bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Analysis of Production Impairment by Condensate Banking in Gas Condensate Fields
Authors: Wilkins A. J. , Morrison G. R. 
Published: October 2016

Abstract
Producing gas-condensate reservoirs below the fluid's dew-point pressure will lead to an increased condensate saturation in the near wellbore region, which impacts the relative permeability to gas. This phenomenon is known as condensate banking and is a cause of productivity impairment. During a field's operational phase, failure to predict condensate banking behaviour accurately will cause problems with a well's ability to attain production targets.
This paper explores the effect of both absolute permeability and condensate gas ratio (CGR) in order to quantify production impairment. To achieve this, three sets of PVT data were characterised. The reservoirs Alpha, Bravo and Charlie have an ideal split (C4-/C5+) CGR of 174.1, 44.7 and 13.9 (stb/MMscf) respectively. For each set of PVT data the absolute permeability has been tested within the range 1 to 1000mD. Both porosity and the relative permeability model were adjusted in proportion to absolute permeability. The range of parameters selected provide coverage of most gas-condensate fields. The PVT data from these reservoirs has been tuned and simulated using a Peng-Robinson twenty-two (22) component dynamic compositional model. Primarily, a single well radial model was used, although implementation of a Cartesian model was also explored for full-field modelling. All models discussed represent an ideal reservoir, consisting of homogeneous properties throughout.
Under a steady-state dry gas production rate of 50MMscfpd productivity impairment reached a maximum of 15.4% assuming an absolute permeability of 1mD and an initial CGR of 174.1 stb/MMscf. This low value of 15.4% was assisted by the positive effect of Velocity Dependent Relative Permeability (VDRP) and condensate stripping within the near wellbore region. In contrast, for situations where VDRP does not apply such as low production rates or post shut-down production ramp-up operations, the effects of condensate banking were significant. That is, removing VDRP to simulate these conditions, under the same dry gas production rate of 50MMscfpd a productivity impairment of 93.2% was observed. This result suggests that the most detrimental effect of condensate banking is caused by unsteady-state production operations. It is intended that the findings of this study be applied to wells currently on production to screen for potential condensate banking in later well life.
E-Learning to Action Learning, a Successful Case Study of an Upstream Oil & Gas Company
Authors: Al-Daihani Eisa , Nandi Arun Kumar , Al-Awadhi Sherif , Matar Maqhim Bander , Razaa Syed Mohammad 
Published: October 2016

Abstract
There are many learning tools available to fill competency gaps of an employee. The common learning tools are classroom courses, workshops, internal on job Training, external on job training with international companies, NOCs and Service Companies, e learning and other learning activities like attending conferences, forums, symposiums etc. However, the most cost effective tool is E-learning. This helps to fill the technical knowledge gap of the participant with flexibility and conveniently. Most of the E-Learning topics include multimedia for better deliverability. It is the most popular learning tool among new generation because they are technology oriented.
The present paper focusses on a pilot project where an attempt has been made to strengthen the E-learning tool through Action learning. The pilot project needed involvement of Coaches and Discipline Experts (DEs) besides candidates selected as participants of E-learning. Accordingly, as a case study, 10 employees (batch of same job family) with same topic were chosen to participate in the pilot project. Few discipline experts and coaches were also involved related to the course content of the E-learning session. A half-day session was organized with online access of the E-learning topic to all participants and DEs and coaches. After going through the entire topic, a group discussion was held and followed by question answer (QA) session.
As E-learning is a kind of self-learning; the effectiveness of the learning tool was dependent on the seriousness of an individual employee. Conventional assignment of E-learning topic and its implementation was helpful in filling the competency gap in the order of 60 to 70% of the course contents or even lower. However, after making E-Learning in to Action Learning through pilot project, the competency gap filling has been achieved up to 100%.
The implementation of E-learning through Action Learning has developed an interest, value addition and fulfillment of competency gaps of individual employees. This will result in fast track development of technical competence and thus help to achieve the group's business needs and company's goal.
Well Abandonment Project and Recommendation for Applying Activity Based Cost/Earn Value Management
Authors: Prasetya Afriandi Eka , Herputra Shanni Ardhana 
Published: October 2016

Abstract
Review the Activity Based Costing (ABC) and Earned Value Management (EVM) fundamentals of being applied to the case study. Examine the constraints and its feasibilities in recommending the implementation of ABC combined with EVM to well abandonment projects.
Well abandonment project is one of phase in the oil well's life span that must be done after it is no longer producing and to protect environment. Instead of giving revenue, well abandonment projects are spending money. To fulfill its deliverables with cost-effectively and in timely manner, the project coverage requires good planning, scheduling, and control. This paper is an actual case study which documents the abandonment of 7 oil wells located in Indonesia. ABC assigns resource costs to a cost object based on activities performed for the cost object. EVM coordinates the work scope, schedule, and cost goals of a program or contract, and objectively measures progress toward these goals.
By applying the fundamentals of ABC and EVM, the abandonment project of 7 oil wells was completed in a total of 131 days, a slippage of 12% over the approved plan of 117 days and at a total cost of 1.078 million USD, versus the target cost of 1.074 million dollars.
This paper explores the step-by-step process that is used to create the Baseline Schedule, track the progress against the schedule and report to the appropriate stakeholders. The paper concludes by recommending ABC combined with EVM be applied to other well abandonment projects.
High-Value Data at Zero Cost: Pulse and Interference Testing in a Deepwater Gas Field Under LNG Plant Start-Up Constraints
Authors: Ly K.. , Das S.. , Pudin V.. , Kazanov D.. , Affinito R. J. 
Published: October 2016

Abstract
Commissioning and start-up (CSU) of an all-subsea development of offshore gas reserves feeding into an onshore liquefied natural gas (LNG) plant is complex and challenging – yet project success is driven by a timely and flawless LNG project start-up. To this end, development wells in the Jansz-Io gas field had to be flowed back to the onshore facility to prove up Gorgon LNG Train 1 capacity before the wells could be relied upon for uninterrupted gas supply to Train 1 start-up. Here, a carefully-considered well proving sequence can yield unique, once-in-a-lifetime and zero-cost subsurface data that improves reservoir characterisation and future decision quality. This paper describes:
Design aspects of the well proving sequence that enabled opportunistic pulse and interference tests to be conducted at no expense to Train 1 start-up: Optimality: balancing the well proving objectives of the various functional stakeholders (flow assurance, facilities, operations and subsurface) while honouring all CSU / operational constraints. Flexibility: recognising and planning for CSU uncertainties (subsea gathering system versus onshore plant readiness; onshore gas demand; and pigging schedule for liquids management). Contingencies: planning for sequence execution issues such as well unavailability and gauge failure(s). Execution – how the tests were executed and how the reservoir responded. Analysis and interpretation of pulse and interference test data, whereby: A simple, conceptual analytical model based on the line source solution was constructed and used to guide analyses in more detailed numerical models. A single-layer 2D numerical reservoir model with local grid refinement at the wells was constructed and used to infer inter-well average reservoir storativity (porosity-total compressibility-thickness product, ϕcth) and transmissivity (mobility-thickness product, kh/μ) and across-fault communication. Existing 3D models were calibrated to the pulse and interference testing data for improved reservoir performance predictions in support of future reservoir management decisions.
The Petrophysic Role of Low Resistivity Pay Zone of Talang Akar Formation, South Sumatera Basin, Indonesia
Authors: Holis Z. , Prayogi A. , Purwaman I. , Damayanti S. , Nugroho D. , Kamaluddin M. K. 
Published: October 2016

Abstract
The South Sumatra Basin is one of the most hydrocarbon prolific Indonesian Tertiary back-arc basins today. Identifying, evaluating, and testing Low Resistivity Pay Zone (LRPZ) in South Sumatera Basin, is a challenge for increasing hydrocarbon resources in term of exploration in Indonesia. The objective of this study was to formulate the petrophysical paramater reference of LRPZ of Talang Akar Formation in South Sumatera Basin, validated by well test data.
The methods used in this study included regional well correlation, petrophysical analysis, core and cutting description, petrography analysis, petrophysical cross plot and cut-off analysis, and well test data analysis. Regional well correlation and petrophysical analysis was conducted for 110 well data in all of sub basin in South Sumatera Basin, those are Jambi, Central Palembang, North Palembang, and South Palembang Sub Basin. Core, cutting description, and petrography analysis needed to observe Low Resistivity Pay mineralogy content. Result of petrophysical cross plot and cut-off parameter analysis would be validated by well test data to formulate the role of LRPZ.
Based on well data, LRPZ was controlled by stratigraphy on sequence boundary of SB-T4 till Maximum Flooding Surface of MFS-T5 in Jambi Sub Basin, and on Maximum Flooding Surface of MFS-T4 till sequence boundary of SB-T5 in South Palembang Sub Basin. Core and cutting description indicated presence of pyrite and glauconite mineral in LRPZ of Talang Akar. Furthermore, petrography analysis indicated presence of pyrite and siderite mineral. These mineral were responsible to increase conductivity on formation. Based on cross plot, it was observed that LRPZ of Talang Akar Formation contained dispersed-laminated shale. It indicated that presence of LRPZ in South Sumatera Basin was caused by presence of fine grained reservoir or superficial porosity. Cross plot two parameter, RPD (Relative Porosity Difference) and resistivity log cross plot, defined cut off parameter is 5 Ohmm for LRPZ of Talang Akar Akar. Based on well test data validation, the water saturation (Sw) cut off on LRPZ is 70%. The observation result concluded that Low Resistivity Pay Zone (LRPZ) of Talang Akar Formation, South Sumatera Basin, was characterized by low gamma ray value, presence of neutron-density log crossover, and presence of hydrocarbon evidence on total gas reading and oil show on cutting, but very low resistivity (&lt;5 Ohm.m).
This petrophysic role of Low Resistivity Pay Zone would be useful to help geoscientist to determine well test interval technically for successful hydrocarbon discovery in Low Resistivity Pay Zone of Talang Akar Formation, South Sumatera Basin, Indonesia.
Fast Track Well Planning in Borneo
Authors: Pathy Kuhanesapathy AL , Kumar Premila AP , Kaeng Geovani C. , Mansor Aznizan Bin , Sausan Sarah 
Published: October 2016

Abstract
This paper highlights the phenomenal achievement of a Malaysian operator's first fast track drilling operation in a deepwater well offshore Borneo. The collaborative well planning (CWP) method fundamental to the drilling success is discussed.
The discussed drilling environment is an overpressured deepwater area that has not only forced the earlier A1 and A2 to early total depth (TD) and caused abandonment of geological targets, but also contributes to numerous operational problems. Despite the challenges, operations on A3 ST-1 required significantly less operational time cost than budgeted. The difference between the previous two wells and A3 ST-1 was that, during the planning period, multidisciplinary concerns were addressed more carefully in real-time by employing CWP to unite geoscientists, drilling engineers, and other stakeholders using 3D integrated platform technology.
This CWP helped the operator meet objectives for A3 ST-1, a fast track well that required only two months of drilling time, rather than the typical 12 to 18 months. It resulted in one primary well location and six geological sidetrack scenarios being accomplished in only one day. Upon the end of the operation, Well A3 was drilled with one successful cased hole sidetrack to geological target objectives without significant operational problems. A significant portion of the success can be attributed to the proper accommodation of concerns and best practices of rig usage, engineering insights, tool usage, and geological conditions during the planning process through the common software platform that can seamlessly allow collaboration of both geoscience and engineering data. The process automation only requires key drilling parameters to construct well trajectories, which was also significant in terms of shortening the planning time.
This paper describes the first application of the CWP concept in offshore Borneo, which has become a trendsetter in terms of efficient and safe deepwater drilling planning and operations.
Production Optimization in Waterfloods with a New Approach of Inter-Well Connectivity Modeling
Authors: Zhai Xiang , Wen Tailai , Matringe Sebastien 
Published: October 2016

Abstract
We present a novel methodology to model inter-well connectivity in mature waterfloods and achieve an improved reservoir energy distribution and sweep pattern to maximize production performance by adjusting injection/production strategy on well control level. The method involves a reduced-physics based fast numerical tracer test on each well that yields inter-well connection strength or well allocation factors, and then a data-driven efficiency model on each inter-well connection calibrated automatically from the production/injection history of the reservoir. The latter one identifies the undesired connection suffered from water cycling or aquifer coning. A producer-injector/aquifer communication network is established which enables instantaneous forecast on reservoir response to various hypothetical well control strategies. An optimization algorithm is applied to improve the flux pattern by strengthening efficient connection and weakening inefficient connection. The objective of the optimization can be to maximize oil production or to minimize water cut. A set of physics constraints (lift limits, injection limits, liquid capacity, etc.) and economic constraints (e.g. oil target) can be enforced in the optimization process.
The methodology is tested based on a full-scaled history-matched simulation model of a real carbonate field. The field is a large waterflood with 200+ wells and 5 years history, and the current water cut is above 30% and rapidly increasing. The full field simulation model was regarded as the true reservoir in this study. The network model was trained up to a time point, and then used to optimize the waterflooding strategy for six months. Reservoir response to the optimized strategy was simulated on the full field model, as well as the historical strategy and do-nothing strategy. The results demonstrated that the optimized strategy maintained oil production and reduced water production by 50% without adding new well, while the historical operation satisfied the oil target by drilling tens of new wells and scarifying water-cut.
This new approach models the key physics in waterflooding with a network model, and uses the model to optimize well control strategy effectively. The model reduces the non-critical physics and incorporates data-driven techniques, therefore it is fast to build, calibrate and run. Compared to traditional simulation modeling, this approach can be used by production engineers to guide operations in a daily to weekly manner.
Subsea Separation – an Undervalued Tool for Increased Oil Recovery IOR
Authors: Hendricks R.. , McKenzie L. J. , Jahnsen O. F. , Storvik M.. , Hasan Z.. 
Published: October 2016

Abstract
Over the past 10 to 15 years subsea processing has been globally established as a market segment within the subsea development arena, and subsea separation has been a vital part of this development with Troll C, Tordis SSB, Pazflor and others. The track record of these installations have been outstanding, some of them with documented uptime of more than 99%. Still focus in the market seems to turn towards more ‘clean’ pumping or compression solutions at a time where the boosting technology options increases, while separation seems to be linked to more complexity and higher capex and are often not included as an option in evaluating a field.
Still, subsea separation has some distinguished qualities that cannot be matched by other IOR methods. The more obvious scenarios are linked to flow assurance issues such as hydrate or slugging conditions in a field, but in addition some fields with very low production pressure or very long transportation distance to shore. Equally important is the operators need for flexibility in the design to cover for uncertainty in the production over the life of field and to count for future unexpected situations. This could be for a greenfield, redevelopment of a brownfield, or in general uncertainties about future sand or water production. Subsea separation is a simple way of mitigating these uncertainties, while at the same time increasing the operational envelope of the overall system compared to a pump or compressor alone. The paper will present examples of how separation can hugely add value compared to boosting alone by using simple, robust technology, resulting in more predictability an increased Net Present Value (NPV) for the operator.
Monitoring Wellbore Fluid Displacement in the Perforation Interval Using Multiple Downhole Pressure and Temperature Gauges
Authors: Paterson Lincoln , Ennis-King Jonathan , Freifeld Barry 
Published: October 2016

Abstract
Permanent downhole gauges for measuring pressure and temperature are very useful for reservoir surveillance. Whereas most applications have used a single downhole gauge, here we discuss experience using multiple downhole gauges simultaneously in a single well. At the CO2CRC Otway site four permanent gauges were installed in the CRC-2 well in 2011 with these gauges bracketing the perforation interval. The gauges were used to monitor the injection at various stages of water, pure carbon dioxide, impure carbon dioxide and nitrogen. Observations from these gauges have allowed the position of the gas-water interface to be observed as it moved up and down through the perforation interval. This provides information on the effectiveness of the perforations and the fraction of reservoir zone being accessed. The changing densities of gas mixtures due to temperature and composition were also inferred. These observations assist the development of better wellbore models for use in reservoir simulation of near-wellbore fluid flow, replacing the often-used initial assumption that one single phase contacts the entire injection or production interval. The current installation in CRC-2 at Otway has eight gauges distributed over two completion intervals, one flowing and one isolated from the wellbore. This elaborate configuration allows observations of additional information including the vertical pressure diffusion between the reservoir intervals.
Comparison of Capillary Pressure-Saturation Models for Gas-Water Systems in Shale Gas Reservoirs
Authors: Ren Wenxi , Li Gensheng , Tian Shouceng , Sheng Mao , Yang Ruiyue , Wang Tianyu 
Published: October 2016

Abstract
For two phase flow simulation in shale gas reservoirs, such as carbon sequestration, drilling fluid filtration and fracturing fluid leak off, it is critical to know the relation of capillary pressure versus saturation (P-S relation). Many P-S models were proposed to characterize the P-S relation. The aim of our study is to evaluate the existing models for P-S relation of shale, including van Genuchten model, modified J-function, Li-Horne model, Kosugi model and Brooks-Corey model.
To meet this goal, first, we converted available mercury-injection capillary pressure data (A total of 13 sets of data from different shales) into gas-water data. Then, each model's parameters were estimated by the nonlinear fitting of experimental data. Finally, the root mean square errors (RMSE) and the correlation coefficients (R2) were employed to evaluate the quality of fitting.
The results show that: 1) for the five models, the mean RSME varies between 0.0087 and 0.1375; 2) van Genuchten model and Kosugi model give better fitting than others, while van Genuchten model and Kosugi model are not much different in terms of fitting precision, both of which are recommended for two phase (gas-water) flow simulation in shale gas reservoirs; 3) Brooks-Corey model exhibits largest RMSE values; 4) for Li-Horne model, pore fractal dimension obtained from fitting is out of the range from 2 to 3, which may be physically unreasonable. Furthermore, it should be note that Kosugi model is derived based on log-normal pore size distribution. Each parameter in Kosugi model has clear physical meaning. Therefore, when involves pore size distribution, Kosugi model is preferable than van Genuchten model.