bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recovery of Casing Gas from Remote and Scattered Oil Wells
Authors: Cui Xiangyu , Weng Yibin , Xue Ming , Xu Wenjia , Fan Junxin 
Published: November 2017

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.