bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Down Hole Tool and Approach To Release Differentially Stuck Pipe
Authors: Machocki Krzysztof Karol , Aljohar Abdulwahab , Zhan David , Abegunde Ayodeji 
Published: December 2021

Abstract
A new down hole system and method to use for releasing stuck pipes is presented. New system design, features and limits are compared to commonly used techniques for releasing stuck pipe showing benefits of the new system when dealing with differential stuck pipe incidents.
The new down hole system is capable to deliver much greater forces when compared to jars and other down hole accelerators near the stuck point. This system can generate over 40G`s lateral forces continuously down the hole acting on the stuck pipe area. The system can be integrated into a Bottom Hole Assembly (BHA) and activated once drill string become stuck or run as a part of the remediate assembly. Different aspects of two types of assemblies are described outlining the benefits and drawbacks.
The author will discuss in details the background and rationale to the new technology, including a review of differential sticking challenges and functionality of this new system.
The new system was compared to the most commonly used techniques for releasing differentially stuck pipe. Previously not releasable stuck pipe forces of over 1,000,000 lb. can now be overcome with the presented new approach to generate down hole forces near the stuck place. Flexibility in system integration and deployment allows for further optimization in BHA design and cost affective fishing operations in dedicated hole sections. This new approach can be implemented to release the most challenging stuck pipe mechanisms in drilling to minimize NPT and cost associated with stuck pipe, remedial operations and sidetracks. Similar approach can be utilized to release differentially stuck pipes, tubing and completions.
The novelty of this stuck pipe release system is the entire down hole system and operations of the overall system using new approach to generate large shocks down the hole. Additional novelty is related to flexibility during integration and deployment of this system. Similar to current shock tools, this system can be placed in BHA, fishing type assemblies and also pumped down inside of the stuck drill string to save time and cost.
Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs
Authors: Zhou Nancy Chun , Lu Meng , Liu Fuchen , Li Wenhong , Li Jianshen , Vaughan Steven , Trine Eric , Li Zhitao , Dean Matt , Britton Chris 
Published: December 2021

AbstractBased on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding.Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions.Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs.In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.
Formation Heterogeneity Effect on Steam Injection and Propagation
Authors: Batarseh Sameeh , Assiri Wisam , SanRoman Alerigi Damian , Khaldi Bander 
Published: December 2021

Abstract
The objective of this work is to evaluate and understand steam injection in heterogonous formation utilizing a state-of-the-art experimental apparatus. Heat transfer and efficiency for steam injection are evaluated in heterogeneous formation and compared with homogenous formation. The information obtained from the apparatus provided the key in designing effective steam injection for optimized recovery in heterogeneous formations.
This paper presents several successful experimental works and proposes solutions to overcome the challenges produced from heavy oil reservoirs. The technology utilizes advanced thermal apparatus to improve heat penetration depth into the formation and efficiency of the thermal heating. Steam is the most used technology due to its high latent heat capacity, cost and maturity. Steam injection should be carefully planned to ensure the injectivity to the target. Heterogeneity adds to the complexity of the operation, as the steam will propagate in different orientations. This study provides the key element to understand steam propagation to maximize the recovery efficiency. The experiments were carried out using heavy oil apparatus, which is designed to accurately simulate reservoir conditions. It measures one meter in length by one meter in width by one and a half meter in height. It has 65 thermocouples, 24 acoustic transducers, 9 vertical wellbores, 9 horizontal wellbores; these data are used for modeling and simulation. The apparatus can use sand or blocks.
Thermal technology is very effective to mobilize heavy and viscous oil; steam injection has been successfully and widely deployed due to its reasonable cost, maturity, and efficient thermal transfer to reservoir fluids. Understanding the formation is vital to ensure successful steam-based stimulation, especially in heterogonous reservoirs. To this end, an apparatus was designed to evaluate steam injection in heterogonous formations. This is one-of-a kind studies that evaluates heterogeneity effect at a large scale and provides detailed analysis. First, steam is injected in homogenous formation to establish a baseline of heat propagation in formation. Second, the apparatus is filled in layers resembling a heterogonous formation, and steam is injected at same conditions (i.e., wellbore depth and injection rate and pressure). The device collected a real-time temperature map using 65 thermocouples. 3D graph and animations are plotted to visualize and evaluate the pattern and trend of steam propagation in both homogenous and heterogeneous formations.
The apparatus is uniquely deigned to evaluate different scenarios that simulate the field and wellbores more accurately. Due to its volume (one cubic meter), the device is the largest apparatus in literature, and flexibility, the device enables the replication of a heterogeneous formation. The amount of data and information gathered, make the apparatus unique and provide key elements to drive successful steam injection operations.
The Optimization of Infill Well Fracturing Using an Integrated Numerical Simulation Method of Fracturing and Production Processes
Authors: Wei Shiming , Jin Yan , Liu Xing , Xia Yang 
Published: December 2021

Abstract
New wells are continuously drilled to improve the recovery of shale gas reservoirs. Production processes of parent wells will induce stress changes in the reservoir and then affect infill wells’ fracturing design. In this paper, we employed an integrated numerical method to simulate the hydraulic fracturing and production processes with single one method, thus the fracturing scheme of the infill well can be optimized. The integrated numerical method is based on the finite element method (FEM), which is named as the discontinuous discrete fracture method (DDFM). The DDFM can be used with conventional finite element mesh, which is perfectly compatible with the discrete fracture model (DFM). The fully coupled solution of DDFM is validated by two problems, including Mandel problem's analytical solution and the numerical solutions of the single fracture propagation. When predict the shale gas production, a new diffusion equation is modified to describe the shale gas flow, and the simulation results showed a good agreement with the field data. At last, this paper takes an infill well construction in a shale gas reservoir in south China as an example. The hydraulic fractures of parent wells are interpreted from micro-seismic data and described with DFM to reduce the computational cost. Then the infill well's hydraulic fractures are described using DDFM. After simulating the production process of two parent wells, we get the current formation pressure and stress state. Aims at obtaining the maximum profit of the whole well region, by comparing the gas production of different fracturing schemes, we can choose the optimal fracturing scheme of the infill well.
Addressing Fouling by Qualifying Chemical Additives Using Novel Technologies
Authors: Farrell Andrew Robert , Frigo Dario Marcello , Graham Gordon Michael , Stalker Robert , Diestre Redondo Ernesto Ivan , Lorenzo María de la O Masa 
Published: December 2021

Abstract
Fouling of heat exchangers and production of stable emulsions in desalting units can present significant challenges in refinery operations. Often these difficulties occur due to the concurrent processing of two or more crude oils that are incompatible under process conditions. This paper describes a significant development in laboratory techniques for studying these issues and evaluating mitigation strategies.
Asphaltenes compatibility was evaluated for oil mixtures that may be co-processed in the refinery using a deposition flow rig, and the results were compared with those obtained with more conventional tests: blending stability analysis by light scattering and various screening methods. The flow rig mimics the process conditions (elevated pressure, high temperature, flow-induced shear) and identifies whether deposition or precipitation will occur. The former can cause fouling of heat exchangers whereas the latter produces solids that can stabilize emulsions in the desalter.
By varying the proportions of oils that were co-injected into the deposition flow rig, the range within which mixtures were unstable was found. By flowing through a capillary (to mimic a heat exchanger) and in-line filter, it was possible to identify whether precipitation of suspended flocs or fouling of the heat exchanger itself was the likely issue for each mixture.
Emulsion-stability tests were conducted using a pressurized rig with an ersatz separator to mimic the desalting unit; results were compared with those obtained in conventional, ambient-pressure bottle tests. Oil(s) and refinery wash water were injected, mixed under representative shear, and allowed to separate within the typical residence time of the desalter. Chemical additives were tested to identify those that were effective at controlling any observed problems.
Results obtained in either flow rig (using representative pressure, temperature, and shear) did not always match those obtained using conventional methods. Asphaltenes fouling occurred under conditions where it was not predicted by screening tests that were conducted at conditions not representative of the process and did not occur under conditions where it was predicted. Differences were also observed between the emulsion stability observed in bottle versus rig tests, though these should be viewed as complementary techniques.
This paper presents new laboratory techniques for the prediction and prevention of refinery fouling and emulsion stability. They mimic conditions in the facilities much better than those typically used to date.
Asphaltene Mitigation in Giant Carbonate Abu Dhabi Fields: A Techno-Economic Comparison Between Continuous Injection and Formation Squeeze
Authors: Grutters Mark , Punnapala Sameer , Abdallah Dalia Salem , Cristea Zaharia , El Nagger Hossam El Din Mohamed , Anbumani Sivashankar , Sennad Rabah , Bakri Hasan Jamil 
Published: December 2021

Abstract
Asphaltene deposition is a serious and re-occurring flow assurance problem in several of the ADNOC onshore oilfields. Fluids are intrinsically unstable with respect to asphaltene precipitation, and operating conditions are such that severe deposition occurs in the wellbore. Wells in ADNOC are generally not equipped with downhole chemical injection lines for continuous inhibition, and protection of the wells require frequent shut-in and intervention by wireline and coiled tubing to inspect and clean up.
Since some of the mature fields are under EOR recovery strategies, like miscible hydrocarbon WAG and CO2 flood, which exacerbates the asphaltene precipitation and deposition problems, a more robust mitigation strategy is required. In this paper the results of two different mitigation strategies will be discussed; continuous injection of asphaltene inhibitor via a capillary line in the tubular and asphaltene inhibitor formation squeeze. Three asphaltene inhibitors from different suppliers were pre-qualified and selected for field trial. Each inhibitor was selected for a formation squeeze in both one horizontal and one vertical well, and one of the inhibitors was applied via thru-tubing capillary string.
The field trials showed that continuous injection in remote wells with no real-time surveillance options (e.g. gauges, flow meters) is technically challenging. The continuous injection trial via the capillary string was stopped due to technical challenges. From the six formation squeezes four were confirmed to be effective. Three out of fours squeezes significantly extended the production cycle, from approximately 1.4 to 6 times the normal uninhibited flow period. The most successful squeezes were in the vertical wells. The results of the trial were used to model the economic benefit of formation squeeze, compared to a ‘do-nothing’ approach where the wells are subject to shut-in and cleanup once the production rates drop below a threshold value. The model clearly indicates that the squeezes applied in ADNOC Onshore are only cost-effective if it extends the normal flow period by approximately three times. However, a net gain can be achieved already if the formation squeeze extends the flow cycle by 15 to 20%, due to reduction of shut-in days required for intervention. Therefore, the results in this paper illustrate that an asphaltene inhibitor formation squeeze can be an attractive mitigation strategy, both technically and economically.
Field Data and Laboratory Study to Investigate Water and Gas Injectivity and Cyclic Hysteresis in Miscible WAG Injection in Carbonate Reservoir
Authors: Masalmeh Shehadeh , Al-Keebali Aaesha , Igogo Arit 
Published: December 2021

Abstract
The objective of this paper is to investigate the water and gas injectivity in water alternating gas (WAG) projects using laboratory and field scale data. It has been reported in the literature that both gas and water mobility has been significantly reduced in three-phase flow compared to two-phase flow. This behaviour has been attributed to a cycle dependent hysteresis effect which reduced both gas and water mobility in the different injection cycles.
To address the gas and water injectivity and the cycle dependent hysteresis concept, the results of a detailed experimental program in addition to field injectivity data will be presented. The experimental program included three-phase experiments performed under reservoir conditions using live crude oil and carbonate reservoir core material. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir conditions and CO2 was used as miscible injectant. The field injectivity data is obtained from two CO2 WAG pilots in a carbonate reservoir.
The main conclusions of the study are: 1- Gas injectivity in the presence of mobile water is much lower than that in the absence of water, 2- Water injectivity in experiments starting with water cycle is better than that in experiments starting with gas cycle when compared at the same water saturation, 3- Cyclic hysteresis in gas relative permeability was observed when comparing the first and second gas cycle, however, no further hysteresis was observed in the subsequent gas injection cycles, 4- Cyclic hysteresis in water relative permeability was not observed, the injectivity was either the same or higher in the subsequent cycles. 5- The gas injectivity at similar gas saturation for experiments starting with gas is better than that for experiments starting with water, 6- Gas and water injectivity field data from ongoing CO2 WAG projects in carbonate reservoirs showed no cyclic hysteresis, the injectivity either the same or improved in the subsequent cycles, 7- The CO2 injectivity was lower than expected, in the same order as water injectivity, which could be due to injecting CO2 in high water saturation zone and 8) The low CO2 injectivity could have a positive impact on sweep efficiency and potential improvement of oil recovery.
This paper presents the results of a well-designed experimental program and field data from two CO2 WAG pilots to systematically investigate water and gas injectivity in miscible WAG projects in carbonate reservoirs. The paper provides a rich and rarely available set of experimental and field data that can help improve and optimize gas and WAG injection projects in carbonate reservoirs. Detailed analysis of the field gas and water injectivity data will be presented and discussed in-light of the laboratory experimental data.
Comparison of Psychological Distress, Life Satisfaction and Workplace Bullying Between Site and Office Workers in Oil and Gas Industry
Authors: Kusumawati Diah , Erwandi Dadan , Lestari Fatma , Kadir Abdul 
Published: December 2021

Abstract
In recent years, various industries become increasingly aware of the importance of mental health. Mental health is closely related to the management of psychosocial hazards in the workplace. The oil and gas industry is considered to be one of the laggards in the management of workers’ psychosocial hazards and mental health even though mental health is considered to affect workers’ health and operational safety. Workplace bullying is a phenomenon that can give adverse effects to individual workers and the organization. For workers, bullying can interfere with physical health, psychological stress, and satisfaction with life and work. This paper discusses prevalence of workplace bullying, psychological stress, and satisfaction with life of workers in the upstream oil and gas industry. The phenomenon experienced by workers on Sites is compared with the experience of the office workers in this paper, with no significant differences found between the incidence of bullying and satisfaction with life between the two populations. On the other hand, there is a significant difference in the psychological stress and chronic diseases reported by the respondents. Site workers experience higher psychological stress and more reported chronic health disorders than the office workers.
Pelican Lake: Learning From the Largest Polymer Flood Expansion in a Heavy Oil Field
Authors: Eric Delamaide 
Published: December 2021

Abstract
Polymer has been injected continuously since 2005-06 in the Pelican Lake field in Canada, starting with a pilot rapidly followed by an expansion. At some point, 900 horizontal wells were injecting 300,000 bbl/d of polymer solution and oil production related to polymer injection reached 65,000 bopd. As a result, the Pelican Lake polymer flood is the largest polymer flood in heavy oil in the world and the largest polymer flood using horizontal wells.
Although some papers have already been devoted to the initial polymer flood pilots, very little has been published on the expansion of the polymer flood and this is what this paper will focus on.
The paper will describe the various phases of the polymer flood expansion and their respective performances as well as discuss the specific challenges in the field including strong variations in oil viscosity (from 800 to over 10,000 cp), how irregular legacy well patterns were dealt with, and how primary, secondary and tertiary polymer injection compare. It will also show the performances of polymer injection in combination with multi-lateral wells and touch upon the surface issues including the facilities.
The availability of field and production data (which are public in Canada) combined with the variability in the field properties provide us with a wealth of data to better understand the performances of polymer flooding in heavy oil. This case study will benefit engineers and companies that are interested in polymer flood, in particular in heavy oil. The paper will be a significant addition to the literature where few large scale chemical EOR expansions are described.