bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study on the Matching Relationship between PPG Size and Reservoir Heterogeneity
Authors: Wu Dejun , Zhou Kang , An Zhibin , Hou Jian 
Published: December 2018

Abstract
Preformed Particle Gels are successfully used for profile control in heterogeneous reservoirs. However, it is still unclear how to select proper PPG size for a given heterogeneous reservoir. In order to obtain the best profile control performance, it is necessary to study the matching relationship between the PPG mesh and the permeability ratio.
In this paper, the heterogeneous parallel-dual-sandpack experimental setup is established, including the injection system, measurement systems for temperature and pressure. During the experimental processes of water injection, PPG injection and subsequent water injection, the fractional flow of the two sandpacks with high and low permeability are recorded respectively. Then, a quantitative characterization parameter of the profile improvement ability is defined by dividing the change of fractional flow of the low permeable sandpack before and after PPG injection by that of low permeable sandpack before PPG injection.
The experimental results show that different PPG meshes will achieve different profile control performance for the heterogeneous sandpack with the determined permeability ratio. The PPG with excessive large size may block the low permeable area, decrease its fractional flow and thus cause more severe flow heterogeneity. The PPG with excessive small size can not well block the high permeability area and they can migrate out during subsequent water injection resulting in the increase of fractional flow in high permeable area again. The matching relationship analysis show that the matched PPG mesh increases as the permeability ratio of the heterogeneous sandpack increases. In detail, the matched PPG sizes for the permeability ratio of 2, 4, and 6 are 120-150 mesh, 100-120 mesh and 60-80 mesh, respectively.
The paper studied the matching relationship between PPG size and permeability heterogeneity, which was beneficial for selecting the proper PPG size for different heterogeneous reservoirs in more future applications.
Spatial Distribution of Clay Minerals in the Neogene Sediments of North Kuwait and its Impact on Thermal Production
Authors: Mishra Prasanta Kumar , Ahmad Khalid , Al Khandari Jassim 
Published: December 2018

Abstract
Clay minerals are commonly observed in the Neogene succession of North Kuwait, both in the two viscous oil rich sandstone reservoirs (S1, S2) and intervening shale layers. SEM and XRD analysis of the core samples explain that Smectite is the dominant and Palygorskite, Illite and Kaolinite as minor clay mineral constituents. The paper describes the vertical and lateral distribution of these minerals in different sedimentary facies from bottom to top and the impact of steam on them.
The bottom and second channel-dominated sand and intervening shale (S2B sand, S2 Shale, S2A sand) layers show variation in total average clay content, as well as the swelling clay (smectite, illite-smectite) and fibrous palygorskite, with a low content in the north and center (2-4.6%), a moderate content in the east (6.7-7.3%) and a high content in the south (11.2-14.4%).
The Middle shale layer (MShale), is recognized as a flooding surface, observed at base of muddy interdistributory bay/lagoonal or floodplain deposits, sharply overlaying the channel-filled sandstones. Smectite –Illite is the dominant clay constituent.
The first channel-dominated sand and intervening shale (S1B sand and S1 Shale) layers contain predominantly smectite, illite-smectite and palygorskite content. The northern, southwestern and southeastern parts of the field, with more argillaceous channels and floodplain facies associations, have a high average total clay content (9.6-20%). The central part of the field, which is predominantly contains clean channel sand bodies, has a lower, average total clay content (4.9-12.6%).
The topmost sand (S1A sand) layer contains higher proportion of muddier channels and interdistributary bay facies, in the northern part and has high (&gt;7%) total clay content, but generally &lt;2% swelling clays and palygorskite. The central part of the field, with clean channel sands, has relatively low (&lt;7%) total clay content, with 0.8-3.2% swelling clays and palygorskite. The southern part of the field, with argillaceous channels, has a relatively high (&gt;7%) total clay content, with 2.2-6.3% swelling clays and palygorskite.
The sealing Cap Shale (bound by maximum flooding surface at the base and an erosive surface at the top) comprises of marine and restricted marine shales capping the underlying S1A sandstones. The clay mineral comprises of illite-smectite, kaolinite and chlorite, with no palygorskite content,
As this viscous oil is planned to be produced by thermal applications, Clay stabilization experiments were conducted to ascertain the permeability reduction in the reservoir due to swelling of clay minerals and changes after exposure to steam. The steam flood experiments are conducted at 32, 65 and 232°C on actual core plugs and the conversion of Illite-smectite to smectite was observed, reducing the permeability. Chemical stabilizers were suggested for controlling these damaging effects at higher temperature.
Waterflood Study of High Viscosity Saturated Reservoir with Multiwell Retrospective Testing and Cross-Well Pressure Pulse-Code Testing
Authors: Aslanyan Artur , Kovalenko Igor , Ilyasov Ilnur , Gulyaev Danila , Buyanov Anton , Musaleev Kharis 
Published: December 2018

Abstract
A waterflood study has been performed on a high viscosity saturated oil deposit with bottom water aquifer and complex geometry driven by regional tectonic stress and numerous shale breaks. The commercial production is on-going for the last 2 years with medium length (1,000 m) horizontal wells and start facing formation pressure decline.
The foremost challenge was to check if injection pressure is transmitted through the oil pay without leaking into the bottom water aquifer. The next question was whether the full net pay is engaged in pressure support under water injection. The last question was to check on permeability anisotropy.
The transmissibility between wells have been assessed with multi-well retrospective testing (MRT) of permanent downhole gauges (PDG) historical data records which are a part of standard ESP telemetry. The fluid mobility and hydrodynamic average thickness between water injector and oil producers have been estimated with cross-well pulse-code pressure pulsations (PCT) based on pre-designed rate variation sequence [1 – 8]. The pulse-code sequence was designed in full-field 3D dynamic model to ensure capturing response in two contrast scenarios: with pressure propagating via aquifer and via oil pay, which have a high degree (30:1) of fluid mobility contrast. The data processing and interpretation was performed in PolyGon™ software [18] using the pulse-code decomposition for PCT tests and multi-well deconvolution for MRT tests.
The cross-well mobility in injector-producer pairs from PCT was indicating that pressure was fairly propagating via oil pay. The effective thickness of PCT-scanned area turned to be in-line with net oil column thickness from 3D geological model.
The MRT-scanned area was showing much lower transmissibility than 3D geological model prediction which was interpreted as the most part of the oil pay in this area has intermittent connectivity due to severe shale breaks development. This gives strong indication on searching the way to commingle production from isolated reservoir elements in this area [8 – 14].
The areal analysis of permeability in PCT-scanned and MRT-scanned areas has indication for 1:2 permeability anisotropy transversal to the regional stress direction which should be reconfirmed by a dedicated study.
Integrated Petrophysical Evaluation of Tayarat Formation for Water Disposal Purpose
Authors: Taqi Fatma , Ahmed Khalid , Saika Pabitra , Tyagi Aditya , Freeman Michael , Ren Zubiao , Zhang Ian , Muhammad Diri , Warrlich Georg , Al-Rabah Abdullah 
Published: December 2018

Abstract
A heavy oil field in Northern part of Kuwait has developed which requires appropriate disposal of produced formation water. Some important questions for water disposal well planning include: Where to inject?Where to inject?What is the maximum operation pressure (MOP)?How far away the disposal wells should be spaced?How much water can be inject in each well?
Integrated subsurface evaluation performed to address above questions. Seismic data provide a good overview lof the structuration and imporatant insight where sweet spots for injection may be found. Wireline logs and core information are used to derive petrophysical properties, characterize fracture, and gather geomechanical information. Injectivity tests established the injection rate and confirmed the estimated minimum horizontal stress. Analogue water injection data from nearby fields are used to provide information on the dynamic behavior of the reservoir, to reduce uncertainties owing to the limited injection rate data available.
The integrated analysis of the relevant, available subsurface data reveals that the Tayarat formation has significant variations in lithologies, mineralogies, and mechanical properties. Important information such as the receiving zone thickness, fracture orientation, injection rate, and storage capacity have been derived. Based on this information, we have made important recomemndations on disposal well spacing and maximum operational operating pressure (MOP).
Petrofacies Classification Method for Enhanced Reservoir Characterization in a Complex Highly Heterogeneous Shallow Unconventional Reservoir in Northern Kuwait : A Case Study
Authors: Choudhary Pradeep , Freeman Mike , Al-Boloushi Ahmed , Benham Philip , Sakia Pabitra , Tyagi Aditya , Ahmad Khalid , Jha Madan , Zhang Ian , Warlich Georg , Al-Rabah Abdullah 
Published: December 2018

Abstract

Objectives/Scope
The shallow depth unconventional reservoir in Northern Kuwait is essentially a monoclinal structure. Sediments have undergone significant shallow depth diagenesis, which resulted in selective oil/water accumulation, controlled mainly by lithological variations. Thus, the reservoir can be classified as stratigraphic-dominant trap. A correlation approach required addressing these variations, which can also be well understood by non-geologist, and the scheme should be appropriate for selection of perforation intervals.

Methods, Procedures, Process
Reservoir sands are in the form of multi-stacked distributary/fluvial channels. Subsequent to sediment deposition, moderate to intense diagenesis took place. The diagenesis resulted in formation of cemented baffles under low reservoir pressure (250psi) regime. For demarcation of bed boundaries, mapping and modelling purpose the reservoir sand, shale, baffles, gas, water, water above oil, this petrofacies classification method is proposed. The method is well capable of defining the various bed boundaries with fluid/gas content in it with confidence. The method developed after extensive core, core data and log calibration and study. More than one thousand wells correlated.

Results, Observations, Conclusions
The classification method is simple, yet robust to characterise reservoir vs. non-reservoir variations and oil/gas vs. water quite effectively. Cementation activities typically noticed on top/bottom of the units but many times in between the reservoir sand also. We are able to correlate cemented layers across the area. The cementation also gives rise to water perched above oil phenomenon due to relatively higher capillary pressure in the zone. Oil is migrated post-cementation and occupied reachable pore spaces. Oil also has undergone significant biodegradation because of favourable temperature and restricted nutrient supply. As a result, thin layers of thermal/biodegraded gas also formed locally. The method allows for surface related categorisation representing clean sand, cemented sand, shale, gas/oil/trapped water zones.

Novel/Additive Information
This unconventional reservoir is being developed with thermal application. Thickness of baffles, barrier, gas, water zones are critical in selection of perforation interval for steam application. This classification method is part of perforation selection for first phase of development and modelling purpose, and it was applied to hundreds of wells, many of them are undergoing production operations successfully.
Fluid Contact Identification for a Heavy Oil Shaly Sand Reservoir with a Biodegraded Oil Column
Authors: Battashi Fathiya , Khattak Ali , Svec Robert 
Published: December 2018

Abstract
This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts.

Methods, Procedures, Process
A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells.
The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes.

Results, Observations, Conclusions
Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach.

Novel/Additive Information
The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.
Production Optimisation of Heavy Oil Wells Using Autonomous Inflow Control Devices
Authors: Moradi Mojtaba , Konopczynski Michael , Mohd Ismail Ismarullizam , Oguche Iko 
Published: December 2018

Abstract
The uneven distribution of the production influx from the reservoir into the wellbore has been identified as the main issue in the management of production in heavy oil wells. This occurs due to a drastic difference between the mobility of oil and water i.e. water flows faster than oil in these reservoirs. This can be exacerbated by reservoir heterogeneities resulting in very high water production rate requiring large water treatment facilities which may be limited in offshore developments, resulting in reduced oil production.
Advanced well completions utilizing Inflow Control Devices (ICDs) and Autonomous Inflow Control Devices (AICDs) have proven to be robust solutions for these problems. Both devices help to enhance the performance of heavy oil wells by delaying the water production, however, AICDs are more capable to reduce the water production and increase oil production even after water breakthrough.
This paper examines the heavy oil/water production control by ICDs and AICDs and discusses the flow loop test data (single and multiphase flow) to describe the performance of devices for various fluids under downhole conditions. Using an example model, the reasons for the superiority of AICD over ICDs is investigated under different scenarios. An optimisation workflow was used to optimise the well completion design i.e. the size and number of devices plus packer placements and numbers.
The results of several field applications of AICDs, from retrofitting the existing completions of the wells with very high water cuts (e.g. 98%) to brand new wells in heavy oil fields, will be discussed. AICD completion as a proactive-reactive device was found to be the most efficient completion at controlling the water production from high productive zones or the fractures, compared to the wells equipped with ICDs and other conventional completions while increasing oil production.
This paper provides insights about inflow control device applications in heavy oil wells and provides a comprehensive guideline on the selection of appropriate completions for the wells in these challenging reservoirs.
Integrated Approach for Evaluation of Free Gas Distribution Assists in Improved Well Management Practices in a Northern Kuwait Heavy Oil Field
Authors: Saikia Pabitra , Al-Rashdan Saad , Taqi Fatma , Al-Dohaiem Khalid , Al-Rabah Abdullah , Tyagi Aditya , Choudhary Pradeep , Ahmad Khalid , Kharghoria Arun , Malik Satinder , Zhang Ian , Cheers Mike 
Published: December 2018

Abstract
Free gas along with heavy oil production affects the progressive cavity pump (PCP) performance. This necessitates the strategy to perforate away from the free gas zone. To be able to do this, it requires an integrated approach to evaluate and map the spread of the free gas accumulation in the field. The paper shall present how this resulted in improved well performance with less free gas interference.
The methodology included the understanding of the production data, sub-surface geology and petrophysics; reservoir heterogeneity and free gas presence from wireline logs, core data and isotope analysis of gas collected during mud-logging and creation of maps and cross-sections showing both vertical and aerial spread of free gas accumulation. This was then integrated with existing production and well management practices, along with numerical simulation results. Such in-depth analysis helps to bring significant changes in well completion strategy and is a vital contribution to the WRFM strategy.
Unlike in conventional fields where depth is more and buoyancy pressures are large, gas can easily displace oil to accumulate in structural highs, in shallow heavy oil fields, free gas accumulation is a result of combination of structural and stratigraphic entrapment process. Vertical migration and lateral migration of gas is likely restricted by non-reservoir facies. As a result a consistent gas-oil contact (GOC) may not be present across large distances. Gas oil contact separates heavy oil by possible structural spill point and lithological boundary, dipping from south to north. Structurally higher areas are prone to localized gas accumulation. The completion stand-off from the gas base has a direct correlation with gas production. So the well management and production practice is to increase the stand-off from gas base to top perforations in future wells and to perform gas shut-off job in current wells to avoid free gas production.
The novelty of the current approach is that it will proactively help in completion strategy to reduce future free gas production, subsequent loss in natural reservoir energy and maintain the oil production target.
Workflows to Assist in Managing a Heavy Oil Field in the Middle Magdalena Basin, Colombia
Authors: Franco Francy , Useche Marcos , Vargas Leonel 
Published: December 2018

Abstract
Heavy oil production poses multiple challenges on oil companies such as intricate operations (complexity), high operational costs (efficiency control), and solutions for high viscosity and low API fluids (specific technology). This paper describes the technical workflows implemented in a heavy oil field located in the Middle Magdalena Valley basin in Colombia to assist in the complexity of an operation where cyclic steam injection is applied.
The complexity of producing heavy oil is due to its high viscosity at repository conditions, which limits the mobility of the fluid and the draining effect to a relative small area around the wellbore, thus it is required an infrastructure that involves many wells, flowlines, manifolds, and facilities to produce this type of crude oil. To support the surveillance and the technical decision-making processes in an operation with more than 300 wells, effective workflows were designed and implemented with the aims to eliminate mistaken decisions, optimize resources, and contribute to cost optimization.
The algorithms, foundation of these workflows, are presented with the analysis of different elements taken into consideration during the technical design process, such as well intervention program, field infrastructure, daily reports, and current well parameters. Additionally, four specific targets are discussed: Heat injection surveillance, which follows program plan vs current execution, including the calculation of heat values from operational conditions (pressure, steam quality, mass rate, and running time); Well test schedule, which organizes the wells test plan in a hierarchy considering flowline connections, well services plan, and priority well list (time since last test, wells with abnormal behavior); Dinalog plan, which is the foundation for artificial lift control; Steam injection scheme, which creates a suggested ranking of wells requiring steam stimulation based on current conditions (Wcut, WHT, production rate), time since last stimulation, and steam/oil ratio.
The developed workflows are applicable in both heavy oil fields, and light oil fields with a large number of wells, and they can be a valuable foundation for digital oil fields providing support for technical management and contributing to resolve the challenges of a vast operation.