bluuebunny/crossref_metadata_2025_split huggingface dataset:
Non-Portland Cement Slurry Development and Application for Ultrahigh-Temperature Geothermal Well with Supercritical Conditions
Authors: Martino Guido Di , Ruch Andreas 
Published: October 2018

Abstract
Exploring supercritical fluids and investigations of their characteristics for geothermal use requires risk minimization similar to those in oil and gas applications. The geothermal operating company leading the DESCRAMBLE (DESCRAMBLE 2018) project consortium within the European Union's (EU) research and innovation programme Horizon 2020, requested a tailored cement slurry suitable as a dependable long-term barrier and appropriate cementing practices which suit the targeted K-horizon's expected supercritical conditions.
A scouting study was performed testing two different Portland-cement silica flour blends under targeted conditions. Additionally, a blend comprising calcium aluminate phosphate cement was selected for this test series. Non-Portland slurry designs have been used in high-temperature geothermal wells (Berard, 2009) as well as in steam injection applications (Li, 2016).
Because of testing equipment limitations, samples were cured at 200°C/206 bar and then heated to 450°C at ambient pressure during the scouting phase. The non-Portland design proved to be the best candidate, although all three cement designs showed cracking. As a result, it was decided to further improve the non-Portland cement's mechanical properties by adding modifiers that would not affect the high-temperature rating of the cement. During the second phase, it was also necessary to consider the operational side of slurry design, as placement temperature was 200 °C with a requirement of more than 5 hours thickening time, which is near the upper limit for a non-Portland cement blend. Additionally, testing conditions were ramped up close to supercritical conditions during initial curing, and samples then underwent further curing at 550 °C and ambient pressure. Tri-axial mechanical properties were evaluated after cooldown.
From an operational aspect, it became apparent during lab testing that mixing order was important as well as extended temperature simulation to help ensure the well was properly cooled down before cement placement. Once all laboratory testing, simulations, and operational preparations were complete the actual 7-inch liner cementing operation was performed with the desired results. Use of a specially modified calcium aluminate phosphate cement blend was successful and initial results from the well showed that this cement system was properly tailored to the geothermal well conditions.
Only a few geothermal wells have been attempted previously under such conditions, hence it was necessary to create and deliver a modified cement slurry design for both geothermal and oil and gas applications. Further monitoring of the cement sheath will be conducted to evaluate long-term properties.
A Sustainable Approach to Production Increase in the Zawtika Field: Sand Control Assisted with Hydrofluoric Acidizing
Authors: William Colin , Grant Graham , Choodesh Attawit , Ramirez Cristian , Nusyirwan Ahmad , Santoso Doffie Cahyanto 
Published: October 2018

Abstract
Sand and fines production in oil and gas wells are a major challenge that can result in production system failures. In unconsolidated sand reservoirs, proper sand-control practices are necessary to help prevent reservoir sand production. To remove formation damage and control fines migration, acid treatments are pumped ahead of sand-control treatments, which can be challenging because variations in mineralogy determine fluid performance and require a customized fluid selection. For this case, improvements in cased hole sand-control completions were initially sought by switching to high-rate water pack (HRWP) or fracture for placement of gravel (FPG) techniques; however, obtaining fracture conductivity and minimizing out-of-zone fracture growth was challenging. To accomplish the latter, fluid selection was optimized with linear-gel systems and relative permeability modifiers as prepad systems. Operators should know the formation's composition at the treatment point for a successful acidizing treatment to be performed. The dominant mineral component and temperature of the target formation determines the most effective preflush, hydrofluoric (HF)/hydrochloric (HCl) acid treatment blend, and preflush/treatment volume.
The successful implementation of HRWP and FPG techniques produced excellent results with regards to skin minimization and production maximization. The HRWP technique was applied when gas/water contact was nearby, allowing flow from a moderate to high payzone kh (permeability × net pay), and FPG was used to produce a proper flow in low kh formations.
The goal of sandstone-matrix acidizing is to remove siliceous microparticles blocking or bridging pore throats by injecting acid formulations containing HF acid. The presence of potassium feldspars, sodium feldspars, illite, and zeolites is a concern because these compounds can form or contribute to forming significant matrix-blocking precipitates, such as sodium or potassium fluosilicates and aluminum fluorides, during HF/HCl treatments. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The goal is to minimize the risk of over acidizing the near-wellbore region and to extend the reaction for deeper penetration when possible. In some cases, the acid systems with the equivalent strength of up to 1.5% HF acid were used.
This paper describes the planning process, acid treatment selection based on laboratory testing, placement and diversion techniques, sand-control completions selection, operation summary, and evaluation of treatment success.
Using Simultaneous Gyro Measurements to Determine Orientation of Magnetic Ranging Instruments in a Vertical Environment
Authors: Rassadkin G. , Ridgway D. , Moss C. J. 
Published: October 2018

Abstract
A variety of magnetic ranging methods are used to determine distance and direction between a magnetic field sensor and a magnetic field source. If the sensor is in a near vertical hole, it may be difficult to orient the sensor's axes relative to known world coordinates, since no gravity high side is available. This can create difficulties calculating and applying ranging results. A magnetic azimuthal toolface may also be impaired due to magnetic interference.
To address this problem, we combine and align ranging and gyro systems in one tool-string and use simultaneous gyro attitude measurements to define the orientation of a ranging system with respect to True North. We apply this technique to two distinct magnetic ranging methods. The first method consists of a solenoid based ranging system. The example shows how this method was used to drill a precisely parallel wellbore in a close proximity to a previously drilled vertical well. The second described method consists of an at-bit-while-drilling ranging system that was used to safely pass by a vertical well while drilling a horizontal well in a close proximity.
The paper compares the results of alternative north orientation techniques for magnetic ranging versus the simultaneous gyro attitude referencing. The alternative techniques include a magnetic north orientation and the north orientation derived from a prior downhole survey and gravity high side tool face. The results show that the described technique can improve magnetic ranging accuracy by up to 10-fold over the previous methods. The paper provides 2D and 3D visualization and numerical analysis of the listed north orientation techniques applied to the magnetic ranging methods.
Simultaneous gyro measurements can significantly improve magnetic ranging accuracy. The applications for the described technique include relief well drilling, plug and abandonment, collision avoidance/risk mitigation, civil and mining projects.
CwD – Enables for Successful Extended Reach Drilling. First Time with 9 5/8" Casing at High Angle
Authors: Amar M. S. , Za'ba M. A. , Liew A. 
Published: October 2018

Abstract
State of the art technology provided by Casing-drilling Services has successfully delivered an Extended Reach Drilling well (ERD) under one of the most challenging scenarios. Challenge consisted on drilling the well from a triple-splitter wellhead in a Malaysian offshore field, navigate through a highly collision-prone platform, pass through a zone prone to loss circulation, and ultimately set up the casing as deep as possible to allow producing from the objective zones, which is located at adjacent fault block.
To enable this long ERD well, the surface casing must be set as deep as possible for higher chance of success in reaching reservoir objectives. The triple-splitter wellhead design with 13 3/8-in. conduit constrained the casing design to smaller casing design. The engineering framework and the drilling techniques had to be adapted to overcome the expected challenges. Analysis of the solutions developed during design and execution, the outcome of the solutions, and the learnings from the project have been documented.
The directional casing-drilling technique enables the surface hole to be drilled as deep as possible with a dynamic kill-while-drilling with a diverter in the event of any kick or shallow gas hazard. A feasibility study was performed during which all the key hazards from anti-collision in this highly congested platform, offset well losses, and well control issues were collected and mapped. After numerous engagements with industry expert/SMEs from both the operator and service providers, casing-drilling technology was selected based on lowest risk and highest chance of success. Strong collaboration at early planning stages was vital in this scenario where all the existing casing-drilling techniques and operational practices were challenged.
The execution result was highly successful. This was the first application of directional casing-drilling from a triple-splitter wellhead with polycrystalline diamond compact (PDC) bit. The PDC bit has allowed significant increase in weight on bit (WOB) and subsequently an increase in rate of penetration (ROP), which is comparable to conventional drilling. In addition, the casing-drilling service eliminates the need to drill a pilot hole where dynamic kill is not possible. This case study provides guidelines, from the planning work to successful field execution, that can be applied for ERD well design.
High Challenging Tight Oil Development by Integrating Innovative Reservoir Boundary Detection Technology into High Efficiency Horizontal Drilling Campaign in West China
Authors: Zhang Jiafeng , Zhi Chennai , Zhu Jianxin , Ye Yiping , Li Tong , Wang Fei , Wang Yong , Li Shuzhong 
Published: October 2018

Abstract
In West China, MH field is typically featured with complex high challenging unconventional reservoir. Very tight conglomerate lithology composed of volcanic rock, claystone and limestone cement as the matrix with average porosity of 9.6% and average permeability of 0.96md. The buried depth of target reservoir is around 3180m. The oil production of vertical well is about 5~6t/day after stimulation (fracturing) while horizontal well production is more desirable and about 3-4 times of vertical wells.
However, the operator faced much high challenges in horizontal drilling such as unstable long open hole interval, extremely slow rate of penetration (about ~3m/hour) in abrasive, grinding conglomerate and shale cap rock (less than 1m/hour). Reservoir structural and stratigraphic uncertainty such as local formation dip changes, 3-5m thick tight sand stacked or pinch out, inconsistent shale inter-beds and oil pay lateral variations often result in unexpected exits from target pay. In current industrial downturn, XOC (Xin Jiang Oil Company) is never so urgent in pursuit of a cost-effective way to secure high efficiency horizontal drilling campaign and successful development of this kind of unconventional tight reservoir.
A pilot project of 6 horizontal wells drilling campaign was launched. The result shows that conventional drilling and measuring while drilling technology like Motor plus GR only was not adequate to address the drilling issues, improve drilling efficiency and achieve the horizontal Net-to-Gross (reservoir exposure rate) objective. However, since the latest high DLS (Dogleg Severity) RSS (rotatory steerable system) drilling technology and unique boundary mapping technology was introduced to XOC and applied in 2016, the drill efficiency and well placement NTG was significantly improved. Boundary mapping technology realized proactive real time geo-steer the wellbore to stay in target sweet spot by detecting reservoir top/bottom at 2-4m TVD away. It significantly increases space for timely decision-making and avoid unplanned exiting from target zone. The newly developed hybrid RSS drilling technology can provide as high DLS as 17degree/100feet and ensure smooth hole in a fully rotate fast-drilling way. The first batch drilling of 10 wells was completed with above technology application, horizontal section ROP increase 47.8%~103% and average footage per run increase 49.1%~59.1%.
With the success of the first 10 wells, XOC decided to extend the employment to whole MH field which will have more than 55 horizontal wells. This paper will delineate the technology application optimization through some distinctive case studies.
Rig Time Optimization and Risk Mitigation Utilizing Through Drillpipe Logging Technique with Slim Wireline Logging Suite
Authors: Ngo H. , Chommali P. , Charucharana T. , Rattanachan S. , Ung-Aram K. , Tangkaprasert P. , Thiangtham C. , Pinprayong V. 
Published: October 2018

Abstract
The Sirikit field is a mature reservoir located in the Phitsanulok Basin in north-central Thailand. The field produced first oil in late 1981. Typical logging programs include a complete set of openhole (OH) logging suites such as a triple combo, including gamma ray-neutron-density-resistivity, or quad combo including gamma ray-neutron-density-sonic-resistivity. The reservoir production and injection are carried out with commingled completion. Therefore, wireline formation testing, and sampling tools are usually included for acquisition.
Development wells with highly deviated trajectories pose challenges to conventional wireline logging (WL) operations, especially in deep wells exceeding 3,000m. In sections with high dogleg severity, the tools are prone to sticking, and the cable can become key-seated due to hole conditions, deviation, washouts or caving.
Log data is a vital component for studying geological complexity, completion and production planning. Therefore, there is a need for an alternative method to convey WL tools to reach the bottom of the hole. In 2015, an alternative conveyance method called "through drillpipe logging" (TDL) was proposed to mitigate the risk of WL tools sticking or hanging up in an openhole environment. This method uses a slim-chassis, 2.25 in. outer diameter (OD), WL logging suite that enables the tool to be run through the drillpipe. The first TDL job was trialed in Thailand in May, 2016 as the second run after the WL run hung up. This TDL run hosted a full triple-combo suite and WL formation testing tools, which reached total depth (TD) while overcoming hole-condition issues that had been experienced during the first run. Following this successful log run, the TDL has become the preferred contingency planning option to support WL operations in challenging wells. To date, a total of 64 jobs, including triple combo (TC), quad combo (QC), formation testing & sampling (FTS) and cross-dipole sonic (CDS) have been executed successfully with less operating time than conventional contingency processes involving wiper trips, tool pushing, or pipe conveyed logging. This track record confirms that TDL provides a fit-for-purpose solution for logging in challenging conditions.
Performance Improvement from Drilling Control Systems Alarm Management and Analytics
Authors: Goetz Christopher 
Published: October 2018

Abstract
Control Systems Alarms on offshore rigs are inarguably poorly designed. Drilling Control Alarms Systems (DCAS) in particular, are notorious and the pack leaving much to be desired. Excessive alarm volumes on these Integrated Control Systems (ICS) lead to Driller alarm blindness and exceed all industry recognized standards. The problem is exacerbated by the general lack of a Human Machine Interface (HMI) console dedicated to the maintenance crews or other roles to leverage for equipment insight and preventative maintenance.
Because of these conditions, Drillers are inundated, and critical alarms are often ignored. Maintenance crews are reactive, resulting in missed preventative maintenance opportunities and equipment failure or non-productive time (NPT). The result is a general opinion that these DCAS are poorly designed, and the alarms themselves are not useful.
This paper will work to alter that perception through illustrating that the DCAS do indeed contain useful information if examined with the correct lens. Additionally, this paper shows that Drilling Contractors have the tools at their disposal to leverage this lens on any ICS. It will illustrate how that can be done, as well as discuss some of the best practices that Drilling Contractors ought to adopt to improve the capabilities of their DCAS.
Achieving Performance Excellence Through Integrated Efficiency Workflow Services
Authors: Soong A. , Arriffin M. F. , Rosland H. A. , Ismail B. 
Published: October 2018

Abstract
Issues emerged from complications with multiple sources of information, including (but not limited to) time taken to complete an entire well, costs involved, and potential risks that can disrupt the duration necessary to analyze offset wells for field development planning. Currently, there is an absence or a less visible workflow or informational standardization because different divisions and field teams work on silo-based knowledge and procedures. To make matters worse, sufficient data are being logged and stored in servers without being used in constructive ways.
This paper discusses a solution that helps save time and regulate standard operating procedures (SOPs) when planning well authorizations for expenditures (AFEs) using actual stored well data, particularly during field development planning. The solution reviewed in this paper can also assist the operation team when reviewing and help improve rig operation performance, such as drilling and pipe tripping, by comparing processed data for rig vs. rig, well vs. well, or field vs. field, whichever end users desire. Additionally, it can statistically map out potential risks and visible/invisible nonproductive time (NPT). Existing server data can then be reviewed to help ensure stakeholders make calculated decisions based on quality data.
Innovative and Cost-Effective Invert-Emulsion Fluids for Drilling Complex Wells
Authors: Al-Bagoury M. , Revil P. 
Published: October 2018

Abstract
Formation losses, high torque and drag, managing equivalent circulating density (ECD) and barite sag are some of the most frequent challenges operators face while drilling complex wells such as deep water, extended reach or narrow pressure margin wells.
Invert-emulsion fluids are used to alleviate these challenges. However, the design of invert-emulsion fluids needs to be tailored to overcome specific drilling challenges. This paper describes the design of invert-emulsion fluids using synthetic base oils such as MG3 DF, Sarapar 147, Saraline 185V and EDC 99 DW and weighted with micronized ilmenite to densities up to 2.30 sg (19.2 ppg) and temperatures up to 232°C (450°F) to handle such challenges. These fluids show the ability of micronized ilmenite to provide significantly lower rheologies to control ECD, significantly reduced sag potential and lowered formation damage. Formation damage potential was assessed using high and low permeability sandstone formation cores.
Ilmenite is acid soluble and easy to remediate if required. The acid solubility of ilmenite will also assist in freeing stuck pipe, which is not the case with barite weighted systems.
Fluids with micronized ilmenite have been effective in obviating drilling challenges. This paper presents designs for high-density, cost-efficient fluids weighted with micronized ilmenite for the drilling of challenging wells. This fluid was used to drill and complete 14 ERD wells with measured depths of &gt;36,000 ft. Utilization of this reservoir drilling fluid has contributed to increased reservoir contact, improved productivity and provided a reduction in non-productive time (NPT).
Egina Deep Water Project Completion Success: One Team Working Together Setting New Performance Standards
Authors: Johnson Kenneth , Morand Christophe , Williams Mark , Okengwu Victor , Akinniyi Temitope , Chaloupka Vladimir , Djenani Romain , Okpalla Chinedu , Bassey Unwana 
Published: October 2018

Abstract
A service company was challenged to deliver best-in-class upper and lower completions by leveraging deep water completion experiences throughout West Africa with the operator and service company's global best practices and lessons learnt. An operator reduced lower completion times, standalone screens, and open hole gravel packs by 60% between the 1st and 24th well while reducing upper completion times by 40% for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies and run reliabilities exceeding 97%.
Production has Spoken, Listen to Your Reservoir Needs and Technology Respond - A Case Study of SS Field Development
Authors: Zakariah A. , Rosland E. A. , Afandi T. , Goh K. G. 
Published: October 2018

Abstract
SS Field with its longer production data now available has enabled further validation of the previous assessment (i.e. SPE-17005 by N. Noridah et all, 2013) of the reservoir needs and technology respond in this field to-date. This paper also highlights the effectiveness of the field-wide downhole flow control solution in terms of more oil and managing undesired field water-cut. It is scrutinized based on the actual field Ultimate Recovery (UR) versus the predicted recovery to further optimise recovery in infills plan.
Extensive evaluation on production performance was conducted well-by-well to engage the overall field performance. The actual production performances are clustered in the categories from the ‘underperformers’ to the excellent producers, considering the reservoir attributes such as reservoir characterization, geological understanding and contacts movement. Meanwhile, technology responds in terms of zonal control efficiency across the sandface is analyzed for improved comingled oil production multi-zones. The assessment is further applied in the infill well-creaming for the extended development plan in SS field.
The study correlates the best reservoir attributes to the technology respond in order to maximize future infill recovery in ensuring fit-for-purpose implementation. Years of production experience have demonstrated a consistently better recovery of SS field against the expected FDP. 75% of the producer meet the FDP production target which contributes towards overall field &gt; 25% EUR despite only near the half of the production life (~20 years).
SS Field is the first pilot PETRONAS field applying field-wide downhole flow control (12 wells) and intelligent Completions (2 wells). An integrated evaluation of the production performance in this field with subsurface understanding is paramount for technology replication. It is a case study that serves as a benchmark for development decision in other fields with similar reservoir characteristics. It also serves as best-practices and lesson-learnt to provide a better insight of a downhole flow control solution efficiency in the late-production strategy of suppressing water for further production enhancement via EOR / infills.