD. Swell Packer technology has enabled cost effective compartmentalization in horizontal laterals and is the preferred OH packer solution for the development.

Deploying swell packers is regarded as being a simple solution to compartmentalizing any lateral where typically the deployment fluid differs from the fluids in which it will swell in; this application prevents the elastomer from swelling during deployment and swelling upon contact with produced or injected fluids. The use of an extended delayed oil swell packer with no delay systems in this particular application enables the packers to be deployed in a Non Aqueous Reservoir Drill in Fluid (RDFNAF) where the packer is required to delay its swelling during deployment, thereafter continue to swell once the packer is at final depth and the elastomer contacts the produced oil.

As lateral lengths have increased beyond 16,000ft and total well MD goes beyond 30,000ft these Extended Maximum Reservoir Contact (EMRC) wells require an oil swell packer to delay its swell time sufficiently to be ran to TD in RDF Non Aqueous Drill in Fluid, deploy a displacement string to swap out the drill in fluid to completion brines & breakers and not reach the 8 ½" dimension of the drilled open hole; thereafter continuing to swell on contact with the produced fluids, in this case oil, and swell out sufficiently to meet the required pressure differential between compartments at the wash out diameters of the drilled formation. At the time of the field development starting, there was a gap in the swell packer technology available globally such that this functionality could not be provided. The paper outlines the qualification process to develop and deploy a new swellpacker design meeting these functional requirements.

To date there have been three deployments with these delayed oil swell packers, with deployments consisting of 23 swell packers in a 6-5/8" production liner length of 19,000ft, with 35,835ft MD; 28 oil swell packers with a production liner length of 20,225ft, with 30,197ft MD; and a 6 5/8" production liner length of 18,905ft with 27,995ft MD.

The application of these delayed oil swell packers in the Giant Offshore Oilfield Abu Dhabi was a first of its type where extensive design and testing went into the swellpacker development. The use of this swell packer technology has presented a commercially viable solution to compartmentalize lateral sections over 16,000ft and wells with total measured depth beyond 30,000ft and is a key enabler to deliver cost savings associated with EMRC well designs.
Human Factors Analysis and Classification System
Authors: Akhtar Muhammad Adnan
Published: November 2017

The ADGAS plant facilities include three LNG trains (Trains-1 & 2 commissioned in 1977 and Train-3 commissioned in 1994), Offshore Associated Gas (OAG) and Integrated Gas Development (IGD) facilities along with utilities and other associated facilities such as storage tankage, jetties for export of the products, etc. The gas feedstock comes from various offshore oil and gas fields surrounding Das Island. The feed gas, delivered to the plant at different pressure levels is compressed through different stages and purified before liquefaction. The feed gas contains impurities like CO2 (Carbon Di Oxide) and H2S (Hydrogen Sulphide), which are removed by gas sweetening process. H2S removed by the sweetening process is converted into liquid Sulphur in the Sulphur Recovery Units. After sweetening, the hydrocarbon gas mixture is cooled in stages followed by fractionation and liquefaction to produce different hydrocarbon products ranging from LNG (a mixture of methane and ethane) to Paraffinic Naphtha.

ADGAS commissioned the OAG and IGD facilities in 2010 and 2013 respectively, enabling gas export from Das Island to onshore Habshan facilities through a subsea pipeline. The primary objective of OAG facility is to process additional quantities of LP Gases that has become available at Das Island from ADMA-OPCO, following increase in oil production. The process involves compression of LP Gases, Dehydrate and dispatch 211 mmscfd of Gas & Condensate through marine pipeline to GASCO facility at Habshan. OAG (two processing trains) processes about 200mmscfd gas whereas The IGD was commissioned in the year 2013. This comprises of three Trains capable of delivering 900 mmscfd of dry compressed HP Gas at 155 Bara through marine pipeline to GASCO facility at Habshan.
Use of Pilot Wells to Cost-Effectively Unlock Field Potential: Case Studies from the Jasmine Field
Authors: Yusuf Mukminin , Saifuddin Farid , Nuada I Nengah , Triandi Muhammad
Published: November 2017

The Jasmine Field is a mature stacked-sand oil field that has been on production since 2005. One of the biggest current challenges is to locate remaining oil accumulations. Seismic mapping, material balance and reservoir simulation studies provide pointers to promising locations, but can never guarantee accuracy. Pilot wells offer a means to appraise identified locations before committing to drilling horizontal wellbores.

A pilot well is often used in Mubadala Petroleum drilling campaigns as part of an overall strategy to extend the field's life by continuing to locate and tap remaining oil accumulations. Collaboration across subsurface teams leads to decisions on pilot well locations. In most cases the pilot well appraisal objectives will be to confirm the structural position, to identify fluid contacts or to assess depth uncertainty, especially in areas where there is no well penetration or in significantly updip locations. These appraisal objectives apply to shallower and deeper horizons as well as to the target reservoir itself, and in Jasmine there is a strong record of accomplishment of successfully locating remaining oil by means of such appraisal. It is critical therefore, that well planning is tailored so as to accommodate the appraisal objectives as well as the eventual production target.

Two case studies are presented, illustrating different approaches to using pilot wells prior to placing horizontal wellbores in Jasmine field. In the first case, the horizontal production wellbore was planned to develop an updip region of the target reservoir, to access remaining oil, with additional pilot well appraisal objectives in both shallower and deeper zones. The location for the new horizontal well was confirmed and this dual-role pilot/producer well not only succeeded in reducing depth uncertainty for the new horizontal wellbore, but also identified additional reserves in other reservoirs. In the second case an appraisal pilot well was used to investigate a downdip region of a depleted reservoir. Material balance assessment had indicated that the volume accessed by the updip producer was larger than suggested by the static model, which might have resulted in water encroachment from downdip, causing the appraisal location to water out. However, seismic imaging identified potential barriers between the updip and the proposed downdip appraisal location, which would have prevented water encroachment from downdip. The pilot appraisal well was required to distinguish between those two possibilities.
Moving Models into Reality: An Automated Workflow to Calibrate Forward Stratigraphic Modeling; Application to Hanifa and Arab-D in Central Saudi Arabia
Authors: AlQattan Hussain , Mezghani Mokhles , Hmoud Khalid
Published: November 2017

Forward stratigraphic modelling (FSM) is an evolving technology for understanding the geology between wells for the purpose of exploration and field development. As opposed to the use of geostatistics, this process-based modeling approach uses physical equations for key controls on deposition, such as initial bathymetry, eustatic sea level change, subsidence rate, wave energy, and other environmental conditions. The output simulation is a 3D cellular model with properties like lithology, porosity, and water depth.

FSM results do not honor the interpretation from the drilled wells. This means that the prediction accuracy from the generated model may not be high. The current process of calibrating forward stratigraphic models is time-consuming and tedious. In this paper, we propose an automated workflow to improve the accuracy of a forward stratigraphic model by automating its calibration to facies data from wells.

For our case study, we use an initial stratigraphic model of the Hanifa and Arab-D in central Saudi Arabia. The modeling area covers 430 km by 370 km, the cell size is 10 km, and the simulation time step is 100,000 years. In the resulting model, cells are assigned to seven index facies based on their lithology, wave energy, and water depth. Initially, we conducted a sensitivity analysis to identify the environmental parameters with critical influence on the final model. Subsequently, we ran several simulations with varying values for these critical parameters. To measure the match between the different simulation models and the observed well facies, we used facies from 16 wells. The simulation run with the highest match was used as the best forward stratigraphic model.

Uncertainty maps, based on superimposing several simulations, were generated to check which areas of the simulation are replicated more often than others, meaning they bear, relatively, the lowest uncertainty. This approach may be used to evaluate the risk of drilling new wells in specific locations, or to provide a measure of the uncertainty for subsequent reservoir simulations. In the future, we will use seismic facies and attributes, in addition to well data, for the model calibration.
The Importance of the Stability of Cement Sheaths: Interaction between Cement, Acid, Carbon Steel and Formation and Treatment Fluids
Authors: Alsaiari H. A. , Sayed M. , Reddy B. R. , Metouri S. , Al-Taie I.
Published: November 2017

The stability of cement sheaths during well workover, production and intervention is an important element for well integrity and operational safety. Cement sheaths support casing, provide zonal isolation, seal off annuli, and protect casing from corrosive fluids. Understanding the interaction of the cement with the production and intervention fluids under reservoir conditions is essential to prevent unexpected operational problems.

This paper provides a systematic study on the interaction between the cement and many oilfield elements including fresh acid, corrosion inhibitor, carbon steel, hydrogen sulfide, and carbon dioxide. A series of laboratory experiments were conducted by exposing set cement to various fluids at temperatures ranging from 50 up to 200 °F. Both fresh and aged cements were evaluated.

Cement degradation during production in sour environments could be severe and consequently provide a source of iron- and calcium-related deposits. The severity of the problem depends on the level of degradation and production conditions. The degradation process can also maximize the exposure of casing surfaces to corrosive fluids leading to an increased concentration of dissolved cations in produced fluids, thus, increased potential for inorganic deposits and water-oil emulsion formation. Severe cement degradation can exacerbate the potential of creating easy pathways for toxic gases to the surface.

Several advanced analytical techniques including X-Ray Diffraction (XRD) and Inductively Coupled Plasma (ICP) were used to evaluate the condition of the cement before and after the fluid exposure in our experiments. The results indicated that, unlike what has been reported in the literature, acid can significantly degrade a major portion of the exposed Class-G cement within less than two hours if the exposed cement surface area to acid is considered. The exposure to hydrogen sulfide and carbon dioxide did impact the cement degradation, but not significantly. The degradation was found to be a function of acid concentration, fluid additives, and environment conditions. To determine whether cement catalyzes the corrosion process, the average corrosion rates were also calculated. The results were in agreement with field observations and beneficial to optimize the cement stability and to minimize the related operational problems.
Advanced Reservoir Characterization in Vaca Muerta using Chemical Tracer Technology
Authors: Panichelli Patricio , Martínez Joaquín Ramírez , Crespo Pablo , Noguera Iván Lanusse , Chatterjee Monalisa
Published: November 2017

The selection of the objective target in unconventional shale formations is a determinant factor on the productivity of wells. In thick unconventional formations, as is Vaca Muerta, the operators are looking for new ways of quantifying the production of each stage of hydraulic fracturing executed in the well.

It is of vital importance for the operators to be certain that every section of the well that has been stimulated is effectively contributing to the well production, and that the clean-out of all stages has been correctly carried out.

Other challenges, such as optimal spacing between clusters, stages and wells, which in turn allow to optimize drilling & completion costs, maximizing ultimate recovery (EUR), appear amongst the main preoccupations.

One of the techniques that the industry has developed to answer those questions has been the use of chemical tracers during the stimulation process. Since 2013, the use of chemical tracer technologies to simultaneously tag water, oil and gas has gained great acceptance in unconventional players in USA, with more than 30,000 stages tagged using this technology. In Argentina, Shale operators are quickly gaining experience too.

This paper describes the technique used on site to apply chemical tracers in a multi-stage horizontal well with 15 stages, in Vaca Muerta formation, Argentina. The paper also comments on the data interpretation and necessary steps to obtain the oil and flowback water production profile during the first 60 days following well startup.

Chemical tracer results showed evidence of zones with higher oil production, and higher stimulation water flowback, as well as confirming the complete cleaning of the well.

A production monitoring tool with long term reach, as are chemical tracers, offers the operator the possibility to correlate operational changes (e.g. choke changes) with the individual response of every stage. It is possible to identify which stages are contributing to the incremental oil production, after each operative change.

Finally, it was observed that the information generated with chemical tracers, geological interpretation, and microseismic results collected during the stimulation along the horizontal section of the well, showed a high level of correlation. This helped the Reservoir Engineering team to explain the differences in productivity of each of the fractured stages of the horizontal interval of the well.
A Maturity Modeling Approach to Ensuring Effective Competency-Based Workforce Development
Authors: Johnson Jeffrey A. , Sim Darrell
Published: November 2017

Objectives & Scope

Developing your workforce is an ongoing exercise in remaining technically current and relevant in a culture of continuous improvement. With changing employee demographics, technologies, assets and business conditions, each competency-based development program requires strong governance and ongoing investment to ensure a sustainable system that supports the development of workforce capability, effectiveness and efficiency. This paper details a maturity modeling approach that defines a governance framework for ensuring an effective competency-based workforce development program.

Methods, Procedures, Process

A competency management framework is described which details the methods, processes and best practices supportive of workforce capability enhancement efforts. Implementation of the framework enables organizations to mature from ad hoc, inconsistent practices, to a consistent, disciplined, and continuously improved set of competency management processes. Specific descriptions are provided of five levels that define the competency program maturity plateaus, as defined below in Figure 1.

Consequently, the five levels of competency program maturity are further referenced to six key competency pillars, as outlined below in Figure 2.

The detailed characteristics, benefits, actions and obstacles that align each maturity level to the six defined pillars of competency are later examined in further specificity.

(Refer to ‘Presentation of Data & Results')

Results, Observations, Conclusions

Characteristics of each maturity level across the pillars are demonstrated. The maturity structure can be utilized to establish a competency program's organization, enable detailed action planning towards targeted and measurable process improvements, and set milestones aligned with strategic business objectives. Competency analytics provide management with a view into the state of organizational capability, clearly illustrating competency gaps and related development solutions. With a dedicated team and a view by management of program evolution, a working maturity model can be a framework that supports and directs a continuous improvement culture.

Novel/Additive Information

Establishing a consistent maturity model through industry collaboration can provide benchmarking opportunities that will benefit corporations as they pursue implementation of competency management best practices.
Optimization of Mercury Removal Unit MRU location in Gas Processing Facilities
Authors: Al-Sawafi Khalid , Al-Jabri Hilal
Published: November 2017

Feed gas from KLD fields has mercury content with around 125 micro g/Nm3. Mercury Removal Unit (MRU) will be designed to reduce the mercury content well below 5.5 micro g/Nm3 and meet export spec. The mercury removal unit (MRU) is located upstream of GSU, unlike other PDO plants as well as other places in oil& gas processing facilities where MRU is located downstream of GSU. The optimized location of MRU is to avoid contamination of GSU equipment with high Hg content.

Before entering the mercury bed the gas is heated approximately 10 °C above its water and HC dewpoints in the superheater to avoid liquid formation in the mercury bed due to pressure drop across the adsorbent. The superheater upstream of MRU ensures that gas to MRU is at single vapour phase. However, due to hydrocarbon carryover from the inlet KOD which mostely heavy components will increase significantly the gas dew point and thus higher superheater duty.

As a further optimization in order to remove liquids carryover and reduce the superheater duty, filter coalescer is added upstream of MRU superheater.

This paper demonstrate how this new approach and lineup was engineered overcoming various challenges.
Looking Beyond the Wellbore: Formation Evaluation Mitigates Risk and Reduces Uncertainty in Multi-Stage Unconventional Completions
Authors: Kotov Sergey , Stolyarov Sergey , Cazeneuve Eduardo , Walles Frank , Gadzhimirzaev David
Published: November 2017

Is there a proven methodology for designing optimum multi-stage completions in unconventional reservoirs? Where to place frac stages, perforation clusters, and how to avoid geo-hazards? This paper attempts to cover some of the fundamental aspects of stage placement and hydraulic fracturing designs by discussing lessons learned from several major US basins.

A holistic data-driven approach to completion optimization is based on the analysis of the production potential, favorable rock mechanical properties, and geological features along the entire wellbore. Lateral reservoir characterization, including advanced cuttings and gas analysis, high-definition imaging technologies of logging while drilling (LWD), and wireline (WL) deep shear wave imaging (DSWI) is used to optimize completion and stimulation designs. The suggested methodology goes beyond the wellbore proximity and provides insight to practical application of advanced formation evaluation (FE) technologies.

To address the challenges of lithological and horizontal stress heterogeneity of unconventional reservoirs and to optimize multi-stage completions, a combination of three primary categories of reservoir characteristics are considered: "producibility", "fracability", and geofeatures. Deep shear wave imaging technique identifies spatial natural fractures, faults, and other structural features up to 100 ft from the wellbore. This technology in combination with advanced cuttings and gas analysis helped identify and avoid faults, as well as target natural fractures for greater productivity and maximized economic return in several US basins. The analysis of field data suggests that geomechanical, petrophysical, and geochemistry data should be reviewed holistically. The post treatment analysis reveals a direct correlation of microseismic activity with the density of natural fractures obtained from DSWI processing. The strong correlation between surface treating pressure, breakdown pressure, and the fracture intensity was also observed. This information allows characterization of complex fracture networks, qualification of near-wellbore tortuosity, and estimation and modification of the hydraulic fracture design prior to the stimulation treatment. The intervals with lower horizontal stress and higher brittleness indexes are treated with lower pressure, and achieve the target pumping rates significantly faster than "ductile" stages. Case studies demonstrate up to 45% production increase compared to offset wells.

As opposed to geometric stage placement, the suggested integrated completion strategy ensures targeted stimulation with the optimum reservoir contact at the maximum operational efficiency. Advanced formation evaluation techniques provide insight to mitigate risk and reduce uncertainty, therefore maximizing return on investment in multi-stage completions.
Rotating Tension Anchor Improves Cement Bond Quality in Steam Well Applications in a Heavy Oil Field Onshore Germany
Authors: Ebrahimi Arian , Sieveke Clemens , Martin Helge
Published: November 2017

A rotating tension anchor was developed to improve the cement bond by enabling rotation of the production casing of steam injection wells during cementing. This would be a world-first application of this casing pre-tensioning system in the application of steam well design.

A good cement bond is crucial for the integrity of a well; this is especially true in the harsh environment created by a 300°C injection temperature in steam well applications. A common and relatively simple approach to improve the cement bond quality is to rotate the casing during cementing. The rotation creates a helical flow pattern, which has an improved displacement efficiency compared to a uniaxial flow.

The design of steam injection wells in this heavy oil field requires a deep-set anchor to pre-tension the casing string with the required pick-up force. The existing anchor system had to be engineered and modified to enable casing rotation during cementing.

Although no breach of integrity has been found in previous steam injection wells, the operator identified improvement potential for the long term cement integrity through ultra-sonic cement bond measurements of existing wells. The 7-in production casing of a steam injection well was pre-tensioned with 264.000 lbs [120 metric tons] overpull and rotated with 20 revolutions per minute during cementing.

This world-first field trial of a rotating anchor tensioning system demonstrates, that the existing tension anchor system can be modified to enable rotation of the casing. An ultra sonic cement bond run, several weeks after cementing, confirmed that use of this equipment produced an improved cement bond quality compared to offset wells of similar age and status.
Carbon Dioxide Saturated Water Injection for EOR in Carbonate Reservoir
Authors: Shimokawara Mai , Yogarajah Elakneswaran , Nawa Toyoharu , Takahashi Satoru
Published: November 2017

Carbon dioxide (CO2) injection is an attractive EOR technique that allows not only improving oil recovery but also protecting environment by reducing CO2 which is recognized as one of green house gases. Water alternating gas (WAG) process has been frequently applied to improve sweep efficiency that is one of the problems of CO2 injection. During the WAG process CO2 is dissolved with water phase, forming CO2 saturated water, that is, carbonated water.

Carbonated water injection has been investigated at laboratory-scale since 1940s, and incremental oil recovery was reported in various papers. A first commercial application of carbonated water was implemented in 1958. It was shown that the injectivity was improved and additional oil recovery was observed during carbonated water injection. Researchers indicated that the mechanisms of increasing in oil recovery during carbonated water injection were viscosity reduction, oil swelling, wettability alteration etc. from the experimental results. Although researchers indicated the interactions between carbonated water and rocks, which may affect multi-phase flow in porous media, a little focus is on the interactions between them.

This paper describes the interactions between injectant and carbonate rocks during carbonated water injection based on the results of core flood experiments at various conditions. The core experiments were conducted at 30 °C and 500 psig using carbonated rocks mainly composed of calcite. Results showed that the pH and Ca concentration increased in the effluents, indicating that the calcite was dissolved with carbonated water. Sucequently, the porosity and permeability are increased when carbonated water was injected. The experimental results are simulated using advection flow of carbonated water combined with calcite equilibrium. The simulation results agree with the experimental results of effluent of pH and calcium concentration for the case of without ageing and, the model did not reproduce the results of ageing samples. This indicates that the dissolution depends on the rock surface.
Atomic-Scale Theory of Relative Wettability of Surfaces for Enhanced Oil Recovery
Authors: Pantelides Sokrates T. , Prabhakar Sanjay , Liu Jian , Zhang Yu-Yang , Lai Chia-Yun , Chiesa Matteo , Alhassan Saeed
Published: November 2017

Extraction of oil from wells is hampered by the fact that oil sticks to rock surfaces and water does not pry it loose easily. Technically, this is an issue caused by the relative wettability of rock surfaces. Experiments have shown that Na ions that are present in sea water have a negative effect on oil extraction, while Ca, Mg, and other ions enhance oil extraction. However, only limited understanding of the pertinent mechanisms has been achieved. Atomic-scale modeling of wettability is usually pursued using classical molecular dynamics based on empirical potentials. Only limited research based on quantum mechanical calculations has been reported so far. Here we describe the development and implementation of parameter-free, quantum-mechanical approaches, at different levels of approximation, that can provide detailed understanding of relative wettability and have predictive capabilities. At the lowest level of approximation, we calculate the binding energies of water and prototype oil molecules to calcite surfaces in vacuum as indicators of relative wettability. At the next level, we calculate binding energies in the presence of liquid water using quantum molecular dynamics. We find that the binding energy of Na acetate is larger than the binding energy of acetic acid, a prototype oil molecule, which suggests that, upon reacting with Na ions, a layer of oil becomes stickier on calcite rocks. On the other hand, Ca and Mg acetate desorb easier than acetic acid, facilitating oil extraction, as observed. At a much more sophisticated level of approximation, we calculate the wetting angle, a measurable quantity that serves as a measure of relative wettability. We applied this method to water on graphene and graphitic surfaces, which has been studied extensively and for which we have obtained new experimental data.
Mitigating Drilling Vibrations in a Lateral Section Using a Real-Time Advisory System
Authors: Bailey J. R. , Payette G. S. , Prim M. T. , Molster J. , Al Mheiri A. W. , McCormack P. G. , LeRoy K.
Published: November 2017

A real-time drilling data analysis and recommendation system that leverages surface drilling data was deployed in the lateral section of a well from an artificial island in Abu Dhabi. A key objective of this technology is to provide the driller with an easy-to-use display of a novel drilling performance map. This paper presents data from this demonstration run, illustrates the features of this technology, and provides general observations on optimization of drilling parameters in this hole section.

The prototype advisory system demonstrated value by recommending rotary speed and ROP (Rate of Penetration) values to continuously optimize the tradeoff between stick-slip vibrations and MSE (Mechanical Specific Energy), depending on depth and formation being drilled. The system relieves the driller of tedious drilling test calculations and seeks to continuously optimize drilling performance. The optimization objective function (OBJ) includes MSE, ROP, and TSE (Torsional Severity Estimate) and provides a surface map that is stoplight color-coded to display the optimal drilling parameter values. TSE is calculated from a drillstring model and observations of the cycle-by-cycle swing in the surface torque.

The typical drilling optimization paradigm holds that higher rotary speed can mitigate stick-slip vibrations at the expense of increased whirl vibrations, and higher WOB (Weight on Bit) tends to increase stick-slip and mitigate whirl. The operational challenge is that these tendencies can vary from run to run, and even within an individual section as pipe length, formation, bit condition, etc. all play a role in the balance between these dysfunctions.

In this application, the system demonstrated that increased rotary speed could mitigate stick-slip for about the first 2,500 ft of the lateral section. From this point on, the drillstring was in full stick slip for all available drilling parameters. However, whirl was sensitive to the effective WOB, determined by the ROP control setpoint in this application. To stay within torque limits and provide sufficient WOB to control whirl, the advisory system actually recommended lower RPM.

This application provided an opportunity to compare the calculated stick-slip levels with bit speed measured at a downhole sensor. Excellent agreement was found between measured stick-slip and the TSE determined from the drillstring model and surface torque throughout the 10 kft lateral. This field demonstration was a first application of the system in ROP control mode, providing new insights into drilling parameter tradeoffs. The system prioritizes objectives with high variability over those with lower variability to improve drilling performance. The data was initially unexpected and led to lower rotary speeds and increased WOB in spite of stick-slip, revealing that it was possible to control whirl without making stick-slip significantly worse.
Corrosion-Erosion Monitoring Systems for Manageing Asset Integrity
Authors: Instanes Geir , Pedersen Audun Oppedal
Published: November 2017

Throughout the oil and gas industry corrosion and erosion damage monitoring plays a central role in managing asset integrity. This paper describes a technology for monitoring of wall-loss rates across continuous areas of pipeline wall. Permanently installed ring arrays of non-invasive ultrasonic transducers delimit a monitored section. The arrays transmit and receive guided ultrasonic waves that insonify the entire pipe section. The received signals are processed by a numerical algorithm to produce a two-dimensional map of wall thickness loss. The algorithm measures wall thickness loss differentially, detecting change between an initial and a current state of the pipe. Wall loss can be estimated with accuracy beyond the pipe manufacturing tolerances. Moreover, a strategy that combines a robust temperature compensation scheme with the intrinsic stability of electromagnetic acoustic transducers (EMATs) is used to address the intrinsic thermal dependency of all ultrasonic technologies, always experienced in field applications. Full-scale experiments are presented demonstrating maximum-depth estimation uncertainty below 0.5 % of initial wall thickness with excellent thermal stability up to 175 °C.
A Step Forward to Assess Cement Blend Flowability and Proneness to Segregation: Cases Histories
Authors: Bourlon Arnaud Joseph , Roy-Delage Sylvaine Le , Taoutaou Salim
Published: November 2017

A recurring challenge in cementing concerns the effectiveness and the quality of cement blending and handling procedures. Some recent technologies involve dry-blending operations and cement-blend handling of specifically tuned blends that mix particles of different characteristics in terms of density, shape, size, and chemistry, including mineral and/or organic components. All blends are usually transported pneumatically, loaded to the rig, and then transferred to the rig silos. During the multiple transfers, depending on its characteristics, the blend may become difficult to flow and prone to segregation. This causes the blend to lose its homogeneity, and, consequently, it becomes difficult to use or even unusable.

Flowability and robustness to segregation are essential blend properties for the handling process. Overall, the differences between particles in chemical nature, density, size, and shape will influence the flowability and the tendency to segregate. Dealing with blends is, therefore, complex since they contain small, medium, and coarse particles, all of them in various proportions depending on the targeted cementing-fluid density and set cement properties.

To counter this challenge, an innovative methodology and equipment were systematically used in field cases to characterize the blend flowability and robustness to segregation.

This new approach is used during the cement-job design as a preventive measure to validate the design and quality control of the dry-blending operations and transportation to the rig. This process helped in designing robust homogeneous blends, thus reducing the likelihood of blend transfer problems.

Three case histories illustrate our new process. In the first case, we evaluated the blend selection between two designs that had good slurry performance for a critical job at a field location. We measured the shear under consolidation, the aerability, and the proneness to segregation of the two blends. Because both blends have good and equivalent flowing properties, we selected the blend that was less prone to segregation. In the second case, the field location designed four complex blends for lead and tail slurries having good slurry performance. We evaluated the shear under consolidation of the four blends, which were classified according to their flowability. Next, we measured the aerability of the blends as a second parameter to discriminate the blends, and then we considered segregation as the last screening parameter. In the last case, we used our flowability criteria to select the maximum acceptable concentration of an additive, which increased cement fluid performance but degraded blend handling.

The outcome of this multidisciplinary approach of blend characterization helps the oil and gas industry anticipate blend-handling issues and continuously improve quality and field handling of engineered complex blends with high confidence and consistency.
Innovative Casing Drilling Technology Improved the Ability to Set the Casing Deeper Through the Problematic Zone in Indonesia Geothermal Operation
Authors: Noviasta Bonar , Falhum Hanafi Muhamad , Setiawan Budi
Published: November 2017

Well A is a geothermal well in K field, located in the Jambi area of Sumatera. The pilot hole of the 17.5-in section was drilled to total depth (TD). However, a 13.375-in casing running difficulty was experienced afterwards. A dedicated cleanout bottomhole assembly (BHA) was run, but this became stuck. The decision was taken to plug the pilot hole with a cement plug and to perform an openhole sidetrack. The difficulty in running the 13.375-in casing is caused by collapsing formation from the borehole wall. The commonly run casing/liner tieback system has no rotational capability when an obstruction is encountered while running the casing.

The 13.375-in × 17.5-in nondirectional casing drilling technology was proposed as the solution. The main component of this technology is the drillable alloy casing bit, which drills on standard casing that is rotated at the surface. The casing bit is equipped with PDC cutters and nozzles with the same function as those in a conventional PDC bit. The casing can be fully rotated while applying weight to cut through the obstruction.

The casing drilling system successfully set the 13.375-in casing to 849.72-m measured depth (MD), 314 m deeper than the initial point of the casing running obstruction. The drilling/reaming capability of the casing bit helped in cutting all the formation filling the predrilled hole. The cementing process was executed well, with good integrity to the surface, shown not only by a surface return during the cement top job but also by a good cement bond log (CBL) result. This eliminated the requirement of having a casing/liner tieback system, which saved operating time and cost. The ability to set the casing deeper enabled sealing off the total loss zone. Consequently, the 12.25-in section drilling could be executed without penetrating the problematic zone, which improved drilling efficiency.
Designing an Effective Leadership Development and Succession Strategy to Deliver Value Creation
Authors: Ewers Bjorn , Obied Tamer M. , Braun Philipp
Published: November 2017

One of the most important Human Capital topics at companies today is leadership development and succession planning. Hundreds of millions of dollars are expended each year preparing leaders for today's and tomorrow's challenges, however most companies never see a positive return on these investments because development programs are either not linked to drive business results or success planning is narrowly focused on those directly within sight.

The need for exceptional leadership at all levels has never been clearer. In a recent BCG survey of over 4000 leaders and HR leaders worldwide, respondents highlighted "Improving leadership development" as amongst the highest business priorities. However, respondents also highlighted that "Improving Leadership" was among their company's most significant weaknesses. Among the factors that handicap leadership initiatives are focus on certification versus learning, fragmented talent management systems, and a disconnect between capabilities and business strategy, and how to effectively identify and place rising stars.

BCG believes that the key to sustainable business outperformance is a tight link between leadership and value creation. Either done in isolation of the other leads to inferior, unstable outcomes. Taken together and tightly integrated with value creation, leadership development can be an engine by which companies consistently outperform against objectives—and competitors. Companies with strong leadership and talent management practices increase their revenues 2.2 times faster and their profits 1.5 times faster than companies with weak practices, according to a survey of more than 1,260 companies conducted by The Boston Consulting Group (BCG).
Upstream Data Architecture and Data Governance Framework for Efficient Integrated Upstream Workflows and Operations
Authors: David Richard Mohan , Saputelli Luigi , Hafez Hafez , Narayanan Ram , Colombani Pascal , Al Naqbi Tayba
Published: November 2017

Integrated Upstream workflows require efficient sharing of data across business disciplines involving planning studies, development, operations to carry our effective monitoring, surveillance of their reservoir and operations for better management of reservoir and production optimization. ADNOC requires quality, complete and timely multi-disciplinary data from its operating companies for efficiently monitoring its assets and provide informed directions.

An Integrated Data Architecture and Data Governance Framework is being established to enable efficient deliver data to execute integrated upstream workflows in a multi-disciplinary and multi-vendor technology environment. The framework facilitates to standardize, streamline G&G, reservoir, production, operations data and processes, and enables integrated reservoir management workflows and inter disciplinary collaboration in a multivendor technology environment.

The Framework provides guidance and best practices to build common data architecture foundation for integrated upstream workflows. The framework enables to efficiently govern the data across its lifecycle and makes the relevant business team and data custodians to take responsibility to validate, store and deliver static and real-time data in a timely manner for Integrated Upstream workflows. The framework components form a key foundation element for efficient integrated workflows towards realizing integrate operations, closed loop optimization, full benefit of Smart Field Investment.
Integrated Deployment of Digital Oil Field in Multiple Kuwait Areas in One Platform and Benefits Realized
Authors: Al-Rakyan Sara , Marie Omar Abu , Ledesma Fernando , Heshmat Kareem , Mohamed Assem , Zahourdin Mohamed
Published: November 2017

Instrumentation of artificially lifted wells located North, South-East and West of Kuwait was an essential requirement for real time surveillance of well behavior, and for successful implementation of a digital oil field. The manuscript focuses on challenges and solutions accompanied with setup of a SCADA intelligent software suite and replication configurations applied to remotely monitor and control assets for production optimization purposes.

Meetings have been held with Information Technology, SCADA and Well-Surveillance teams to agree on the technical requirements (server's specifications, network diagrams, well connectivity, data road map, data backup, security measures, disaster backup plan, etc…) The availability of having remote terminal unit built-in in the variable speed drive allowed instant access of real time data with ability to remotely control and modify running parameters for artificially lifted wells. Infrastructure has been built based on the company's standard IT security policies, by segregating network levels from field to domain network.

Well surveillance and field development teams from different areas targeted specific wells to be connected to the smart surveillance solution. Lining up different teams at the same time was a challenge to test, configure and confirm the successful connectivity. Integrating data from different areas/servers in one secure location was our main challenge to overcome. Replication of data was the only solution to assure a security channel that communicates between the different fields in to a single secured location with very limited ports to open and supervise. Wells were fully instrumented and equipped with the required gauges, sensors, and emergency shutdown devices, to evaluate well performance instantly.

Web based setup was the best solution for replicating real time data to the corporate level while keeping it secured and separated from the field network and available for all users accessible through end user system portal. Software acting as a real time data surveillance and historian with the remote access capability created a new level of effective surveillance. Management by exception became available at the corporate level to run failure statistics and identify areas for improvements by utilizing the current setup to optimize production and extend life time of equipment.

Achieving this level of surveillance helped in closely monitoring of well behavior, securely transferring and storing data, identifying operational needs of each field, and was considered as an extra level of surveillance. Successful deployment of the digital oil field in all areas of Kuwait integrated in one secured platform helped in utilizing all equipment available, increasing engineers' effectiveness to improve productivity, increase wells production, meet QHSE (quality, health, safety and environment) standards and reduce human risk.
Studies on Nanoparticle-Stabilized Foam Flooding EOR for a High Temperature and High Salinity Reservoir
Authors: Zhu Youyi , Tian Jing , Hou Qingfeng , Luo Yousong , Fan Jian
Published: November 2017

Foam is a mixture of gas and water where the gas is dispersed as bubbles in a continuous liquid phase. Foam flooding is one of chemical enhanced oil recovery (EOR) technologies by using foam fluid's "Jamin effect". Field tests showed that the EOR performances of foam flooding depend largely on both foamability and stability of foam under reservoirs conditions. To enhance foam stability, high molecular-weight polymer as stabilizer was generally introduced into foam solution. However, in high temperature and high salinity (HTHS) reservoir condition, this function of polymer was limited being the degradation of their large molecules. Therefore, it is necessary to call for an alternative stabilizing agent. DL offshore oilfield is one of HTHS reservoirs with reservoir temperature of 100-120°C and salinity of 34,370 mg/L, which has entered high water cut stage. The selection of EOR technique is very important for future development of such reservoirs. In this case, foam flooding with nanoparticle replace polymer acted as foam stabilizer was proposed. Nanoparticle-stabilized foam formulation was studied under the target reservoir conditions.

The nanoparticle-stabilized foam formulation was screened by static bulk foam tests. Though foaming agent and nanoparticle types screening tests, the effect of nanoparticle on the stability of foam system was investigated by measuring the foam properties of the foamability (foaming volume) and stability (drainage half-life). The distribution of nanoparticle size was analyzed. The injectivity and resistance factor (RF) of nanoparticle-stabilized foam fluid were studied on core flooding. Core oil displacement experiments of nanoparticle-stabilized foam flooding were conducted at the reservoir condition.

From the nanoparticle-stabilized foam system screening tests, α-olefin sulfonate (AOS) and fluorocarbon surfactant as foaming agent and clay nanoparticle as foam stabilizer were selected. The results showed that clay nanoparticle could greatly enhance drainage half-life of the foam system. More dense foam was formed in nanoparticle-stabilized foam fluid. Injection experiments of nanoparticle-stabilized foam on core showed a good injectivity when core permeability was more than 200 mD. RF of foam fluid showed that nanoparticle-stabilized foam had good mobility control function. EOR effect evaluation on core flooding indicated that foam flooding could contribute 17%-21% of OOIP incremental oil recovery under good operating protocols.

The experimental results were considered to be technical feasibility and effectiveness of nanoparticle-stabilized foam flooding EOR methods for DL reservoir, which might present further understanding for nanoparticle-stabilized foam flooding EOR field application on the HTHS reservoir.