bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful implementation of Through Tubing Technology (Sand Control and Gas Lift) in challenging offshore environment as an integrated development strategy for sustainable development of marginal fields: A Case Study
Authors: Sharma Anurag , Singh Alok Kumar , Anand Saurabh , Parasher Arunabh , Sharma Amit , Kale Sagar 
Published: May 2016

Abstract
Well AB-5 was drilled & completed in a marginal field in offshore West coast of India. Initially well produced only gas, till the oil bearing sands were perforated & it was being put on commingled oil & gas production. Through tubing sand control was installed in the well in view of continuous sand fill observed post perforation due to unconsolidated sand formation. Over the period of time, formation pressure depleted and the well eventually load up & died in absence of any mode of artificial lift on the unmanned platform. The Challenge was to unload & activate the well using gas lift in a commercially viable manner, avoiding expensive Barge based operation without having the said facility & provisions available.
Since no Gas Lift Mandrel was present in the upper completion, a Thru-tubing Gas lift technique using retrievable straddle packers with GLV in between & conveyed on slick line was being adopted. A temporary arrangement of nitrogen tanks, pumps & surface set up for subsequent well unloading was organized. Further, a 20 T modular crane was installed on the platform after a detailed platform structural load analysis for spotting the surface equipment. Detailed NODAL analysis was being carried out for modeling the required nitrogen rates and the well performance at different gas lift parameters. Post GLV installation, nitrogen was pumped thru the annulus via the GLV, installed against circulating SSD, into the tubing.
This Paper not only describes the Job design, technique implemented & challenges overcome during successfully activating a theoretically dead well to approx. 1000 BOPD production, thus establishing the viability of Through Tubing Sand Control (TTSC) & Thru-Tubing Gas Lift (TTGL) technologies but also delivers an integrated development strategy for sustainable development of marginal fields.
The same technology is now being implemented in other water loaded wells of the field having similar technical and logistical constraints.
Field Introduction:
LG gas field is the first commercial discovery in XY Block. Field is located about 10 - 15 km west of the Hazira (near Surat in Gujarat) coastline in the Gulf of Khambat. The field is about 38km2 in an area ranging in sea water depth of 10 to 25 metres due to the presence of bars and channels at the seabed. The area experiences some of the harshest sea conditions with 6 - 8 knots of underwater currents and tides up to 6 - 8 metres. The seabed channels and bars are continuously shifting. The seawater is extremely muddy with near zero visibility.
In-situ Residual Oil Saturation And Cluster Size Distribution In Sandstones After Surfactant Flooding Imaged With X-ray Micro-computed Tomography
Authors: Iglauer Stefan , Sarmadivaleh Mohammad , Geng Chong , Lebedev Maxim 
Published: May 2016

Abstract
We imaged a sandstone at connate water saturation, residual waterflood oil saturation, residual surfactant flood oil saturation and residual polymer flood oil saturation at high resolution in 3D with a micro-computed tomograph. We measured oil saturations, porosities, residual oil cluster size distributions and oil cluster surface areas on each image. We found that the waterflood and polymer flood reduced the oil saturations significantly (from 68.4% initial oil in place to 38.3% after waterflooding and 28.5% after polymer flooding). The surfactant flood was ineffective, which is probably due to the formulation we used and/or the fluid equilibration times we applied. The residual oil cluster size distributions and cluster surface area-volume relationships followed power-law relations, consistent with previous experimental measurements. We conclude that micro-computed tomography can enhance understanding of pore-scale fluid dynamics significantly.

Introduction
With a growing global population and simultaneously shrinking crude oil reserves (note that crude oil still is the most important energy resource (IEA 2010)) it is vital that advanced technologies are developed which can recover additional oil (so called unconventional oil). Such techniques are usually classified as enhanced oil recovery (EOR) methods, and they include gas injection (e.g. N2 or CO2, Iglauer et al. 2013, Blunt et al. 1993), surfactant injection (e.g. Xie et al. 2005, Iglauer et al. 2010, Al-Sulaimani et al. 2012) and polymer injection (e.g. Zaitoun et al. 2012, Iglauer et al. 2010, Seright et al. 2011, Zhang et al. 2012). Recovery of heavier oils can also be increased by steam injection or combustion drive (Lake 1990), i.e. through oil viscosity reduction.
We focus here on surfactant EOR (SEOR), which has been tested in a range of field operations (e.g. Ferrell et al. 1988, Reppert et al. 1990, Maerker and Gale 1992). Typically small surfactant concentrations are used (Iglauer et al. 2010) to minimize costs. One of the main problems with SEOR is, however, surfactant adsorption (= loss) to the rock surface (e.g. Gale and Sandvik 1973, Pursley and Graham 1975, Wu et al. 2010, Green and Willhite 1998).
Tectonics of the Mozambique Margin Through the Integration of Gravity and Magnetic Modelling: the Rovuma Basin Case Study.
Authors: Gilardi Matteo , Longoni Roberto , Spadini Giacomo 
Published: May 2016

Abstract
The Rovuma Basin is located along the eastern margin of northern Mozambique and southern Tanzania, forming one of a series of continental passive margin basins that stretch along the coast of East Africa. The basin covers onshore and offshore areas for approximately 64,000 Km2.
The correct definition of the geological evolution of an area is of primary importance for a proper assessment of its petroleum potential; in the present work an integrated approach, based on seismic interpretation, structural analysis and 2D Gravimetric/Magnetic modelling, has been applied on three different interpreted seismic sections to provide more predictive and reliable geological models.
The Gravimetric/Magnetic modelling has contributed to the definition of the Rovuma Basin architecture by testing two possible geological scenarios: one with a shallow top basement surface and another with a deep top basement surface, both interpreted on seismic data. Through the integrated potential methods study one of the above scenarios has been validated.
The results of the integrated workflow could be summarized as:–proper basement surface depth scenario definition;–description of the main structural lineament geometries;–basaltic bodies geometry and location definition;–characterization of continental, transitional and oceanic crusts and definition of a possible Continental Ocean Boundary (COB) location.
The mutual support between the structural studies and potential method teams has been the key to improve the geological knowledge in frontier exploration areas.

Introduction
The correct definition of the geological evolution of an area is of primary importance for a proper assessment of its petroleum potential. In the present work an integrated approach, based on seismic interpretation, structural analysis and 2D Gravimetric/Magnetic modelling, has been applied on three different interpreted seismic sections to provide more predictive and reliable geological models.
2D Gravimetric/Magnetic modelling are non-unique, many models may provide calculated gravity responses that will fit the observed profiles. However, with some geological control, sensible assumptions and knowledge of likely structural styles, the results can be constrained reasonably well.
By combining geological and geophysical interpretations on three differently oriented interpreted seismic sections, the tectonic evolution of the Rovuma Basin has been investigated (Fig.1). The Gravimetric/Magnetic modeling has contributed to the definition of the Rovuma Basin architecture by testing two possible geological scenarios: one with a shallow top basement surface and another with a deep top basement surface, both interpreted on seismic data as possible basement. Through the integrated potential methods study one of the above scenarios has been validated.
Solving The Conflicting Dips Problem In Complex Media By Considering All Possible Dips In Crs Method
Authors: Shahbazi Aamin , Ghosh Deva , Soleimani Mehrdad , Mann Juergen 
Published: May 2016

Abstract
In the existence of conflicting dips, where the seismic events are bent, faulted, or pulled up by the salt dome or anticlines or even intersect another structural event, some parts of the events may not be imaged well in stacked section and may produce uncertainty in the final migrated section for interpretation. A modified version of the CRS stack, the common diffraction surface (CDS) stack, is a method that could solve the problem of conflicting dips that may happen frequently in complex and semi-complex structures. This strategy has some advantages that improve the continuity of reflection events as well as diffractions in the presence of conflicting dip situations. To investigate whether it could solve the seismic imaging problem in such media, we processed the Sigsbee 2A synthetic data and a real seismic data set with the new method. Finally, the stacked result of Sigsbee 2A and the results of the poststack depth migration of the real data also proved that the continuity of the events is fully preserved and there are no gaps in the diffraction events, even where they intersect other events. This method could resolve some of the ambiguities of imaging in complex structures.

Introduction
Working in complex and semi-complex structures requires new processing's methods to solve the problems of imaging in those situations. In those geological conditions, some problems like as defining the boundary of salt diapers or mud volcanoes, defining the location of faults, folding systems and unconformities, identify the reflection events below that structures and the problem of conflicting dips, are difficult to handle. The newly introduced method of common reflection surface (CRS) stack (Hubral, 1999) and the later method that was a modification of CRS stack under the name of common diffraction surface (CDS) stack (Soleimani, et. al., 2009b) beside the technique of prestack depth migration (PSDM) could be used in such situations. To solve the problem of imaging in this situation, Sigsbee 2A synthetic data and a real seismic data set were selected for application of the CMP stack method, defining the problems in imaging and solve the problems by applying the CDS stack method to them. The seismic data was selected from a sedimentary basin in north east of Iran, Gorgan.
Using Wireline Formation Tester Pressure Survey to Validate and Fine-tune Model Building: A Case Study for a Multi-layered Mature Reservoir
Authors: Badusha S.  I. , Qamber A.  M. , Al-Rashdan S. , Safar A. , Mahato A. , De S. 
Published: May 2016

Abstract
Wireline Formation Tester surveys are routinely performed for pressure profiling in all new wells. These surveys are being extensively used to identify contacts, cross communication etc. The information is updated and integrated for a full field perspective so that depletion trends, communication across faults, and presence of sub-layers within the main sand lobes are identified, validated and mapped. This data set is acquired over time, against a well laid out strategy and against all the sands.
As a precursor for building a model in a multilayered mature oil field of Kuwait, the collected data were analyzed to draw interesting and operationally important conclusions. The study reinforced the sub-layering classification followed in the field on a broader scale; however in a few instances, marked anomalies were noted. The existing sand layering scheme was re-visited and corrections applied by adjusting the layer tops in those wells.
Multiple pressure points across adjacent sub-layers with close pressure regime were grouped and re-grouped and plots were generated. The layers followed the existing geological layering scheme; but in some instances, the plots indicated a different picture of the extent of these sub-layers. This type of validation of layering scheme of the static model gave important insights during upscaling for the dynamic model. Analyses of the plots were carried out in different segments for well clusters across faults. The plots uncovered important information about the nature of the faults. Conclusions drawn from these plots are planned to be used for supplementing Pressure Transient Analysis information during history match.
Experimental Simulation Of Hydrocarbon Expulsion
Authors: Schwark L. , Stockhausen M. , Galimberti R. , Elias R. 
Published: May 2016

Abstract
Laboratory studies simulating thermal maturation of source rocks to generate and expel oil/gas differ from natural conditions. Amounts and compositions of products deviate between experiments and those found in natural petroleum source, carrier and reservoir rocks. Experimental data used in numerical models simulating oil/gas generation/expulsion thus seem to require adaption, causing significant uncertainty in present petroleum systems analysis. We designed and tested a procedure to simulate laboratory generation and expulsion of hydrocarbons under conditions most similar to natural conditions.

Problem identification
The critical factors in combined petroleum generation and expulsion simulation studies are: the pore and kerogen network of a sediment must remain as closely as possible in its natural state, as destroyed pore-systems are unsuitable for interpretation due to artificial reaction sites and migration avenues created upon experiment;kerogen maturation must occur in the presence of water, as water acts as hydrogen donor for oil/gas formation and via hydrostatic pressure and associated flow stimulates migration of oil/gas; consequently, dry pyrolysis often used in petroleum generation experiments for kinetics calculation will not reflect near-natural oil/gas expulsion;pressure regimes applied upon experiment must mimic differentially the lithostatic and hydrostatic pressures, as lithostatic squeezing will cause collapse of clay mineral aggregates but opposes kerogen swelling in non-lithified rocks; consequently experiments under all-directional identical confining pressures are unsuitable to reflect oil/gas expulsion;the generated and then expelled oil/gas fluids must be allowed to migrate in the given pressure and permeability regime in order to avoid artificial secondary reactions, including condensation as well as cracking, hence rendering closed pyrolysis unsuitable for many petroleum expulsion studies.
Exceptional cases may include tight shales, where expulsion is hindered or burial of reservoirs associated with oil to gas cracking.
ESP Well Surveillance using Pattern Recognition Analysis, Oil Wells, Petroleum Development Oman
Authors: Awaid A. , Al-Muqbali H. , Al-Bimani A. , Yazeedi Z. , Al-Sukaity H. , Al-Harthy K. , Baillie Alastair 
Published: May 2016

Abstract
PDO is managing some 850 Electrical Submersible Pump (ESP) systems scattered across North & South fields, which is continue to grow in the next five years business plan. All ESP wells have real time down-hole sensors that measures intake and discharge pressures, intake and motor temperatures, vibration and current leakage. The oil producing fields are equipped with real time data transmission system where several data measurements; down hole (such as pump intake and discharge pressures and temperatures) and surface (such as volts, amps and frequency) are transmitted directly from the well site to the gathering stations, central control rooms and even to the engineers' desktop.
At present, PDO is deploying an integrated smart tool which will monitor, control, and optimize oil production and ESP performance to the various disciplines involved in oil production and optimization like Reservoir and Petroleum Engineers, Programmers, and Field Operation Teams. However, in order to enable these modern well surveillance systems, which often produce an overwhelming quantity of information but the data is often misleading or difficult to interpret, establishing the Pattern recognition of the trended real time data is key to make the software intelligent enough to be effective to the work places.
This paper will demonstrate how precise ESP, well and reservoir performance can be predicted from simple physical relationships and how these relate to the trends of surface and downhole data. A number of real field examples of data trends will be shown to illustrate how a proper understanding of these patterns will allow prompt ESP troubleshooting and ensure the correct actions are taken. The results are correlated with equipment pull and inspection reports to validate the diagnosis.
Pattern recognition trends and analysis will be presented for common problems such as hole in tubing, shut in at surface, ESP wear, blockage at pump intake, debris in pump, broken shaft, change in reservoir pressure, blockage at perforations, etc. A proper understanding of these trends will allow the correct settings of alarm and trips and assist in the implementation of semi-automated well surveillance and diagnostic system which being currently deployed in the Company. A pattern recognition analysis check sheet will be included in the paper to allow users to quickly interpret data trends and diagnose well, ESP and reservoir performance problems.
Remaining Oil Saturation Determination in Dukhan Arab C and Arab D Reservoirs
Authors: Wahlheim Thomas A. , Jamieson W. Hank , Schnacke Arthur , Dixon James R , Attia Tarak , Barrios Levin , Ab Majid Mohamed Naguib , Silva Herman , Trabelsi Ali , Omar Mohd 
Published: May 2016

Abstract
The Dukhan Field Arab C and Arab D Jurassic reservoirs have been developed via natural depletion followed by peripheral water injection of variable salinity waters. Additionally, the Arab D crestal development has been influenced by the expansion of the primary gas cap and subsequent gas cycling project.
Six wells were recently drilled, cored and logged in areas of the reservoir that had been partially swept by water with the objective to quantify the remaining oil saturation (ROS) at these locations. Data acquisition to determine the oil saturations consisted of coring and acquiring a comprehensive logging suite comprised of resistivity, induction, dipole sonic imager, sonic scanner, electric imager, nuclear-magnetic resonance, and dielectric. The coring utilized low-invasion methods, with deuterium oxide tracer, to assess the degree of invasion. The cores were analyzed for routine properties and by Dean Stark analysis for ROS. Core description was done at a thin section and macroscopic level. Wellbore salinity samples from separate flow units were obtained to characterize the water in the swept zone to assist in evaluation of the water saturation from the logs. Following collection of the data, analysis was performed to:Integrate the core and log saturation data to develop most likely estimates of ROS.Examine the impact of throughput using reservoir simulation models.Assess remaining oil saturation by reservoir, zone, and rock type.Assess the uncertainty and establish ranking criteria in ROS measurements.
ROS from high-quality deep resistivity logs using true formation water salinity data provided the most likely measure of ROS at reservoir conditions. The integrated analysis resulted in a consistent set of ROS measurements grouped by zones and rock types. This dataset can be used for additional studies identifying future opportunities for improved recovery from the reservoirs.

Introduction
The Dukhan Field Arab C and Arab D Jurassic reservoirs have been developed via natural depletion followed by peripheral water injection of variable salinity waters which also vary from the reservoir's aquifer salinity. Additionally, the Arab D crestal development has been influenced by the expansion of the primary gas cap and subsequent gas cycling project.
The Remaining Oil Saturation (ROS) study focused on evaluating remaining oil saturation data from six cored wells in the Dukhan Field that were logged with comprehensive logging suites.
The scope of the study included:Integration of core and log oil saturation data to develop most likely estimates of ROS.Examination of the throughput impact using reservoir simulation models.Assessment of ROS by reservoir, zone, and rock type.Assessment of the uncertainty and establishment of ranking criteria in ROS measurements.
Reservoir Rock Typing of Upper Shu
Authors: Al-Tooqi Sabah , Al-Habsi Naima , Al-Shukaili Mohammed , Ehrenberg Stephen N. 
Published: May 2016

Abstract
Core samples from 10 wells in Lower Cretaceous limestones of the Upper Shu'aiba Formation were characterized by conventional core analyses, petrography, bulk chemical analyses, and mercury injection capillary pressure data to define reservoir rock types (RRT) for input to reservoir modeling. Initial grouping by lithofacies allows linkage of rock types to a 3D geological model, but results in RRT with high degrees of overlap in petrophysical properties. When diagenesis is included, however, in the form of porosity cut-offs added to the lithofacies criteria, RRT can be defined having both 3D geological significance and distinct ranges of pore-throat size distribution.
The use of total porosity as a rock typing criterion is based on the interpretation that porosity is controlled on reservoir scale by depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms have low clay and thus highest porosity. Although most of the pore space is microporosity, higher total porosity corresponds with higher proportions of macropores and probably also with greater frequency of open fractures, resulting in better permeability. High-porosity samples also have several systematic positive differences in MICP characteristics from lower-porosity samples of the same lithofacies.
Because both lithofacies and porosity are related to the sedimentological and stratigraphic organization of the Upper Shu'aiba clinoforms, the RRT defined by these criteria can potentially be implemented in a reservoir model for assigning particular ranges of petrophysical properties to distinct portions of each clinoform. By this procedure, seven RRT have been defined in the present selection of samples.