bluuebunny/crossref_metadata_2025 huggingface dataset:
No Difference in Outcomes Between Short and Longer-Stay Total Joint Arthroplasty with a Discharge Home
Authors: Leroux Timothy S. , Maldonado-Rodriguez Naomi , Paterson J. Michael , Aktar Suriya , Gandhi Rajiv , Ravi Bheeshma
Published: November 2019

Background:

Outcomes following total hip arthroplasty (THA) and total knee arthroplasty (TKA) with a short length of hospital stay have been reported; however, most studies have not accounted for an inherent patient selection bias and discharge disposition. The purpose of this study was to utilize a propensity score to match and compare the outcomes of patients undergoing THA or TKA with short and longer lengths of stay with a discharge directly home.

Methods:

An administrative database from Ontario, Canada, which has a single-payer health-care system, was retrospectively reviewed to identify patients who underwent THA or TKA from 2008 to 2016. Patients were subsequently stratified into 2 groups based on their length of stay: short length of stay (≤2 days; thereafter referred to as short stay) and longer length of stay (>2 days; thereafter referred to as longer stay). Using a propensity score, patients who underwent short-stay THA or TKA were matched to patients who underwent longer-stay THA or TKA. Matching was based on 15 demographic, medical, and surgical factors. Our primary outcomes included postoperative complications, health-care utilization (readmission and emergency department presentation), and health-care costs.

Results:

Overall, 89,656 TKAs (14,645 short stays and 75,011 longer stays) and 52,610 THAs (9,426 short stays and 43,184 longer stays) were included in this study. Patients who underwent short-stay THA or TKA were significantly more likely (p < 0.05) to be younger, male, healthier, and from a higher socioeconomic status and to have undergone the procedure with a higher-volume surgeon. Over 95% of short-stay cases were successfully matched to longer-stay cases, and we found no significant difference in complications, health-care utilization, and costs between patients on the basis of the length of stay.

Conclusions:

Patients undergoing short-stay THA or TKA with a discharge home were more likely to be younger, healthy, male patients from a higher socioeconomic status. Higher-volume surgeons are also more likely to perform short-stay THA or TKA. These characteristics confirm the previously held belief that a selection bias exists when comparing cohorts based on time to discharge. When comparing matched cohorts of patients who underwent short-stay and longer-stay THA or TKA, we observed no difference in outcomes, suggesting that a short stay with a discharge home in the appropriately selected patient is safe following THA or TKA.

Level of Evidence:

Therapeutic Level IV. See Instructions for Authors for a complete description of levels of evidence.
Rotational Tibio-Pelvic Constrained Hip Arthroplasty: A Surgical Technique
Authors: Cahill Sean V. , Yu Kristin E. , Dussik Christopher M. , Lee Francis Y.
Published: November 2019

Case:

A 25-year-old man presented with chronic bone and soft tissue infection of the right thigh following resection and radiation of epithelioid sarcoma. Multiple revisions and debridement procedures had failed to control the infection and left him unable to ambulate. We describe a modified Van Nes rotationplasty using a constrained, prosthetic hip between the tibia and pelvis following femur resection. With 18 months of follow-up, the patient was able to walk with a prosthetic device without evidence of recurrent infection.

Conclusions:

We report this rotationplasty as a potential approach to avoid hip disarticulation in cases requiring extensive debridement for incurable infection.
Optimization of the SAGP Process in L Oil-Sand Field with Response Surface Methodology
Authors: Kang Xiaodong , Li Baozhen , Zhang Jian , Wang Xudong , Yu Wei
Published: November 2019

In this study SAGP (steam and gas push) technology was designed to improve the thermal recovery efficiency in L oil-sand field, where traditional steam flooding efficiency was unfavorable with high steam oil ratio and expensive operation cost. The optimization of SAGP process were performed with numerical simulation and response surface method "Box-Behnken", which could be done with acceptable accuracy by performing a limited number of runs, hence, reducing the engineering time and effort. With the simplified equation between the EOR and different SAGP parameters including Injection gas type, injection time, injection gas mol% and volume, operators could determine the best combination of all the factors according different conditions efficiently. This study provides critical insights for understanding the SAGP flooding mechanism and its effect on SAGD flooding effectiveness in the oil sand field, which also delivers a good reference for improving the development efficiency of oil sands with better economic benefits.
IMO 2020 May Only Be A Beginning -Reinforcement of Maritime Environmental Regulations and Its Impact on Oil & Gas Industry
Authors: Nakano Michihiko
Published: November 2019

In 2016, the IMO has decided that the global fuel Sulphur limit of 0.50% on marine fuel oil would enter into force on 1 January 2020 ("IMO 2020 Global Sulphur Cap"). It is one of the biggest challenges for the marine industry that it had experienced in the modern era for its magnitude and urgency. Then in 2018, the IMO adopted an initial strategy of the reduction of greenhouse gas emission from international shipping in 2018 ("IMO GHG Initial Strategy"). It is a landmark decision by the IMO as it envisions a reduction gross greenhouse gas emission from international shipping and phase them out entirely for the first time. The IMO GHG Initial Strategy is not imminent comparing with the IMO 2020 Global Sulphur Cap, but it would be more serious and strenuous for its technical difficulties or practicability. By this presentation, we are going to describe where we are and where we are headed as to this topic by illustrating history and background, on-going discussions and trend on incremental reinforcement of environmental restriction in the maritime sector, possible options and solutions and those innovation gaps and so on.
Technologies and Practices to Push The Extended Reach Drilling Envelope within The Existing Constraints
Authors: Paila Phalgun , Singh Rudra Pratap , Abid Kashif
Published: November 2019

Optimizing resources and pushing the drilling limits to tap into deeper reservoirs at minimal cost has always been the primary objective of many operators worldwide. Moreover, the prolonged current market conditions are pressurizing every stakeholder involved within the well-delivery process to reduce time and the associated costs like never before. This paper deals with an Offshore Artificial Island project where the drilling limits were constantly challenged by adopting new technologies and practices in an extended-reach drilling (ERD) campaign.

The complexity of these extended-reach wells was managed effectively with excellent planning and execution. Implementation of new and existing technologies and the adoption of revamped operational practices has managed the challenges of equipment capabilities, torque and drag, ECD, wellbore stability, hole cleaning and stuck pipe avoidance to name a few. The project drilled longer wells at less costs. This approach has resulted in drilling and completion of wells comfortably within the equipment-rating envelope. Additional technological means such as newly developed lubricant and mechanical drill pipe torque reducer subs helped reduce the friction factor and eliminate drill string buckling. Existing technology in the bottom-hole assembly (BHA) minimized the tortuosity in the wellbore, along with transmitted real-time downhole drilling data (Torque, Weight on Bit, Mechanical Specific Energy, and Equivalent Circulating Density) which helped in active drilling parameters optimization for efficient drilling. Similar technologies and practices were used in landing the completion string.

The geo-mechanical studies undertaken at the concept stage and later revised against the offset well information helped in drilling the troublesome shale formations with no associated events. Specific importance was given to maximizing the hole cleaning by having the right tools in the BHA that could accommodate higher flow rates while using a tandem drill string for lower hydraulics. In addition, the newly formulated field / formation specific drilling and reaming practices minimized the stuck pipe, saving approximately 10% in overall well costs.

This paper discusses the successful drilling of a number of offshore ERD wells with various complexities and tailored solutions with minimal downhole problems and within continuously revising planned times and budgets. The lessons learned and techniques associated with drilling of extended-reach wells at lower costs will be detailed in this paper. This information would give insights and considerations to all stakeholders who intend to drill extended reach wells or challenge their current limiters. This proven successful methodology and its results are considered a benchmark for the nearby fields in the region.
A Subsurface Sectorization Workflow for Assessing Reservoir Properties, Screening for Remaining Hydrocarbon Volumes and Ranking of EOR Methods to Improve the Reservoir Ultimate Recovery Factor
Authors: Gerges Nader , Rihet Jeremy , Walley Stuart
Published: November 2019

Enhanced Oil Recovery (EOR) strategies are becoming increasingly common in the Middle East, used primarily for optimizing mature fields. The final location, selected for any EOR scheme, is often critical to its ultimate success and developing new methods to investigate the most optimal EOR locations can add significant value in optimizing recovery from mature fields. One approach for a given field, is to subdivide 3D Geo-cellular model into different sectors and perform a statistical analysis of the 3D model's properties (porosity, permeability, saturations, etc.) in each individual sector. This task is usually performed manually and can be resource intensive and time-consuming. In particular, in the case of large mature fields in the Middle East, the scale and data volume involved often makes the workflow impractical to implement. Advanced ‘automation methods’, developed to rapidly generate EOR sectors and perform the statistical analysis of 3D model properties are therefore necessary. This work presents a new workflow implemented for extracting and analyzing model properties at a scale relevant for EOR planning in large scale Middle East Fields.
ExxonMobil's Experience with Sour Gas Treating and Acid Gas Handling
Authors: Northrop Scott , Seagraves Jenny , Ramkumar Shwetha , Cullinane Tim
Published: November 2019

Development of sour gas reserves involves extraction, treating, and disposal steps that can be operationally complex. Historically, highly sour gas reserves are left undeveloped because of the technical challenges and high production costs. These reserves are now being reevaluated as potential sources of supply in areas with high demand for natural gas.

To address development challenges, ExxonMobil has applied a dual approach to advancing technologies. First, our broad experiences and well-defined best practices are used to select technologies that best meet the "routine" aspects of sour natural gas development and production. Second, ExxonMobil's industry-leading research capabilities are applied to create new technologies that make treating of difficult sour gas streams feasible.

ExxonMobil has over 70 years of experience in operating and developing technologies for gas treating. Relevant experiences will be described along with the efforts to develop and apply innovative technical solutions needed to develop these reserves. Examples include FLEXSORB™ SE solvent for acid gas enrichment and tail gas clean up, the Controlled Freeze Zone™ process for separating significant concentration of contaminants from natural gas, and cMIST™ technology for dehydration and selective H2S removal from raw gas. Each of these technologies will be discussed in some detail, as will our general experience with sour gas treating.

This paper illustrates how new technologies developed by one company can become part of the body of applied science that ultimately benefits the broader industry.
Real-Time Estimation and Management of Hydrate Plugging Risk During Deep-Water Gas Well Testing
Authors: Zhang Jianbo , Wang Zhiyuan , Duan Wenguang , Fu Weiqi , Tong Shikun , Sun Baojiang
Published: November 2019

Hydrate formation and deposition usually exist during deep-water gas well testing, which easily cause plugging accident in the testing tubing if it was not found and handled in time. A method to estimate and manage hydrate plugging risk in real-time during deep-water gas well testing is developed in this work. This method mainly includes the following steps: predicting hydrate stability region, calculating hydrate behaviors, analyzing the effect of hydrate behaviors on the variation of wellhead pressure, monitoring the variation of wellhead pressure and estimating hydrate plugging risk in real-time, and managing hydrate plugging risk in real-time. As hydrates continue to form and deposit, the effective inner diameter of the tubing decreases, and the wellhead pressure also decreases accordingly. The risk of hydrate plugging can be estimated by monitoring the variation of wellhead pressure. When the wellhead pressure decreases to the critical value for safety at a given gas production rate, it is indicated that hydrate plugging is likely to occur. Under this condition, hydrate inhibitor is needed to inject into the tubing to reduce the severity of hydrate plugging, and real-time monitoring of wellhead pressure variation is also needed to guarantee the risk of hydrate plugging in the testing tube is within safe range. By using this method, the real-time estimation and management of hydrate plugging during the testing process can be achieved, which can provide basis for the safe and efficient testing of deep-water gas wells.
Drilling in the Digital Age: An Aproach to Optimizing ROP Using Machine Learning
Authors: Batruny Peter , Yahya Hanif , Kadir Norazan , Omar Amir , Zakaria Zahid , Batamale Saravanan , Jayah Noreffendy
Published: November 2019

Low rates of penetration (ROP) were experienced in an area with well-known lithology. The vast drilling experience and similarity of drilling conditions in the area, provided the operator with enough data to improve the well schedule and cost performance through the use of machine learning.

Machine learning, specifically artificial neural networks (ANN), is a statistical tool to find relations between multiple inputs. Details that would have been missed or considered outliers by a mathematical model can be accounted for and explained in the ANN model. The ANN was trained on thousands of real time data points recorded from selected wells in a specific depth interval. Typical drilling parameters such as weight on bit, rotary speed, bit hydraulics, lithological properties, and dogleg severity were the input parameters chosen in the model to generate ROP. Once the model was calibrated to historical data, it was used to find the best parameters to maximize ROP.

R squared factors were 0.729 and 0.675 for 12.25 in. and 17.5 in. sections repectively. This was achieved with an ANN structure of 2 hidden layers consisting of 5 nodes each. Sensitivity analysis identified bit hydraulics, weight on bit, and rotary speed as the major parameters impacting ROP. The ROP model was used to conduct a "virtual drill-off test" to identify drilling parameters that maximize ROP. ROP dependency on weight on bit and lithological analysis suggests bit design can be further improved. Bit hydraulics showed that higher flow rate was needed in sections with higher overbalance. Optimum drilling parameters were tested on four wells and resulted in more than 50% higher ROP compared to original field data.

In an industry increasingly dominated by big data, separating the clean data from the "noise" will be a vital topic. This paper aims to provide a blueprint for the use machine learning to optimize ROP in a manner that is simple and easily replicated.
Optimal Surface Cooling Solutions for Thermal EOR Projects
Authors: Sulaimani Husam , Sellappan Ganesamoorthy , Hamm Mark
Published: November 2019

Thermal Enhanced Oil Recovery (EOR), is considered the most applied EOR method, which contributes to around 66% of the global EOR. Steam Injection is normally employed on the reservoir to reduce the viscosity of heavy oil and enhancing its mobility, at high temperatures. One of the common issues arising with continuous steam injection, is reservoir heating, causing produced fluid temperature to increase, exceeding the temperature limitations of the downstream facilities. The objective of this study is to develop and provide an optimum surface cooling facility to minimize the impact of production and avoid the need for major modifications to the facility.

The methodology used involve; surface process simulation using UNISIM simulator, subsurface dynamic heat modelling using CMG Stars software, materials selection, economical and costing studies. The parameters used were; existing and future well counts, individual wells gross production rates, and maximum expected produced fluid temperatures. Different solutions have been considered such as water dilution, super grade materials, Mechanical Refrigeration, Wet Surface Air Coolers, Draft Air Coolers and Heat Recovery Exchangers. The selected options have been evaluated based on technical, economical, environmental and operability criterions.

Dilution with water and super graded material options were discarded, due to lack of external water supply, and significant life cycle cost respectively. All the Heat Exchanger options were also discarded due to the inability to meet cooling mediums specification, as well as the presence of economical and operational difficulties. The optimum selected technology is to provide Air Coolers at the individual Wellheads, although this solution is theoretically and economically convincing, there are some operational and maintenance challenges to overcome considering the remote locations of the steam injection wells. However, some parameters such as cost, simplified technology, maintainability, availability, will play a key role in demining the optimum technology.

Unlike most published studies, the outcome of this study has been validated with existing field data (operational learnings), as well as being the first of its kind to implement, benchmarking with other major oil and gas producers, also saving significant capital costs by 69%.
Applying a Foamed Cement Operation for Surface Casing in a Deepwater Well: Case Study, French Guiana
Authors: Ribeiro Danilo , Souza Leonardo , Paredes Jose Luis , Michon Patrick , Szakolczai Cyril
Published: November 2019

Lightweight or, alternatively, foamed cement slurries for surface casing operations are often necessary during special situations (i.e., low fracture gradients) for the required zone to be isolated. The foamed cement technique reduces the heat of hydration (HoH) of the slurries, reducing potential risk of shallow hydrate flow and losses because of its reduced hydrostatic pressure. This alternative for lightweight slurries has been used globally with successful results.

The foamed cement operation was designed and executed considering specific aspects and details, including a combination of factors, such as expected low fracture gradient, mechanical property requirements, logistic constraints in terms of the difficulty managing two types of cement (large tonnage of Blend and G cement vs. rig capacity and safety volume requirements), long sections to be cemented, and the uncertainty of the cement volume excess necessary to achieve return in the seabed. Because this was the first cement operation for the operator at this remote deepwater field, the planning phase required extensive discussions. Rig silo capacities and deck space on the rig were limited, which constrained the possibility of considering backup for all bulks, chemicals, and equipment.

Execution of the cement operation was as per the approved program without deviation. The cement volume returned at seabed indicated an openhole diameter with ±100% washout. A tracer additive (fluorescent dye) mixed with the spacer was successfully used to indicate fluid return at seabed (2120-m water depth). As part of the best practices to execute this operation, a liquid additive system was used to provide pump volume flexibility. Foamed cement laboratory tests were performed, considering field samples and the foaming agent (surfactant) were injected straight at the suction of the pump. As expected, the foamed cement operation is an extremely efficient and effective technique to achieve zonal isolation in a surface casing string of a deepwater well. Currently, this procedure is frequently used in fields globally. A case study of the first foamed cement application for surface casing in French Guiana is discussed.
A 40 Years Brown Field Rejuvenation
Authors: Hassan Siti Normaizan , Bt Latif Nurlizawati , Ashqar Ayham , Ishak Ahmad Zamzamie , Mustafa Azfar Hafizin , Roy Amit
Published: November 2019

This paper discusses a comprehensive study to address the uncertainties and troublesome major field development. The west Malaysia field has 7 platforms, and 110 wells. Production started in 1979. The highly complex, elongated anticline structure, possess over 330+ interpreted normal, reverse and wrench faults. It is deposited in Lower Coastal Plain within transgressive system tract.

Despite the strong and consistent reservoirs production, recovery Factor (RF) remained at 19% indicating potential remaining value.

The new look requirement were imposed as a result of disappointing drilling results mainly due to Key uncertainties in hydrocarbon redistribution, sand continuity and its quality, oil production across adjacent fault blocks.

Multicomponent seismic was acquired, to establish an updated reservoirs framework and assist in mapping hydrocarbon, water as well as lithology identification (sand/shale/coal).

Several wells were suspended based on the indicative study result. 85 new opportunities were identified, and tiered based on technical confidence and risk appetite. A roadmap consists of detailed development strategies spanning over 5 years and beyond associated with ~100MMstb reserves value that will bring the RF to 31% were proposed.

Main study outcomes resulted of reducing sand distribution uncertainty, reservoir extension was clarified and confirmed with the new seismic interpretation result. By passed oil were mapped.
Co-Development Aspects of Super Giant Reservoirs With Condensate-Rich Gas Cap
Authors: Ziablitckaia Yulia , Sharif Ahmed , Abdou Medhat
Published: November 2019

Conventional strategy for developing of giant oil reservoirs with a gas cap involves an optimal production from the oil column before the gas cap is blown down. This paper investigates technical aspects of co-development strategies where demand for the gas may entail earlier exploitation of the gas cap along with the existing oil column development.

Co-development of giant reservoirs with condensate-rich gas cap are particularly challenging due to the presence of significant condensate volumes. The basic strategy of the co-development plan involves producing from a gas cap first under full gas recycling so as to accelerate condensate recovery. This is followed by sales gas production by means of partial gas recycling in conjunction with water injection at gas-oil contact for pressure maintenance purposes. The injection of water at gas-oil contact is intended to provide a water barrier or fence that separates and / or minimize gas cap expansion toward oil. The degree at which sales gas is produced is under pressure maintenance scheme is thus linked to the level of the partial gas recycling and the efficiency of the barrier or fence water injection.

To explore the feasibility of this process, reservoir simulations of mechanistic models were first used to study the reservoir physics of water injection at gas-oil contact for the purpose creating water barrier and /or fence. This was followed by implementation of the co-development scheme using sector models that represent two giant carbonate gas cap reservoirs. The feasibility and merits of the co-development strategy were measured by performance metrics that include condensate recovery, sales gas production, minimum oil loss and fluid migration at gas-oil contact and overall water demand.

The results show that partial recycling along with barrier water injection may provide a mechanism for concurrent gas cap and oil column exploitation. A key factor that underlies the success of the co-development plan is the ability of the water injection at gas-oil contact to recover potential pressure drop in time as gas recycling ratio is reduced by forming effective barrier. This, in turn depends mainly on the reservoir geology and water injection volume and scheme. Moreover, reservoir characteristics that are favorable to the process are lower formation dip angle, smaller surface area at fluid contact and good injectivity of the reservoir rock.
The Automation of Steady-State Fractional Flow Upscaling in Stratified and Random Rock Type Structures
Authors: Ramsay Travis
Published: November 2019

In discrete upscaling methods, the saturation history of corefloods is often lost, while automated upscaling methods retain the saturation history of corefloods. A reservoir simulator is used to upscale imbibition relative permeability using discrete and automated methods. Both discrete and automated upscaling methods can be categorized according to a Peclet number ratio, which describes relative permeability upscaled in the capillary limit for stratified and random rock type assemblages. The upscaled results are then compared to both the rock type curves and to results from different cores to validate whether the effects of rock type volume fraction and distribution are preserved. The term random here refers to a carbonate sample relative to its stratified counterparts. In the cores with stratified geometry, a Peclet number ratio is used to ensure multiphase capillary limit flow and preserve adequate scaling. The ratio is determined from the Peclet number in adjoining rock types; a Peclet number ratio is computed from a pair of rock types (or pseudo-rock types if more than two rock types are present), since the geometric and associative relationships of rock types are ill-defined. The discrete method follows an isolated dual-rate injection, while the automated procedure is performed by sequential dual-rate injection.

The effects of rock type volume fraction and distribution are preserved while upscaling in the capillary limit for core assemblages possessing stratified and random configurations; this is true for both discrete and automated methods. Behavior in the stratified cores at the saturation endpoints is then used to further classify the behavior of the random assemblage. The primary conclusion is that automated relative permeability upscaling in a commercial reservoir simulator is a viable alternative to discrete upscaling methods, as it is both functionally efficient and maintains a saturation distribution and profile analogous to the standard coreflooding process. Secondarily, upscaled relative permeability is rock type dependent on the distribution and volume fraction of the differing rock types in the capillary limit. An analysis of curves generated in stratified geometries and randomly assembled rock types, such as carbonates, shows discernable differences and suggests care must be taken during upscaling from pore to core to ensure rock type volume fraction and distribution effects are not lost.
Integrated Engineered Solution for Realtime Through-Tubing Remedial Sand Control
Authors: Ramah Moorthy Kuhaneswaren , Mohd Zainudin Nik Mohd , Nor Nazri , Arief Tham Nabilla , Huang Pin Y , Ishak Eliza , Ismail Abdul Malek , Wijoseno Danny Aryo , Sorman Ignatius , Yong Nigel , Liu Hai , Nwafor Chidi , Ling Kong Teng , Wibisono Rahmat
Published: November 2019

Coiled tubing (CT) sand cleanout has been a normal practice for offshore wells, and repeated cleanout runs will have to be done over the years to sustain production. It has been observed that the production period of these offshore wells has shortened significantly after each cleanout due to sand particles loading up in the production tubing at a faster rate. This production trend is typical for wells with no downhole sand control in the original completion. Various aspects in terms of well design and reservoir conditions have significantly increased the complexity of sand cleanout. This, for example, includes the large 9 5/8-in. casing section with small dual upper completions of 2 7/8-in. production tubing, a high angle with a long horizontal section, and severely drawn-down reservoirs. There were also previous findings on the well where cement pebbles were found on the production choke at surface contributing to higher risk during intervention.

An integrated engineered solution was brought forward to successfully execute the CT sand cleanout job by capitalizing on both engineering and operational efficiencies. In terms of technical and engineering design, real-time fiber-optic downhole telemetry system, nitrified cleanout with a shear-thinning gel fluid that has superior suspension ability, and a milling tool for cement pebble cleanout were utilized. Operationally, an electrical submersible pumping (ESP) system capable of providing continuous supply of seawater and custom-built skidding beams for sand screen deployment purposes were also introduced for the first time for CT operations in southeast Asia that successfully improved operational efficiency and job safety.

A remedial sand control solution was also used to improve production longevity after sand cleanout, without doing any major pull-tubing workover or sidetrack drilling. Either through-tubing sand screens or a sand agglomeration treatment technique was carefully chosen and deployed to address the sand load-up issue in these wells. This paper discusses the operations, challenges, and the key success factors that have contributed to a well-engineered CT cleanout and deployment of sand screen and sand agglomeration treatment.
Acid Stimulation Evolution and Optimization for HPHT Deep Gas Formations
Authors: Moid Farrukh , Rodoplu Rasim Serdar , Nutaifi AbdulRahman
Published: November 2019

Acid stimulation and fracturing in multiple layers formation requires an integrated approach to design and execute an effective stimulation treatment. An extensive campaign of acid stimulation on carbonate formation to increase productivity index in a deep High Pressure High Temperature (HPHT) gas bearing carbonate formation is discussed here. A high degree variation in permeability across long interval, stress barriers between target zones, and completion limitations were main challenges to design an effective stimulation treatment.

The target was to achieve effective acid stimulation for multi-layers carbonate formation with different formation properties and stress barriers. Although all layers had similar initial pressures and gas compositions; but different properties. Comingled flow was planned from the formation, therefore effective stimulation for each layer was recommended to drain effectively and improve recovery.

To assess the best stimulation strategy in early stage of development, complete set of diagnostics conducted across all formations before and after the acid treatment coupled with geomechanical studies on actual core samples. Various stimulation techniques were implemented from Small Matrix Treatments (SMT) with Coiled Tubing, Matrix Acidizing Treatments (MAT), High Rate Matrix Acidizing (HRMA), and Acid Fracturing Treatment (AFT). Thorough study of results as part of learning process was conducted to optimize the important parameters that affect the stimulation efficiency such as perforation strategy, completion design, diverter selection, fracturing design and implementation. The importance of modeling in optimization process, comparison between different treatment types and fluid systems is discussed supported by actual data such as temperature logs, post-treatment flowback analysis, pressure transient analysis and production logging results.
Predicting LNG Loading Arms Structural Bearings Condition
Authors: Nistor Marius
Published: November 2019

The scope of this technical paper is to present existing methodology of predicting structural bearings condition of LNG Loading Arms in ADNOC LNG through a systematic monitoring system (LNG Loading Arms Verticality Check) included into maintenance periodic routines in order to maintain operational reliability, optimize plant availability.

Few years back, ADNOC LNG experienced abnormal structural bearings noise along with leaning issue of two LNG Loading Arms, culminating with one Loading Arm becoming immovable. Despite the fact that the structural bearings are designed for entire life span of Loading Arm, it was recommended by OEM to replace all three structural bearings (slew, luff and apex), activity which was performed with significant resources and cost impact.

A systematic monitoring approach to monitor the verticality of mobile arms was adopted into the ADNOC LNG Preventive Maintenance Program associated with LNG Loading Arms. The technical paper is presenting the methodology and best practices to trend and benchmark wear-and-tear process experienced in the LNG Loading Arms structural bearings. LNG Loading Arms - Verticality Check utilized a combination of GPS, conventional surveying and electronic techniques for the rapid acquisition coordination data required for the monitoring approach.

Several detailed verticality check surveys were conducted for four LNG Loading Arms by determining coordinates (plan and height) from a network of GPS observations connecting newly constructed reference control points as the basis of a 3D network. The monitoring procedure was designed to trend the existing targets coordinates (installed on the LNG Loading Arms - "bull-eyes") and compared with the As-New structural bearing condition and LNG Loading Arms operating behavior, keeping in account the verticality deviation causes attributed to several factors (Loading Arms positioning errors, structural bearing clearance, other mechanical structural distortion, etc.). Each of the Loading Arms were found to be out of verticality along the virtual critical axis, but still within the calculated acceptable limits.

Current maintenance practice on monitoring the Loading Arms verticality check is a powerful systematic tool for better assessment of structural bearings condition in ADNOC LNG - Das Island plant, methodology which can be implemented within other facilities using transfer arms.
The Impact of Dynamic Filtration on Formation Testing in Low Mobility Carbonate Formations. Case Study: Lower Cretaceous Carbonate Reservoir in the UAE
Authors: Kuliyev Myrat , Lyonga Molua Sammy , Cig Koksal , Sepehri Siavash
Published: November 2019

Formation pressure and sampling measurements in low mobility formations under dynamic filtration can lead to measurements influenced by continuous mud circulation. Generally, active mud circulation inhibits mud cake growth, promoting filtration and invasion of mud filtrate into the reservoir. The resulting invasion adds its own pressure to the actual formation pressure. This is more pronounced in low mobility formations where pressure or sampling measurements made with mud circulation show higher than expected reservoir pressures and/or extended clean up times as a result of dynamic filtration and invasion.

We focus on formation pressure acquisition and present data sets where pressure acquisition was done with active mud circulation. The data is then compared with measurements acquired in a pseudo-static and static mud column.

The measured near wellbore formation pressures acquired with active mud filtration are significantly higher (in some cases, > 400psi) compared to those obtained with a static mud column (assumed to be reading closer to the true formation pressure). The additional pressure is often referred to as supercharging, i.e., the excess pressure superimposed on the original formation pressure by the viscous flow of mud filtrate. The difference depends amongst other factors primarily on the formation mobility and surface pump flow rate during the pressure acquisition. For higher mobilities, there is generally little appreciable difference between active mud circulation and zero mud circulation. Secondary factors like pipe movement, pipe diameter, mud composition and reservoir wettability also influence the degree of the extra pressure measured.

Best practices for formation testing while drilling in low mobility carbonates are discussed. Lessons are drawn from experience where ignoring such best practices result in questionable data.
Application of Cryogenic Spill Control Techniques in Floating LNG
Authors: Mulè Giampiero , Luciano Valentina , Pastorello Antonino , Whymant Alan
Published: November 2019

Coral Sul FLNG is designed to produce, liquefy, store and transfer LNG and condensates directly at the offshore reservoir. Over 430 meters long, Coral Sul will be the first FLNG ever built to operate in ultra-deep waters, its wells are located 2000 meters below sea level. The vessel is currently under construction by Technip, JGC, Samsung Consortium (TJS) in South Korea for a joint venture led by Eni as operator and partners (ExxonMobil, ENH, GALP, KOGAS and CNPC).

The main safety challenges for the FLNG technology, relate to the management of cryogenic spills on board and the protection of people and assets in a very congested environment.

FLNG technology is introducing a set of new safety rules for the industry which are still under development by main international certification bodies. Today, the lack of industry standards regarding FLNG technology, and the congested nature of the installation, make the Risk Based Approach an essential step to validate the design and identify fit for purpose reduction measures.

Coral project carried out several actions for Cryogenic Risk Management with the aim to: ensure safety of all the Personnel on Boardminimize the potential for escalation and maintain asset integrity.

This Paper describes the Risk Based Approach followed for Coral FLNG project and describes some of the most important design safety measures implemented on board to manage cryogenic spills: Design of Drainage System and Overboard dischargeDesigned against the Risk of Rapid Phase TransitionActive Protection Methods: Water Curtains to protect hull sideImproved Coating Materials (combined effect Cryogenic Spill Protection + Passive Fire Protection)

Suitable design of drainage system is a key safety aspect for the design of the FLNG, since it is essential to minimize the vaporization which can create dangerous flammable gas clouds on board.

The solution proposed for Coral Sul FLNG is a combination of open gutters, sloped open channels and vertical pipes which allow the quick discharge overboard of accidental spills, minimizing the vaporization in congested areas. In proximity of overboard spillage points, water curtains are implemented to protect the hull side, and the effect of discharge is evaluated for rapid phase transition.

Steel decks and structures must be protected against fractures that can follow accidental cryogenic spillages and lead to structural failures which put at risk lives and assets. Specific coating materials have been developed for the protection of decks, piping and equipment to avoid the escalation of any incident. These coatings provide combined protection against embrittlement and fire. Application of coating is done used RBA approach.

Design of drainage system and coatings have been identified as technical novelties. A technology validation program has been put in place for Coral Project in order to assess the maturity of the new technologies.
Successful Management of Collision Risk in an Extended Reach Well
Authors: Naknaka Manchukarn , Prasertamporn Praisont , Ledroz Adrian , Naranasamy Jayaneethe , Ramasamy Kesavan
Published: November 2019

Mubadala Petroleum planned to drill a complex Extended Reach Well (ERD) from an existing platform. To reach the required geological targets, the preferred wellpath was required to pass within close proximity of an adjacent oil producer that had a resultant separation factor (SF) of 0.70. A SF of less than 1.0 presents a mathematical possibility of well collision due to overlapping Elipses of Uncertainties (EOU). As such there was the likelihood of the inability to drill the well with a consequencial impact to the Mubadala business plan. A novel solution was by implemented by utilizing High Inclination Drilling with Gyro (HIDWG) tool to safely manage and mitigate the risk of well collision.

The Jasmine field is a mature, complex oil field containing multiple stacked sandstone reservoirs, largely having individual oil and gas water contacts that have been on production since 2005. One of the major challenges is safely and economically accessing the remaining bypassed oil. Wellpath collision is an ever increasing risk as the ageing assets become more congested, which could lead to property damage and losses of production. Collision avoidance is gauged with a SF that takes into account the well depth, toolface, and the error model of the electronic survey tool.

A conventional Bottom hole Assembly (BHA) with Measurement While Drilling (MWD) tool was initially considered, however the proximity calcuations yielded a SF of 0.7, and the well could not be drilled according to the company's drilling standard. To manage the risk and safely drill the well, the survey error uncertainty needed improvement. Instead of a conventional MWD, a High Inclination Drilling with Gyro (HIDWG) tool was utilized to reduce the survey error uncertainty to yield higher precision drilling control at depth in excess of 10,000 feet and at an inclination higher than 70 degrees.

As a result of the BHA upgrade, the SF was instantly improved from 0.70 to 1.0, the collision risk was reduced to an acceptable level, and the well design was compliant with the drilling standard. Furthermore, the HIDWG was utilized for the first time in the Gulf of Thailand.

Mubadala Petroleum successfully executed the ERD well utilizing the HIDWG, in combination with an Advance Hybrid Rotary Steerable System (RSS). The HIDWG tool provided an all-inclusive real-time surveying solution that delivered highly accurate surveys and with the Advance Hybrid Rotary Steerable System (RSS)'s precise drilling control throughout the intervals of close proximity with other wells.

This paper explains how the HIDWG tool provided an inclusive surveying solution that could deliver both high accuracy surveys and precision drilling control throughout the zones of anti-collision concern of the ERD well. The chosen solution enabled the ERD well to be drilled to the required target successfully and allowed production to be established as planned.
Monitoring of Volatile Organic Compounds to Sustain Safe Laboratory Working Environment
Authors: Yonebayashi Hideharu , Sasaya Kazuyo , Watanabe Takumi , Inamura Takashi , Kobayashi Atsushi , Iwata Takao
Published: November 2019

As a part of laboratory Health, Safety and Environment (HSE) management system, the working environment control is applied to eliminate exposure hazards for workers. This control is a continuous effort in our laboratory as the working environment management system. Volatile organic compounds (VOC)s are ones of very common exposure hazardous factors in petroleum R&D laboratory. To better working environment control, the working environment measurement additionally to the chemical risk assessments is conducted at first to assess the concentration of VOCs in accordance with the guideline of domestic act. The measurement design is optimized on the basis of actual chemical use in the monitoring objective laboratories. The chemical records has been tracked in the chemical inventory management system. The measurement is conducted by two methods to assess both of average and the maximum VOC concentrations in the objective laboratory. Based on the measurement results, the objective laboratories are classified into three ranks. If necessary, counter actions will be taken: for instance, ventilation system improvement as building management, and consideration of substitute. Furthermore, the working record what types of chemical used and how long hours to handle them are linked to the health management system in which the workers who handle solvents must take a semi-annual special medical check. Further potential improvements were debated by adopting the process safety management in laboratory phase, and installing flexible exhaust system.

The working environment management is important for protecting employee's health. The system is not independent and linked to other HSE management systems. Therefore, a well-organized grand design is worthy as total management system which includes each management system for waste, inventory, procurement, building maintenance, and so on. Because this paper discussed a practical example of HSE management system from both of detailed and high level. The discussion should be useful for considering HSE in laboratory.
Success Story of Utilizing Real Time Drilling Data to Remotely Support Drilling Operations and Identifying the Areas of Drilling Performance Improvement
Authors: Mohamad Abdul Salam , Al Dhanhani Omar , Joshi Ashish , Hussein Ahmad , Alsawwafi Khadija , Clergier Alberic , Dubey Anurag , Pausin Wiliem , Al Fardan Firas , Jradat Amin
Published: November 2019

Upstream Oil & Gas industry has been continuously focusing on reducing the operating cost, while targeting higher operational efficiencies. To that extent we are seeing a continuous move towards remote operations with efficient utilization of available data to identify operational issues and provide benchmarks for improving drilling performance. The industry is putting significant efforts into using instrumentation and software to optimize operations in all domains for exploration and production (E&P) to move towards the Digital Oil field of the future.

With a similar vision, ADNOC Onshore have implemented Real Time Data Management project in partnership with Schlumberger for enabling remote real-time drilling operations and performance reporting across its entire active rig fleet. The objective is to provide a single platform to users for: Technological solution enabling real-time data transmission from all rigs to ADNOC Onshore Headquarters and enabling real-time visualizations of the drilling data.Engineering solution to transform real-time data into information to easily identify the areas of operational improvement allowing to implement specific measures to reduce ILT and NPT which can help in reducing costs and risk.

This project has also provided an automated Drill Well on Paper (DWOP) process where high frequency real-time data is utilized along with low frequency Daily Drilling report data to provide better insights for well planning and generate ideas for improving performance and reducing costs.