bluuebunny/crossref_metadata_2025 huggingface dataset:
Moving Toward Smart Monitoring and Predictive Maintenance of Downhole Tools Using the Industrial Internet of Things IIoT
Authors: Temer Elias , Pehl Hermann-Josef
Published: November 2017

While all other industries are aligned with the digital evolution, oil and gas operations have also taken advantage of the importance of the digital transformation, especially in the actual context. Our industry is arguably in a new wave of the digital oilfield, with a growing consensus toward "smart" operations and "predictive" maintenance instead of the "reacting better" approach, which is not adequate in the new industry conditions and has been proven as an inefficient approach. Oil and gas operators and services companies have a major opportunity to increase efficiency and reduce operational costs through better asset tracking and predictive maintenance, combined with operations and technology expertise. This paper will focus on the maintenance management of downhole equipment, evolving in an unforgiving downhole environment, which in the case of equipment failure, can cause high financial losses. It will also present a use case and opportunities and challenges of smart monitoring and the predictive equipment maintenance approach, which is supported by newer technologies, such as the industrial internet of things (IIoT) and data analytics that use machine learning (ML) algorithms compared to the traditional, reactive approaches to equipment maintenance.
Integrating Microgels and Low Salinity Waterflooding to Improve Conformance Control in Fractured Reservoirs
Authors: Alhuraishawy Ali , Wei Mingzhen , Bai Baojun , Almansour Abdullah
Published: November 2017

The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low-salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently investigated by some reserchers. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Semi-transparent five-spot models made of sandstone cores and acrylic plates were built. The effect of low-salinity waterflooding on oil recovery was studied. Models were designed with three parallel open fractures. Sodium chloride (1.0, 0.1, 0.01, and 0.001 wt. % NaCl) were used for brine flooding and 1.0 wt. % NaCl for preparing swollen PPG. Two microgel concentrations, 2000 PPM and 5000 PPM, with 850 micrometer particle size were used. Three cycles of low-salinity water were injected after the second conventional brine injection was completed. Oil recovery factor, water cut, injection pressure, microgel extruded pressure, fracture pressure (Pf), monitoring pressure (P1 and P2), and water residual resistance (Frrw) were measured. The interwell connectivity also was investigated. Laboratory experiments showed that the oil recovery factor, injection pressure, and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. The tortuous wormholes resulted highrer oil recovery than the straight wormholes and the oil recovery decreased as number of fratures and fracture width increased. The microgel concentration had a signicicant effect on plugging effeciecny; therefore, the 5000 PPM Microgel showed higher plugging efficiency than 2000 PPM. The result showed the interwell connectivity between the injector and producer decreased when low salinity waterflooding applied and increased the interwell connectivity between the injector and the monitoring points. The plugging efficiency, stabilized injection pressure, fracture pressure, monitoring pressure, and water residual resistance factor—all increased when the salinity of injected water decreased. Furthermore, the microgel strength decreased as brine concentration decreased. However, lower salinity water caused the incremental oil recovery factor to increase. Thus, there is a limitation in increasing the plugging efficiency under low salinity water. This limitation occurred when the brine injection pressure was less than the PPG’s extruded pressure. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.
Evaluation of Late Cretaceous Cenomanian Petroleum System in Offshore Abu Dhabi with Geochemical Analysis
Authors: Kojima K. , Yamanaka M. , Taniwaki T. , Amo M. , Chiyonobu S.
Published: November 2017

Identification of hydrocarbon generating source rocks and evaluation of their potential are essential in the exploration and development of hydrocarbon resources. For an offshore oil field in Abu Dhabi, we conducted geochemical study using crude oil and core samples from Upper Cretaceous Cenomanian carbonate rocks. The study objectives are 1) correlation of crude oil and source rock with biomarker, and 2) evaluation of the source rock potential.

The Cenomanian carbonate rocks of the oil field are composed of shallow marine porous limestone and deep marine lime mudstone. This Cenomanian lime mudstone was believed as source rock of the crude oil in the interfingered Cenomanian porous limestone reservoirs. However, the origin of crude oil has been poorly constrained with geochemistry yet. In this study, we carried out geological description and RockEval pyrolysis analysis of core samples to evaluate source rock potential of the lime mudstone. Then, biomarkers such as hopane, sterane and compound specific isotopic ratio of n-alkane were analyzed to correlate the source rock and the crude oil samples with GC/MS, GC/MS/MS and GC/C/IRMS for high resolution biomarker measurements and robust interpretation.

As a result, the biomarker fingerprints of the crude oil in porous limestone and the organic material in the lime mudstone show significant similarity. It proves that the crude oil in the porous limestone is migrated from interfingered organic rich Cenomanian lime mudstone. In addition, the lime mudstone shows excellent source rock property (Total Organic Carbon exceeding 4%, Hydrogen Index > 600mg/g TOC) and categorized as Type I/II source rock deposited in marine environment. Furthermore, the biomarkers effectively constrain the maturity of source rock which is difficult to evaluate with Vitrinite Reflectance and RockEVAL analysis. Consequently, the timing of hydrocarbon generation and the area of effective source rock will be interpreted based on our study result with higher confidence.

This study deepens understanding of Cenomanian petroleum system in offshore Abu Dhabi. The result suggests the advantage of biomarker application not only in oil-source correlation but also in source rock maturity analysis.
The Effect of Ba2+ & Sr2+ on EOR Efficiency in Carbonate Reservoir During Low Salinity Waterflooding
Authors: Park Hyemin , Park Yongjun , Yeonkyeong Yeonkyeong , Kim Joohyung , Lee Wonsuk , Kwon Oukwang , Sung Wonmo
Published: November 2017

When low-salinity water containing SO42- is injected into carbonate oil reservoirs, rock dissolution and in-situ precipitation occur as chemical equilibria are progressed, altering both permeability and wettability. The Ba2+/Sr2+ ions present in the formation water as impurities chemically react with the SO42- ions, and BaSO4 and SrSO4 are precipitated. In addition, when injected low-salinity water including SO42-, either dissolution of Ca2+-containing minerals or CaSO4 precipitates are occurred. These reactions can cause a serious impact on the efficiency of enhanced oil recovery (EOR). Therefore, the main purpose of this study was to identify EOR efficiency induced by low-salinity waterflooding (LSWF) when Ba2+/Sr2+ were present in a carbonate oil reservoir.

From the results of the effluent analysis and material balance calculation with the produced Ba2+, Sr2+, and Ca2+ concentrations, when Ba2+/Sr2+ concentrations were low, permeability was improved because of rock dissolution predominating over in-situ precipitation. These results concurred to the permeability change which was calculated with the measured pressure data. Also, in the analysis of wettability alteration through the measurements of contact angles and relative permeabilities before and after LSWF, higher concentrations of impurities consumed more SO42- in precipitating BaSO4 and SrSO4, resulting in weaker wettability alteration due to the reduction of sulfate activity. These phenomena ultimately influenced EOR efficiency, i.e., the oil recovery was greater as Ba2+/Sr2+ concentration were lower. Therefore, applying LSWF containing SO42- ion to carbonate oil reservoirs is not always a desirable EOR method when Ba2+ or Sr2+ is present, as an impurity, in the formation water.
Ways for Optimizing and Increasing Reliability of Centrifugal Compression Systems in Oil and Gas Industry: Case Study in Sultanate of Oman
Authors: Hatmi Khalid Al , Mashrafi As'ad Al , Balushi Sa'Ud Al , Al-Kalbani Haitham , Shaikh Mohammed , Vakili-Nezhaad G. Reza
Published: November 2017

Rotating equipments reliability and performance have evolved in the recent decays. Manufactures continue to produce more sophisticated machines. Those equipments form a central part of any oil and gas plant. Compressors in particular considered being a major investment for any company. For any operator, keeping the compressors performance and reliability is a very major task which requires an intense OPEX spending in some cases.

This study was conducted to focus on the common issues which are related to centrifugal compressors in Oil and Gas Industries with the aim to increase the reliability and performance of this type of compressors and to form a kickoff for compressors low performance root cause analysis. Also, it will serve as a quick reference for engineers and operators to troubleshoot and optimize compression system.

The common compressors issues identification and short listing of this study was not limited to literature review instead a detailed analysis of an existing centrifugal compressor system was carried out and common issues were reported. These issues were shortlisted to focus only on the process related aspects which are liquid carry over, surge, improper system configuration, variation on inlet gas properties and pressure impacts on the performance.

An existing compression system has been selected to study the effects of the listed issues. The performance and reliability of these compressors were checked and monitored for the last three years.

To meet the objective of this study, a detailed analysis was conducted to solve these issues and optimizing the system. The study includes theoretical analysis and field troubleshooting and trials). Theoretical aspects of the work with regard to the compressor efficiency, power consumption as well as other important issues are examined based on thermodynamic analysis of the systems.

The theoretical analysis concluded that the reliability and performance of the compressor system can be increased through a number of recommendations including optimization of the suction and discharge pressure, continuous process monitoring, enhancing inter stage scrubbers’ efficiency and maintaining the gas molecular weight through compressors stages. In addition, some recommendations are given which are applicable during the design stage such as recycle line location, drain system design, seal system design and scrubbers internals accessibility. The recommendations of the theoretical analysis are under long term field trials to ensure their applicability and sustainability. The results from this study are projected to be generalized for similar type of compression system in the industry. This paper will be of interest to anyone who designs or operates multistage compression systems.
Recovery of Casing Gas from Remote and Scattered Oil Wells
Authors: Cui Xiangyu , Weng Yibin , Xue Ming , Xu Wenjia , Fan Junxin
Published: November 2017

It is difficult to collect/gather casing gas given the number of wells and their location in an undulating terrain without separate gas pipelines. To solve this obstacle, synchronal rotary compressors were specifically designed for the demonstration area. In the demonstration area, synchronal rotary compressors and walking beam compressors were installed on oil well pads to inject casing gas into oil pipes. This approach decreases wellhead back pressure to ensure crude oil production and avoid casing gas flaring or venting. When oil wells didn’t connect to pipelines, the moderate compression and vehicle transportation method was applied to gather the gas. The oil and gas mixture is transported to batteries where a light hydrocarbon recovery plant has been built. Dry gas, LPG and stable light oil are produced from the mixture using a separation and refrigeration process. LPG and light oil are shipped to market, and the dry gas is used to generate electric power. The walking beam compressors were installed in 2011 and had been in use for more than dozens of months. The synchronal rotary compressors were installed in 2010 and had been in use for more than years. The related light hydrocarbon recovery plant was built in 2011 and is fully operational. Collectively, the gas-gathering and processing devices can recover more associated gas -- up to 20,000 cubic meters per day -- and reduce GHG emission by 15,000 tonnes CO2E yearly. The total investment was $8.2 million including gas gathering system, crude oil stabilization device, light hydrocarbon recovery plant, waste heat recovery, etc. The payback period was 4.5 years, and the intenal rate of return (IRR) was 22.5%.
Optimized Whipstock and State-of-the-Art Dual-Reamer Assembly Deliver Highly Efficient Drilling Operation in the Norwegian North Sea
Authors: Labrousse S. , Kjøraas M. , Angeltvedt T. T. , Olsen C. , Torvestad B. , Konglevoll A. , Moldekleiv R. H. , Esmat M.
Published: November 2017

Reentry wells are drilled routinely in mature fields. On some occasions, drilling the reentry well is complicated by unexpected casing wear in the motherbore or restrictions above the planned kickoff point, which might be due to junk in the hole, sagging, casing collapse, or ovality. In this paper, we present an actual case where a reentry well design was affected by such a restriction and how this challenging situation was overcome efficiently.

This paper will: Present the consequences of the restriction on the reentry well design, initially planned with its 12 ¼-in. section and 9 5/8-in. liner.Describe the solution designed to pass through the restriction and deliver a reentry well design as near to the initial plan as possible, including an innovative undersized whipstock design, 10 5/8×12¼-in. hole section with a dual-reamer assembly, leaving a marginal 10 5/8-in. rathole and a little 11¾-in. rathole, and real-time near-bit directional data sent across the lower reamer.Summarize the risks and compensating measures associated with the designed solution, including shocks and vibrations leading to tool failure and trip, limited record of directional work available with such a design; i.e., a section longer than the vendor’s world record for this dual-reamer size and running 9 5/8-in. liner in the 11¾-in. rathole.Present the successful operation results obtained by using the dual-reamer assembly, fit-for-purpose directional capability, and successful casing run to total depth. This was the longest 10 5/8×12¼-in. run with a dual-reamer assembly, also known as rathole elimination assembly, performed by the vendor worldwide and the section was drilled and completed ahead of schedule and below budget.Highlight the main drivers that make this custom-made solution portable for applications in other situations.

This case study demonstrates how close collaboration between the operator and wellbore departure and directional drilling vendors led to an innovative whipstock and an aggressive drillstring design delivering a proper sidetrack and a fit-for-purpose borehole in one run. This collaboration turned a challenging situation into a successful drilling operation by minimizing the effects of a potentially harmful restriction.
Equivalent Fluid Model Characterization Expedites Daily Surface Network Optimization in a Complex Reservoir Under Miscible WAG, Field Case
Authors: Rubio Erismar , Khan Karem Alejandra , Figuera Luis , Davila Rayner , Bin Amro Ahmed Abdulla , Caicedo Sergio , Al-Ameri Salem
Published: November 2017

Achieving history match for all three phases in a surface network model is not a straight forward task. Many variables are interacting in the process from sandface, well models, system architecture, measurements, and well testing until export meters. The objective of this study is to illustrate a methodology followed in a smart field located in Abu Dhabi, where it was possible to calibrate and match oil, gas, and water historical production rates in a top side model containing more than 55 strings among producers and injectors. Reservoir characterization played a very important role since the asset contents - a series of carbonate oil baring reservoirs with different properties - connected to a common surface network. The main reservoir has a strong compositional gradient starting from gas condensate to black oil fluids with saturation pressure and GOR varying in a wide range. Wells associated with the most prospective zone are placed in five inverted patterns as part of a miscible alternate water and gas injection (WAG) process which provide pressure support; others are under peripheral water injection with very stable bubble pressure and GOR across all areas. To combine in a single model all the complex and different fluid characteristics and dynamic interactions represented a challenge for the engineers.

A surface network model was built with the purpose of creating online production optimization scenarios that consider all production system behavior using an economical model for boosting oil while minimizing gas production in order to reduce operating costs. After network calibration was performed, oil and water total rates matched. However, the resulting gas production was overestimated compared with the one reported in export meters, indicating that fluid properties need to be tuned since important compositional changes were expected to happen when pressure drops from subsurface to the processing plant. The present study demonstrates how to construct a representative fluid model for a group of complex reservoirs that honor actual production rates for all phases allowing network model history match, reducing computing time to accomplish comprehensive production optimization based on truly surface constraints.
The Application of Specific Drilling Energy to Identify Overburden Lithological Boundaries and Aid Well Operations - Oman Khazzan Field
Authors: Jahdhami Nafa Al , Anboori Abdullah Al
Published: November 2017

The concept of Specific Drilling Energy (SDE) has been in existence for decades and used in both the mining and oil industries to mainly optimize drilling performance and efficiency. We present a practical application of SDE to pick key lithological boundaries during and post drilling. This in turn is serving as an additional tool used to aid well operations and also characterise the overburden of the Khazzan Field.

Developing the giant Khazzan Gas Field requires drilling a large number of wells to the deep target reservoir. Characterizing the overburden in such a field requires a consistent approach in defining the overburden geological formations to aid drilling operations, selecting casing setting points andavoiding future drilling surprises in planned wells. The concept of specific drilling energy is being applied in the Khazzan Field to aid Geologists in three ways:Firstly, picking shallow formation tops for top holes drilled by a rig with no mud logging unit. Secondly, real time picking of shallow formation tops besides potentially removing cuttings lag time factor and consequently to ensure correct casing setting depths in order to avoid wellbore stability issues. Thirdly, it serves as an additional tool to QC formation tops post drilling particularly for tops picked in the absence of petrophysical logs.

Various forms of the equation have been developed through time to mainly assist drillers optimize drilling performance. In this case, thevery earliest form proposed by Teale in 1965 was used in which main inputs into the SDE equation include Rate of Penetration (ROP), torque, Weight on Bit (WOB) and Rotations per Minute (RPM) which are readily recorded by drilling sensors at no extra cost. When this data is loaded into petro-technical software, such as Petrel in this case, the powerful display functionality allows comprehensive correlation between wells and eases the process of picking formation tops.

A few examples are presented upon which this methodology aided picking the top of a casing setting formation, calling total drilling depths and performing correlations between wells post drilling to aid the provision of tops prognosis in future planned wells.

This work proves that the applications of the SDE concept is not just limited to drilling optimization, but also in assisting Geoscientists identify lithological boundaries and aid informed decisions in well operations using solely drilling parameters.
Allocation Of Zonal Production In Smart Wells: Offshore Abu-Dhabi Case Study
Authors: Salimov Rail , Sarsekov Arlen
Published: November 2017

The field considered in this paper is located in offshore Abu Dhabi with a production history of nearly fifty years. The long term field development plan includes completing hundreds of wells with intelligent completion. A pilot smart well targeting three separate flow units was introduced in 2014 before full-field scale application. One of the challenges faced while piloting the smart well is zonal production allocation which will be addressed in this paper.

Best practices worldwide to monitor and allocate stacked production in smart wells include: periodic PLTs, permanent downhole Venturi flowmeters, rate calculation using pressure loss across the ICV, IPR curve based allocation, DTS optical fiber, geochemical fingerprint analysis and downhole acoustic passive listening. In this paper PLT based approach, ICV pressure loss and IPR-based allocation methods are tested and compared based on three years pilot well production history, numerous flow tests and five downhole gauges recordings.

Though PLT based approach is the easiest method to apply on brownfields it has the biggest uncertainties due to following factors: PLTs are not logged for full range of possible ICV positions; PLTs in horizontal wells are rarely logged in well-stabilized regime; coiled tubing in deviated wells have a direct impact on the inflow proportion. Pressure loss across ICV method based on multirate flow test results look promising but absolutely requires at least partial choking of all ICVs. The biggest advantage of dP vs ICV method is non-sensitivity to transitory flow behavior. IPR curve based method found to be simple to implement as well as quite robust for certain conditions. Main drawback of IPR method is its non-reliability in transition period if ICV / Wellhead Choke positions are modified.

A new allocation methodology is proposed and tested in this paper – production allocation using numerical simulation. If properly applied, this methodology can overcome the transition period issue of IPR method. The biggest advantage of this method is that it may be the most accurate method for back-allocation even though it is very time consuming to implement. Another novel method proposed in this paper is using dual downhole gauges per ICV. Zonal allocation is computed considering friction pressure loss between ICVs. This method is successfully tested and validated in a recent water injector with ICVs. It can fit best for single phase fluid and relatively high production / injection rates.
Nurture the Culture; HSE Culture Improvement Program
Authors: Al Badawi M. , Al Muhairi M. , Suresh Kumar G. , Al Hammadi H. , Al Hamadi Y. , Patil A.
Published: November 2017

All organizations’ ultimate goal is "Zero Accident" and to achieve this target in our organization also, a benchmarking study on HSE KPIs, and deep analysis of the HSE incident data was carried out. The results of the study revealed that personal factors constitute a significant percentage of the unsafe acts and unsafe conditions reported.

Addressing these results, the direction was set to focus on people’s unsafe behaviors by introducing the "HSE Culture Improvement Program".

"HSE Culture Improvement Program" is based on the solid principles of motivating, reinforcing, and sustaining safe behaviors among the company employees and contractors.

The program roadmap was consolidated with series of initiatives: Introduced "TAKE 2" methodology.Introduced a friendly animated character named HESSA for effective HSE communication.Improved effectiveness and visibility of behavior based program the "Online HSE Observation Tour" by setting the target to leadership site visits.Conducted a major HSE campaign for reaching out to employees through "HSE Touching Your Life" campaign.Developed a professionally designed "HSE Computer Based Training."Introduced of HSE motivation program entitled the "HSE Champion" and also balanced it with the "HSE disciplinary".

All aspects of HSE Culture Improvement Program were developed in-house and no external parties were involved.
Well Integrity Management: Challenges in Extending Life of a Mature Gas Condensate Field – A Case Study
Authors: Jain S. , Al Hamadi M. A. , Saradva H. , Asarpota J. , Sparke S. J. , Volkov M. , Abu Rahmoun H.
Published: November 2017

Sharjah National Oil Company (SNOC) operates 3 fields Onshore Sharjah with 30+ years’ production history from over 50 gas condensate wells. The fields were produced historically under a blow down scheme resulting in significant condensate volumes being dropped. While these existing resources could be recovered through drilling additional wells apart from optimization opportunities in the current production regime, the most economical solution would be to verify if the existing well stock could be confirmed as having sufficient well integrity to safely allow the continued use of these wells thereby extending the field life through careful well and risk management.

The Sajaa and Moyeveid gas fields feature a series of challenging production issues. These include varying hydrogen sulphide levels upto 500 ppm, surface cemented annuli, sustained casing pressures, carbon steel tubulars, known corrosion issues greater than 0.5 mm per year, carbon dioxide and water production, all from multi-lateral wells at extremely low reservoir pressures. SNOC developed a comprehensive risk ranking process that categorized the wells into low, medium and high risk using a wide range of available production data, well age and corrosion inhibition data. Further investigation included corrosion logging data acquired from 2 wells in 2015 providing indicative well status and validation of electromagnetic corrosion measurement technology. Although, it did not provide a comprehensive and in depth review for a representative wider range of wells. In order to provide a more deterministic status of the well stock, and optimizing the risk ranking process, 10 wells were selected to be investigated with a campaign of corrosion logging in 2016. However, it was important that the intervention program would have minimal production impact with a small footprint slick-line intervention unit that would utilize state of the art magnetic imaging technology to record and measure the status of the well tubulars. Additionally, HSE impact was reduced by restricting the operations to daylight working hours and minimizing the numbers of personnel exposed to the well-site.

This paper summarizes the logging operations, analysis of the data collected, well tubular status & issues such as shallow surface corrosion and well correlation on a field basis. It also focuses on how this was integrated into the SNOC risk ranking model to allow continued production from the wells, while still maintaining the well integrity status that supported the company’s philosophy of managing risks ‘as low as reasonably practical’ (ALARP) maximizing recovery from a mature reservoir
True Resistivity in High-Angle and Horizontal Wells - Correction of Thin Layer Effects Using Image-Constrained Inversion
Authors: Boesing David , Wessling Stefan , Marsh Roger , Wright Mat
Published: November 2017

The application of traditional petrophysical interpretation techniques for formation evaluation (FE) in high-angle/horizontal (HA/Hz) wells is limited because formation geometry affects circumferentially averaged and/or deep-reading logs such as multi-propagation resistivity (MPR). The log responses of neutron-density (N/D) or gamma ray (GR) may not correlate with MPR readings as a consequence of different depths of investigation and azimuthal variation of the lithology around the wellbore. Therefore, alternative approaches and modeling workflows are needed for quantitative petrophysical evaluation of the individual layers.

This study on HA/Hz wells demonstrates the benefits of combining different types of FE data for a quantitative petrophysical evaluation in a shale-sand formation using an image-constrained resistivity inversion algorithm. It includes the calculation of true formation resistivity in sand reservoir intervals, with the expectation that intersecting shale layers affect the MPR readings. The increased shale content in the form of thin laminations was indicated on the GR log.

To account for the thin and conductive shale layers in a resistivity inversion, a detailed structural earth model was created for the near wellbore. The strike and dip of boundaries were interpreted from a bulk density borehole image and projected away from the borehole within a depth-of-detection tube. The layers in the model were populated with expected property values derived from offset wells and the interpretations of the related FE logs. A resistivity inversion algorithm was run as part of the workflow, providing true formation resistivity (Rt) as output.

A synthetic data set was used for demonstrating purposes. The data set consisted of a 70 degree inclined well penetrating horizontally layered sand-shale sequences. The applicability of the new approach was then confirmed by a field data set from the North Sea in which FE data were acquired in a high-angle well using logging-while-drilling (LWD). In both data sets the formation geometry affected the log responses. The workflow described in this study enabled efficient merging of detailed borehole image information into the forward modeling and inversion processes. The true formation resistivity was obtained for each layer for input for further petrophysical analysis using traditional interpretation techniques. The comparison of water saturation calculations based on apparent and on true resistivity logs, respectively, demonstrated the added value of this approach for an improved quantitative petrophysical evaluation and revealed the significant impact of formation geometry effects in HA/Hz wells.
Study on the Drilling Fluid Flow Rate Allowable Range in Offshore Drilling Considering the Extended-Reach Limit
Authors: Li Xin , Gao Deli , Tan Leichuan , Zhang Hui , Chen Xuyue , Zhou Yingcao
Published: November 2017

Offshore drilling has the characteristics of high risk investment, increasing the difficulties of offshore drilling design. Conventional offshore drilling fluid flow rate design method fail to consider the effects of extended-reach limit in offshore drilling. As a result, the extended-reach well (ERW) may unable to reach to the designed well trajectory length, causing potential safety hazards. Therefore, there exist a drilling fluid flow rate allowable range (DFFRAR) in offshore ERW. In this study, considering the dynamic pressure balance of bottom hole and drilling pump's rated pressure and rated power, coupled with the needs of hole cleaning, four constraint conditions of DFFRAR and corresponding DFFRAR prediction model are proposed. The predicted DFFRAR of offshore ERW must satisfy these constraint conditions simultaneously. In the end, an ERW in South China Sea is analyzed, and the well's DFFRAR is also determined. Furthermore, some optimization measures are also put forward to obtain wider DFFRAR. The results of case study show that the DFFRAR of offshore ERW in South China Sea ranges from 31.1 L/s to 35.7 L/s when the designed well trajectory length is 3243 m. In addition, the DFFRAR becomes narrower with the increase in designed well trajectory length and ROP. In contrast, the DFFRAR becomes wider with the increase in rated pressure of drilling pump and fracture pressure of drilled formation. Moreover, the window of DFFRAR will be closed if one of these constraint conditions is not satisfied. A wider DFFRAR is conductive to the offshore drilling safety. It is necessary to obtain wider DFFRAR as much as possible by taking optimization measures. This work provides a practical tool for determining the offshore ERW's DFFRAR and achieving wider DFFRAR in order to improve the drilling efficiency and obtain good economic benefits in marine environment.
Optical Spectroscopy for Downhole Gas Show at the Drill Bit: Real-Time Sweet Spot Detection
Authors: Maity Sandip , Halder Purbasha , Liao Yi , Brazil Stewart , Kavoori Nagapriya
Published: November 2017

Moving gas show analysis from surface to downhole at the drill bit has the advantages of identifying sweet spots directly and immediately, enabling focused stimulation which can lead to improved well production and EOR, and to optimized completion, and kick detection at the bit. We have explored the use of optical spectroscopy for gas show at the drill bit. Based on our initial study we identified two potential approaches – a Raman spectroscopy-based approach where the gas concentration is measured in-situ in the dissolved state, and an absorption spectroscopy-based approach where gas is extracted out and tested. While the approach where the gas is tested in-situ would be the preferred one, the high risk involved here led us to simultaneously develop the extractive approach. Proof-of-concept experiments have been performed to down-select the most appropriate approach. We have been able to demonstrate that both methods can detect methane at the desired concentration levels down to better than 1%. It has been concluded that since dissolved methane at the required concentration can be detected using the non-extractive approach, it would be most suitable to use the Raman-based gas detection for downhole gas show at the drill bit.
Optimize the Spares and Spare the Resources
Authors: Gongade Ashish , Al Awadhi Ibrahim , Narayana Sathyanath , Al Ahmad Alya , Miranda Robert , Oka Sameer
Published: November 2017

GASCO (Abu Dhba Gas Industries Ltd) commenced design and construction of processing facilities since 1978. The main plants and subsequent expansions were engineered in phases by different EPC Contractors. Piping Material Specifications (PMS) were developed for each Project as per EPC Contractor’s engineering understanding and as per the Project need. This resulted in having different PMS for similar fluid services in an identical process Units/Trains. This paper presents the outcome of the study to optimize the number of PMSs and generate a common PMS to satisfy all the existing plant requirements.

GASCO has around 800+ Piping classes across all the sites. The selection of right PMS was a challenge during the modification projects in existing plants. It was also difficult for Store/Ware house personnel to maintain the inventory and track spares as because of large number of stock codes. A comprehensive study was undertaken to develop a master set of PMS involving following steps; data collection & review, checking the compatibility with latest Codes and Standards, study lessons learnt, generate back up calculations, documentation and publish the Design General Specification (DGSs).

Through this comprehensive study, 800+ piping classes were optimized to 150 number of piping classes in a common PMS to suit overall GASCO’s requirement. The co-relation of existing piping classes having outdated materials with newly developed classes made the selection of required piping class much easier and user friendly. The new PMS, with new material classes ensuring good engineering practices and adapting the lessons learnt over the years of operation. This optimization campaign facilitated GASCO to formulate a definitive approach towards the selection of common piping material for specific fluids across the plants.

The new PMS has segregated the material requirement for various fluids with different operating temperature and pressure conditions from different Units/Trains. Some of obsolete components had been taken out from PMS based on GASCO’s operating experience over last 30+ years. The selection of material has become easy at all level of work force when doing the modification work.

Use of right piping material will save material cost with engineered material solution with minimal failures. Alignment with all the Plants with common piping classes will maintain optimum inventory across GASCO plants. The same philosophy can be used within all the OPCOs under ADNOC directives of cost saving and standardization.
The Study of Effects from Small Bore Connection Geometry for High Vibrational Excitation
Authors: Pewkliang S. , Janbanjong P. , Rahong P. , Muangsuankwan N. , Nokjib S.
Published: November 2017

The objective of this paper is to study the effect among the branch pipe to main line ration, the overall length of Small Bore Connection (SBC) and the high frequency vibration excitation on SBC.

The process of this study is to analyze the cause of high vibration excitation due to effect of SBC geometry and operating condition by gathering data from "SBC Integrity Management Program. All relevant data which is used for this study is comprised of dimension data from Likelihood of Failure (LOF) for SBC geometry, vibration result and operating condition of piping. The total amount of 3,391 sets of SBC data, which is collected from four (4) offshore production platforms. The study is conducted by noticing of the display for the data set, which cause is pointed on high vibration result. The graphs relation among the branch pipe to main line ration, overall length of SBC, frequency and velocity of vibration are plotted to define the parameter range of high vibration excitation.

The result from this study is presented that the high vibration excitation from all SBC data is in line with the ENERGY INSTITUTE's guideline. Most of anomaly and high vibration on SBCs are found at branch pipe to main line ration ≤13% and overall length of SBC ≤ 2m. High frequency vibration is found at operating pressure ≤ 5 barg. The major root cause is from the resonance of natural frequency and excitation frequency at low pressure condition.
Working together for Successful Drilling through a Fault: Risk Management, Planning and Execution
Authors: Yanez_Banda M. , Ruzhnikov A. , Kasimin A. , Husien M. , Malagon C. , Al-Wahedi K.
Published: November 2017

Since the start of drilling campaign at new field in the United Arab Emirates the operator faced the challenge to drill across faults, what can lead to well control, wellbore instability, total losses and stuck pipe. To minimize the impact, a risk management plan was developed and implemented during drilling and completion stages, which allowed to execute wells in trouble-free manner.

The operator gathered the respective teams (geomechanics, seismic, operation geologists, drilling engineering and operations) and service companies with the objective of understanding the nature and potential operational impact of the faults. Afterwards, a very detailed risk management plan (RMP) was developed, which included different options with mitigation measures on how to deal with losses. This included changes in the well design, drilling fluid, BHA and casing setting depth. The compromises and benefits of each scenario was worked until a primary option was determined. Also, detailed procedures in case of non-standard situations were developed with contingencies.

Based on the measures developed as part of the risk management plan the drilling of the sections through the fault and completion (casing run, cementing, etc.) were conducted in trouble-free manner. The prevention measures were implemented as per plan, what allowed to avoid mitigations measures and there was no non-productive time associated with fault.
Successful Troubleshooting to Improve RFCC LPG Amine Absorber Performance
Authors: Thamizhan Velavan Sikkampatti , Darak Nikhil Dwarakanath
Published: November 2017

LPG Amine absorbers are being used for removal of H2S from RFCC LPG stream prior to process in downstream LPG MEROX unit. The underperformance of the LPG amine absorber has adverse impact on downstream unit operation and meeting product specification. Since commissioning of RFCC Unit, LPG product was observed to be consistently off spec with respect to H2S content (>100 ppm against the design of 10 ppm). This high H2S slippage was severely impacting the Refinery operation as below, High caustic consumption in downstream LPG Treating unit & impacting Spent Caustic Treatment unitOff spec LPG product with respect to Disulphide content from LPG Treating UnitRFCC LPG product was not meeting the intermediate LPG sphere storage criteria of H2S content <50 ppm.

In order to troubleshoot and identify the possible reasons for high H2S slippage from LPG Amine Absorber, a team was formed comprising of representatives from various dicipilne and agencies. Systematic way of troubleshooting was adopted with several brainstorming sessions between all the stakeholders. Following actions points evolved out of brainstorming session, Review column operating conditions for any deviation from design operating conditionDesign review of the column internals

Based on in-house simulation and design review of LPG amine absorber, it was observed that existing column internals were inadequate to avoid mal-distribution and the same was deliberated in details with Licensor. Licensor concurred with the findings and packing vendor was engaged for further review. Column internals (Packing, Disperser plate and Distributor) has been redesigned and replaced with new internals. After replacement of column internal LPG product H2S content was observed to be within product specification.
Competency Development for the Next Generation of Petroleum Engineers
Authors: Lau Hon Chung
Published: November 2017

Competency development in petroleum engineers is a life-long process. It starts with the undergraduate education and continues on throughout the career of the petroleum engineer. In this paper, we have identified the key competencies that need to be developed in the next generation of petroleum engineers in light of the increasingly complex, interdisciplinary and global nature of petroleum projects. These key competencies include dimensionsnot found in traditional petroleum engineering and geoscience (PE&G) programs such as leadership, health, safety and environment (HSE), interdisciplinary and intercultural competencies. Our research has shown that geophysics training is missing in most undergraduate PE&G programs. In addition, leadership training at the undergraduate level is a key need for future readiness of petroleum engineering students. The remaining core competencies, HSE, interdisciplinary and intercultural competency, are mostly learned at the workplace. Both university educators, corporate trainers and managers need to adapt their pedagogical methods to build competencies in Generation Y petroleum engineers. Suggestions of what they can do are given. To be effective trainers, they need to act more like mentors than teachers and supervisors.
Subsurface Competencies Verification & Management Model, a Case Study of Upstream Oil & Gas Company
Authors: Al-Daihani Eisa , Nandi Arun Kumar , Razaa Syed Mohammad
Published: November 2017

In order to link all subsurface trainings and staff development activities with HR Strategies of the company, subsurface competencies "Verification & Management" model has been attempted. The objective of the model is to provide a quality "Assurance" and "Control" tool to the management. Besides, this will provide "Internal Verification Process" to ensure acquiring "Competencies" related to specific jobs and provide standard criteria and tangible measures.

There are many definitions of competency. What we have selected for our company is the ability to apply "Knowledge", and "Skills" to perform a Specific Task Effectively and Consistently within Time Frame and demonstrated by "Relevant Behavior".

We need certified competencies to achieve company strategic goals and objectives more effectively by developing competent work force, to select the right people for the right career paths based on competency criteria, to enhance the culture to recognize performance based on knowledge skills and behavior within time frame as per the company personnel policy. The other reasons to have certified competencies are to have consistent approach from joining to retirement, to identify young professionals and Discipline Experts at early stages for "Fast track development" and to execute succession planning effectively.

The paper emphasized on benchmarking the entire model with internationally available resources and came out with a robust recognition flow chart. The implementation processes and workflow has been defined among six stake holders. Besides, roles and responsibilities of different stake holders are defined. Recognition guidelines have been illustrated for progression of an employee from one grade to other. And evidence tools have been designed which will help to verify the competencies.

The model will be helpful in linking subsurface trainings and staff development activities of an employee with HR strategies and will bring transparency in the career progression of an employee.