bluuebunny/crossref_metadata_2025_split huggingface dataset:
Single Trip Sand Control and Cementing System
Authors: Moses Nicholas , Ismayilov Elnur , Newn Edwin , Mogga Emmanuel , Zou ChunLei , Poizat Jeremie , Milne Gordon , Sanni Ireti , Thomson Stewart , Haubrich Blayne 
Published: March 2022

Abstract
The operator of field S initiated a project with a key objective to unlock and increase oil recovery while maximizing the economical oil ultimate recovery and maintaining a daily production with a ceiling unit development cost. The targeted sandstone reservoirs are shallow with unconsolidated formation which require active sand control. To achieve the objectives, a Single Trip Sand Control and Cementing System was developed by the service provider utilizing existing proven technology which was adapted to be a fit for purpose solution. The main driver in developing the single trip system was operational simplicity. The high-level procedure of the system is:
Drill open hole from surface to target depth in a single run. Make up lower completion assembly and production casing and run to target depth. In the same trip, set production packer and release service string. Gravel pack the lower completion or install as a stand-alone screens completion and cement the production casing in place before pulling out of hole.
Once the single trip system was designed and developed, a detailed system integration testing was carried out to ensure that the technology performed as expected. The turnaround time from design to execution was reduced tremendously by utilizing existing proven technology with minimal modification required. From there, 2 wells were identified for a pilot technology trial where this novel system was implemented. The execution of these 2 wells was successful with the expected learning curve of implementing a new system. One of the key findings were the robustness of the system as it was applied in a well with higher than normal doglegs, highly deviated shallow reservoir and the sand screens were run through extended open hole shale sections which would have been cased off in a conventional completion approach. Additionally, the single trip approach allows for further optimization with multi-skilling personnel, and this led to an improved operational efficiency. Post well completion, the 2 wells have been successfully put on production and are producing sand free. This unconventional approach can unlock more marginal reserves that were previously not feasible to be developed economically.
Newly-Developed Visualized Reservoir Characterization While Drilling Technology Improves Understanding of Complex Channel Sand, Assists EOR in a Mature Oilfield in Bo Hai Bay
Authors: Yang Bin , Nie Min Chao , Shen Hong , Li Yu Guo , Xu Nian Da , Zhang Hua Guo , Niu Cheng De 
Published: March 2022

Abstract
PLxx oilfield is a mature oilfield which has been developed by horizontal wells for several years with water-injection production style. It features with shallow, complex, high challenging unconsolidated channel sand with lateral property variation due to pinch out, stacking or lamination. The thickness of pay zone changes from couple of to ten more meters which brings much high challenge to reservoir delineation while drilling and horizontal well placement execution. The oilfield locates at a faulted belt of Bo Hai Bay among which some small faults may happen. But it's difficult to be identified because of the low S/N ratio incurs from the shallow gas effect on the seismic data.
Moreover, uneven flowing zone units exist within sandstone package due to dynamic reservoir production, uncertainty of lateral sand connections and possible inter-well interventions. As such, this makes the oil-water distribution more complicated and the oil-water contact isn't uniform in the sand package.
In order to furtherly understand the complex channel sand, place the wellbore in the favorable sweet spot and enhance the oil recovery, a newly-developed visualized reservoir characterization while drilling integrated technology associated with RSS(rotary steerable system), HSVP(high speed data transmission system), RTC(remote transmission connection through Internet) and OSC(operation support center) was employed to optimize the operation efficiency during a three-wells drilling campaign in this oilfield. This newly-developed reservoir characterization technique is the industry innovative fully 9 components measuring azimuthal Electro-Magnetic propagation tool in one single sub. It provides not only the conventional propagation resistivity but also the geo-signal responses in a very quick, flexible way. In one of the case, the unique "Dual-diagonal orthogonal T-R antenna design" ensures the DOI (depth of investigation) as deep as 6.8meters.
The reservoir boundaries such as the top, the bottom or the oil-water contact were distinctly characterized and the horizontal drainage section was precisely navigated within the profitable pay zone. The post-well reservoir characterization result is comparable with the seismic profile and very helpful to understand the dynamic reservoir flowing zone unit. The excellent performance is also reflected in the oil production; the initial oil production was increased from 40 m3/day to 69m3/day which is 75% higher than expected. Minimum 25% of oil recovery will be enhanced as forecast.
Understanding the Impact of Corrosion on Gas Wells Past its Design Life
Authors: Zaidil Hanani , Wong Sim Siong 
Published: March 2022

Abstract
Field X produces dry gas from a carbonate reservoir with moderate aquifer support consisting of 16 wells most of which were drilled between 1986 to 1987. Up until 2021, these wells would have been in service for approximately 35 years, past its theoretical design life. Based on production forecast, the field is expected to continue producing for another 10 to 18 years. In view of the prolonged life extension, there is a need to review the integrity status of the well to ensure safe production until the end of field life. Wellhead preventive maintenance are conducted on a six-monthly basis to assure safety critical equipment (SCE) functionality and performance. Maintenance data collected since 2008 provides a good view on surface and subsurface valve integrity.
In recent years, observations on external corrosion have received some attention. At the same time, there were efforts in determining and verifying the corrosion rates for production tubing, wellhead and x-mas tree. For well tubing and production casing, load based assumptions were used to estimate the minimum allowable tubular thickness to establish a basis for remaining life estimates. To verify the remaining life estimates, in 2019, a multi-finger caliper log was ran across the tubing of Well B to measure actual metal loss around the pipe. A magnetic log was also run in Well B in the same year to obtain quantitative measurement of remaining metal thickness in 13-3/8", 9-5/8" and 7" tubing. The observations from these exercises indicate that calculated estimates are more conservative as they do not account for the impact of the highly dynamic conditions downhole. While logging provided an independent view of the condition of the tubing and casing, no inspection of the x-mas tree cavity was carried out. An opportunity to close this gap and obtain information on the internal condition of the x-mas tree body is presented to Field X with the abandonment campaign on two idle wells in quarter three of 2021. The x-mas tree was retrieved, and internal inspection was conducted. The same is done for retrieved tubing from the abandoned wells.
This study and its findings will enhance understanding on well design life, especially for vintage wells of over 30 years and provide assurance that wells are safe to produce.
Safety Control Technology of Ultra-High Pressure Gas Wells with Annular Pressure: Case Study of Tarim Oilfield
Authors: Cao Lihu , Sun JinSheng , Zhang Bo 
Published: March 2022

Abstract
Kuqa foreland basin in Tarim Oilfield is the largest ultra-high pressure gas fields in the world, with buried depth of 6000-10000 m and reservoir pressure of 115-14 MPa. Complex geological conditions, extreme working conditions and harsh corrosion environment bring great challenges to the integrity of high-pressure gas wells. This paper introduces the safety control technology for the ultra-high pressure gas wells, which ensures the safe production. For economic development ultra-high pressure gas field, it is essential to control the safety of high annular pressure. Field investigation of abnormal pressure indicates the previous design method and pressure control measures of two-stage barrier decreasing step by step in ultra-high pressure gas wells are difficult to meet the requirements of fine safety control. Therefore, the annular pressure safety control technology with the core of "two-stage well barrier equal strength design, annular pressure dynamic window control and pressure grading control" is established to realize the fine control of ultra-high pressure gas wells. Firstly,in the stage of ultra-high pressure gas well wellbore design, based on the equal strength design method, 140 MPa metal seal easily replaceable casing head and small coupling production casing are developed, which are integrated with the equal strength tubing string and Christmas tree to realize the "double insurance" of wellbore pressure. Even if the primary barrier fails, the secondary barrier can still prevent the leakage of high pressure gas.Secondly, based on international standards such as API RP 90-2 and ISO16530, the calculation method and control chart of annular allowable pressure dynamic window were established before ultra-high pressure gas wells were put into production. To improve the scientific foundation of annular pressure control, the damaged or failure mode of well barrier was taken into account to guide the annular pressure management. Finally, a management method was established for the production of ultra-high pressure gas wells, including risk assessment process and hierarchical management, and the hierarchical response measures are formulated to ensure the safety and stability of oil and gas wells, which can avoid the high risk and high investment brought by work over operations. Based on the safety control technology of ultra-high pressure annulus pressure in Tarim Oilfield, the proportion of oil casing annulus pressure in new wells is reduced from 40% to 0% within one year, and the overall annulus abnormal pressure well is reduced from 29.4% to 19.7%, which ensures the effective development and safe production of ultra-high pressure gas fields in Kuqa foreland basin.
Predictive Modelling of Carbon Dioxide Injectivity Using SVR-Hybrid
Authors: Mardhatillah Mutia Kharunisa , Md Yusof Muhammad Aslam , Sa'id Alva Andhika , Mohammad Fuad Iqmal Irsyad , Sokama Neuyam Yens Adams , Md Akhir Nur Asyraf 
Published: March 2022

Abstract
Southeast Asia is increasingly gaining attention as a promising geological site for permanent CO2 sequestration in deep saline aquifers. During CO2 injection into saline reservoirs, the reaction between injected CO2, the resident formation brine, and the reservoir rock could cause injectivity change due to salt precipitation, mineral dissolution, and fine particles migration. The underlying mechanisms have been extensively studied, both experimentally and numerically and the governing parameters have been identified and studied. However, the current models that have been widely adopted to investigate reactive transport and its impact on CO2 injectivity have fundamental limitations when applied to solve small, high dimensional, and non-linear data. The objective of this study is to develop efficient and robust predictive models using support vector regression (SVR) integrated with hyperparameter tuning optimization algorithms, including genetic algorithm (GA). To develop the model, 44 datasets are used to predict the CO2 injectivity change with its influencing variables such as brine salinity, injection flow rate, particle size, and particle concentration. The performance for each model is analyzed and compared with previous models by determination of coefficient (R2), adjusted determination of coefficient (R¯2), average absolute percentage error (AAPE), root mean square error (RMSE) and mean absolute error (MAE). The model with the highest R2 is selected as the predictive model for CO2 injectivity impairment during CO2 sequestration in a saline aquifer. The results revealed that both SVR and GA-SVR are able to capture the precise correlation between measured and predicted data. However, the GA-SVR model slightly outperformed the SVR model by a higher R2 value of 0.9923 compared to SVR with R2 value of 0.9918. Based on SHAP value analysis, brine salinity had the highest impact on CO2 injectivity change, followed by injection flow rate, particle concentration, and jamming ratio. It was also found that hybridization of genetic algorithm with support vector regression does improve the model performance contrary to single algorithm and contributes to the determination of the most impactful factors that induce CO2 injectivity change. The proposed model can be upscaled and integrated into field-scale models to improve the optimization of CO2 injectivity in deep saline reservoirs.
An Intelligent Selection Model for Optimum Artificial Lift Method Using Multiple Criteria Decision-Making Approach
Authors: Adam Abdelateef M. , Mohamed Ali Ahmed A. , Elsadig Abdelaziz A. , Ahmed Anas A. 
Published: March 2022

Abstract
The urge to design a selection model for a proper artificial lift system is noticeably escalating. It becomes prudent for the operator to consider most, if not all, of the available evaluation and selection methods. The concept behind it is to yield improved production at better conditions than could be expected.
The artificial lift includes five methods, and it is very crucial to select the best method considering the field conditions. In this paper, the best artificial lift is selected using multiple criteria decision-making model which is composed of the combination of Technique for Order Preference by the Similarity to Ideal Solution (TOPSIS) and the Analytic Hierarchy Process (AHP).
This new user-friendly model undertakes 15 essential technical factors sorted into three sets (well data, reservoir data, and quantitative data) each factor has its own weight in the final selection decision. Furthermore, the Results depicted in bar graph for further illustration. It is important to note that the final decision is entirely based on technical manners. Additional economic evaluation and detailed cost analysis are required when the model results in close outputs between alternatives.
Lastly, this integrated model was tested on 12 wells from block-4 and Block-6 in Sudan, inputs were real-time data from initial and status. Successfully, in the end, it yielded its theoretical results.
Riser-Less Surveillance for Aging Subsea Wellhead with Light Construction Vessel
Authors: Sripramote Pobtorn , Yingvorapant Worawit 
Published: March 2022

Abstract
Legacy Unocal have drilled hundreds of exploration wells between 1970's to 1990's in Gulf of Thailand with semi-submersible drilling rigs and drillships. Those exploration wells were plugged and abandoned as per the requirements back in the 1970's which the subsea wellheads were not cut and removed. According to asset retirement obligation, all structures above seabed need to be removed before returning concession area. These subsea wellheads are planned for cut and recovery, however, there are many uncertainties in regard to well conditions which includes trapped gas in casing annulus and casing corrosion. The correct and safest approaches to cut and recovery are to perform wellbore logging runs, gas evaluations, and casing wall thickness investigation.
The challenges faced in executing the logging runs in open water environment are to conduct safe, efficient, and reliable operations on Dynamic Positioning (DP) vessel which includes a work-class Remotely Operated Vehicle (ROV). The key factor is to attain as much information and quality logging data to engineer a successful cut and recovery campaign for these complex subsea abandonments.
To perform this operation in open water, it can lead to inaccurate logging data due to uncompensated conditions. An innovative solution was collaboratively invented and developed with Business Partners to deploy Logging Tower Subsea Deployment system (LTSDS) to mimic static logging condition. The tower is self-standing design with a capability to rig up on different type of wellhead. The trial was performed but had complications of deployment due to weather impact. The new method, non-compensated real time logging on Electric Line, was introduced to improve time spent per wells. The comparison of logging results from both methods shown similar and reliable log interpretations. The remaining wells were logged with non-compensated real time method, which reduce operational time by 45% as well as lower associated operational risks.
Other challenges encountered included logging depths 100 ft below mudline. Since some wells have shallower holdup depths or the tool could not pass due to encountering obstruction at shallow depths, gauge cutter was deployed with slickline unit to remove obstruction, followed by downhole high pressure jetting tool which was effectively helping to achieved logging intervals.
Interpretation of logging data were completed on more than 100 wells and results were used to engineer a detailed cut and recovery campaign and utilize new technology that the team had sourced to execute the operation.
With innovative designed set up of riser-less operation on light construction vessel, it is proven to meet objective of reliable logging data and cost efficiency and demonstrated flexibility for operation improvement.
Laboratory Study on the Use of Novel Biodegradable Scale Inhibitors Against Mixed Calcium Carbonate and Calcium Sulfate Scale
Authors: Husna Ully Zakyatul , Elraies Khaled Abdalla , Shuhili Juhairi Aris B. M. , Tewari Raj Deo 
Published: March 2022

Abstract
The development of the scale layers in oil and gas operation results in production losses and equipment instability because of pipeline blockage, energy leak, corrosion acceleration and severe accidents which will impact the safety of production. Among many types of scales, calcium carbonate and calcium sulfate are considered the most frequent, prominent and terrible. On the other hand, cellulose is a class of natural polymers and also contains abundant functional groups including hydroxyl, carboxyl, and amino groups, resulting in good chelation and dispersion effects. They possess good physical and chemical properties, thermal stability, and biodegradability, abundantly available and inexpensive which make them promising compounds for the creation of "green" oil field reagents, including scale inhibitor. In this study, we tested two types of biodegradable polymers named hydroxyethyl cellulose (HEC) and carboxymethyl cellulose (CMC) for application as calcium carbonate and mixed carbonate and sulfate inhibitors. There are three methods carried out, starting from the thermal stability test, static bottle test, and dynamic scale loop test. The inhibition performance tests were done at temperatures of 50°C, 70°C, and 90°C. The inhibitor concentration was varied from 10, 50, 100, 1000 until 10000 ppm. The results indicate that both HEC and CMC have the potency to be used as inhibitors for these two types of scales. Both results from the static bottle test and dynamic scale loop test indicate that HEC and CMC were able to inhibit the formation of the tested scale, yet they have not been able to completely inhibit 100% of scale formation.
IGUSA: Prediction of Ultimate Strength of Fixed Offshore Structures in Malaysian Waters Using Machine Learning Techniques
Authors: Ishak Muhammad Izzat Muhaimin , Lemma Tamiru Alemu , Muhammad Daud Mohd Hafis , Mohd Fatimi Norfazlin , A. Rahman Ahmad Rizal , A. Rahman Azam , Othman Abdul Rahim 
Published: March 2022

Abstract
IGUSA (Intelligent Global Ultimate Strength Analysis) is a tool developed by PETRONAS to predict the ultimate strength of a fixed offshore jacket platforms installed in Malaysian waters using machine learning techniques.
The ultimate strength, or more commonly represented by Reserve Strength Ratio (RSR), is a gauge of the robustness and redundancy inhibited in a fixed offshore structure. It is very useful in being an indicator for fitness-for-purpose of the platform and which is an integral part of Structural Integrity Management (SIM). However, a typical deterministic ultimate strength analysis for a fixed offshore structure is a time intensive process, using specialized software in the realm of plastic collapse analysis. As such, it is intended that machine learning techniques to be utilized to perform a prediction for the RSR, subsequently optimizing resources in SIM processes.
This paper will discuss the development of data-driven predictive model of IGUSA. Various machine learning techniques were experimented on PETRONAS' Global Ultimate Strength Analysis (GUSA) data. The objective is to obtain an accurate and reliable model to predict the RSR. Nonlinear regression using Artificial Neural Network (ANN) was found to provide the best model to predict the Base Shear Collapse, and hence the RSR for a typical jacket platform. The ANN model was incorporated into the IGUSA tool for deployment within PETRONAS. It is envisaged that IGUSA will be a valuable rapid screening tool for the typical platforms and the deterministic ultimate strength efforts can be focused on the more critical platforms.
Based on IGUSA development, the usage of machine learning techniques is proven to be useful in the structural engineering discipline. It is hoped that IGUSA will be able to assist PETRONAS and other Oil and Gas Operators in the region to optimize their resources in SIM processes.
A Workflow for Shale Play Exploration and Exploitation
Authors: Khan Muhammad Hanif , Yousaf Warda , Sadaqat Bilal , Javed Naila , Olukade Abdulrahman 
Published: March 2022

Abstract
This article aims to give an outline of an integrated geoscience approach that may apply in the initial identification of the shale play, address complex unconventional reservoirs, their associated challenges and finalise the pilot vertical wells to evaluate their potential.
Shale exploration depends on the proven source rock within the basin, so the availability of the required data, well data and seismic data in public domain for initial study and basin screening is usually easy. The investigation may start after knowing the well developed proven source rock in the basin. An extensive study of structure, tectono-stratigraphy, source rock and reservoir characterization, thermal maturity models and exploration strategy is required by using the regional tectonic history, drilled wells with multiple penerations in source rock, open-hole logs, mud samples and cores of the source rock to get the answers to the critical questions on the attributes that influence shale plays. Once these attribute questions have been satisfactorily confirmed to be in the required range or with an analog, that data can be utilized to locate possible sweet spots to drill pilot vertical wells with the goal of acquiring extensive coring, open hole logging and formation pressure testing data to identify the best candidates for further horizontal well evaluation.
This article highlights and demonstrates a possible step by step workflow for the selection of the shale play area, sweet spot and pilot vertical wells locations by using the schematic data maps, published material examples and building possible cut offs essential for exploration decision process.