bluuebunny/crossref_metadata_2025 huggingface dataset:
Khursaniyah Gas Plant Experience with Foaming During Startup of Karan Non-Associated Gas
Authors: Al-Qahtani Mohammed Hussain , Garland Paul
Published: May 2016

Methyl di-ethanolamine (MDEA) is one of the most popular solvents for gas treating with several advantages over other amines, especially its ability to remove H2S and slip CO2 from sour gas. MDEA is like other types of amine that can experience major foaming upset, especially in high pressure sweetening units. All amines are subject to foaming in industrial applications given certain conditions and circumstances. This paper describes the investigations that Saudi Aramco pursued to eliminate early foaming incidents during the commissioning stage. The paper emphasizes the need for rigorous process evaluation and the application of fundamental principles in plant trouble-shooting. With a joint effort between Khursaniyah Gas Plant Engineering and the MDEA specialist (INEOS), the root causes of foaming were identified and corrected without any capital investment.

Karan Nonassociated (NA) Sour Gas is a CO2 rich stream. Formulated MDEA (GasSpec SS-3) was selected for Sweetening in Karan Gas treating facilities to enhance the H2S/CO2 ratio in acid gas and to meet the required Sales Gas specification prior to sending it to the Saudi Master Gas System (MGS). The Karan nonassociated sour gas field was discovered by Saudi Aramco in 2006. This newly developed offshore field is located 120 kilometers northwest of Jubail Industrial City in the Eastern Region of Saudi Arabia. Produced sour gas is coblended at a tie-in offshore platform through five 20" subsea flow lines. From the tie-in offshore platform, the gas is being sent via a 38" subsea pipeline to the onshore gas treatment facilities in Khursaniyah Gas Plant (KGP), where new gas processing facilities were constructed. Karan facilities consist of three gas treatment processing trains, each designed to process 620 MMSCFD of NA sour gas, producing sales gas and acid gas.
Fully Retrievable ESP: A New Artificial Lift Concept
Authors: Spagnolo S. , Pilone S. , Corti L. , Liantonio G. , Rizza G. , Tita G.E. , Kitsoukou D.N.
Published: May 2016

The "Fully Retrievable" ESP System is a new technology, which permits the rigless deployment and retrieve of conventional Electrical Submersible Pump (ESP): a wire-line, coil-tubing or rod should perform these actions.

This paper shows the eni experiences in this application and the approach used for the completion design according with the company policy highlighting the benefits and the criticalities faced.

Two Fully Retrievable ESP were installed by eni in the following fields:Alaska - OP18-08 - Nikaitchuq Field - onshore arctic environmentCongo - FOKM 101 - Foukanda field - offshore.

Each of them involved different issues and will be discussed in detail in the following sections.

This paper goes all the way through the well definition, completion philosophy and ESP system selection exploring constraints and limitation of this equipment.

An economical comparison was performed and the conclusion is that the retrievable ESP should be used in all of those fields where the workover cost is high and the deferred production is important due to rig unavailability.

It will be presented that the main benefits of this technology include:Simple ESP retrieving with smaller environmental impactCapability to run temporary systems to clean up or test the wellFine tuning of the ESP based on production data.

The benefits of the technology were tested using an internal eni tools for risk analysis based on Monte Carlo simulation: the results are discussed in the last part of the article and highlighted the above expressed consideration and main criticalities.
3D OBC Seismic Survey Productivity Enhancement with Satisfying Geophysical Requirements
Authors: Nakayama Shotaro , Belaid Kamal
Published: May 2016

Ocean Bottom Cable (OBC) seismic survey has several technical advantages over conventional towed-streamer technique as it enables the acquisition of wide azimuth and high fold datasets having long offsets and less spatial discontinuities. However, its usage is still limited because of requirement of relatively large operational efforts which likely results in more survey cost and duration. Consequently, optimization of OBC seismic survey productivity is essential to narrow the business gap with towed-streamer acquisition and enhance widespread applicability of OBC techniques.

Due to the decoupled aspect of the source and receiver lines, OBC survey can inherently form numerous survey designs. Our study is conducted with the aim to find efficient OBC seismic survey designs that still satisfy established geophysical objectives among infinite selections.

We introduce survey designing criteria on the basis of sampling of OVTs (Offset Vector Tile) which allows us to achieve desired offset and azimuth distributions in final imaging.

Productivity analysis is then performed based on current equipment availability enabling a variety of survey designs and geometries which were not feasible previously. We also adapt several geometry options including two dual source-vessel operations:Distanced Separated Simultaneous Shooting (DS3); andDual Source-Vessel Flip-Flop Shooting (DSVFFS).

Applicability of dual source-vessel operations to OBC survey has not been well described unlike marine towed-streamer and land cases. Thus, we analyse the impact of dual source-vessel operations on OBC survey efficiency. Additionally, we discuss technical challenges resulting from the relationship between OBC survey designs and the resultant interference noise wave fields not generally associated with other acquisition techniques.

Introduction

In spite of technical benefits of OBC surveys, time and cost are often regarded as the determining factor for the type of acquisition employed. In general and where applicable, the conventional towed-streamer survey is still the preferred business option. Therefore, further improvement of survey efficiency is important to narrow the business gap with towed-streamer acquisition and enhance widespread applicability of OBC techniques.
Quantitative Formation Evaluation in High Angle and Horizontal Wells - A Step Change in Reservoir Characterization
Authors: Zhou JinJuan , Guo Pingjun , Mendoza Alberto , Passey Quinn , Wertanen Scott , Gaillot Philippe
Published: May 2016

Advanced directional drilling technology has made it possible to drill extended reach wells with long horizontal displacements, resulting in optimally placed wellbores within reservoirs and more economical hydrocarbon production. Logging-while-drilling (LWD) technologies provide new opportunities to improve reservoir characterization and geologic models however, the complicated wellbore and formation geometries in highly deviated wells impose difficulties for quantitative interpretation of well logs using conventional petrophysical analysis methods. LWD log interpretation in high-angle and horizontal wells is often limited to geosteering in well placement applications and qualitative reservoir description.

We developed a state-of-the-art formation evaluation toolkit for quantitative interpretation of well logs in high-angle and horizontal (HA/HZ) wells. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 1) 3D and 2D displays for well path, wellbore images and field logs to quality control the data; 2) comprehensive image and log analysis to build a 3D geometrical earth model; 3) depth coherence analysis to effectively correct the recorded wellbore images of various logging tool sensors with different depths of investigation; 4) 3D joint inversion to accurately model and interpret gamma-ray, neutron, density and resistivity logs in order to build a common petrophysical earth model; and 5) populating the common earth model with bedding geometries and rock- and fluid-property distributions.

The toolkit has been successfully applied to a field example to illustrate its applications in quantitative reservoir characterization of net-to-gross (N/G), porosity (???), and water saturation (Sw). Incorporating more accurate descriptions of bedding dips and azimuths from HA/HZ wells within the earth model results in improved geologic models for reservoir simulation. Sensitivity analysis in the workflow defines the uncertainties in wellbore image analysis and wellbore directional surveys.

Additional uplift in reservoir characterization includes quantifying lateral variations and improving reservoir facies classifications, along with delineating potential calcite zones and quantifying stratigraphic bedding and orientation. The results include bed thickness distributions and guidance to appropriate petrophysical cutoff values.
Well Accessibility Considerations in Well Completion Designs for Long-Reach and Deviated Offshore Wells
Authors: M. Jeffry Suzanna Juyanty , Shivananthan Dinesh Mohan , Roh Cheol Hwan
Published: May 2016

AA is a new gas field located offshore Sarawak currently under field development planning phase. The elongated field structure consists of multi-stack reservoirs that are located up to 15,000 ft tvdss. Two options for developing the shallow Phase 1 wells (down to H800) have been assessed; completing at either one or two wellhead platforms. To decide between the two options, the team needed to be confident about the ability to safely intervene these wells in future, which triggered detailed accessibility analyses for all wells considering various intervention methods.

Four main intervention methods assessed were slickline, braided line, electric line (E-line) and coiled tubing (CT). This paper provides the details of well accessibility analyses conducted during development planning stage. Sensitivities on the types of intervention activities, bottom-hole assemblies and friction factors were also studied. The findings from the study has significantly changed the well completion designs of the long reach deviated wells justifying use of smart wells. This systematic well accessibility approach was applied for the first time in PCSB to replace the traditional rule of thumb of simple 60 degree deviation used as a cut-off for well accessibility.

Field Background

AA Field is located offshore Sarawak within Baram Delta province. It is one of the deepest resources that are currently being developed in this area. The 6-km elongated field structure has multi-stack reservoirs, with the targeted reservoirs located some 10,000 - 15,000 ft tvdss (Figure 1).

The large pressure differential and different water encroachment in each reservoir increase the level of complexity in developing these resources since zonal isolation is required. Well creaming exercise found that 5 development wells are sufficient to drain the reserves of Phase 1 shallow reservoirs down to H800 (Figure 2).
Factors That Affect Gas-Condensate Relative Permeability
Authors: Kalla Subhash , Leonardi Sergio A. , Berry Daniel W. , Poore Larry D. , Sahoo Hemant , Kudva Ryan A. , Braun Edward M.
Published: May 2016

When the pressure in a gas condensate reservoir falls below the dew point, liquid condensate can accumulate in the pore space of the rock. This can reduce well deliverability and potentially affect the compositions of the produced fluids. Forecasting these effects requires relative permeability data for gas-condensate flow in the rock in the presence of immobile water saturation. In this study, relative permeability measurements have been conducted on reservoir rock at a variety of conditions. The goal has been to determine the sensitivity to interfacial tension (which varies with pressure) and fluid type (reservoir fluids, pure hydrocarbons, and water). The results show a significant sensitivity to fluid type, as well as an interfacial tension sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that is applicable to a specific reservoir, we conclude that laboratory measurements should be conducted at reservoir conditions with actual reservoir fluids.

The measurements reported here used a state-of-the-art relative permeability apparatus of in-house design. The apparatus uses elevated temperature and pressure, precision pumps, and a sight glass with automated interface tracking. Closed-loop recirculation avoids the need for large quantities of reservoir fluids and ensures that the gas and liquid are in compositional equilibrium.

Introduction

Gas condensate fields are valuable resources under high natural gas prices due to expanding gas markets. They are also valuable under low gas price markets because of the produced liquids. Gas condensate reservoir development is similar to developing dry gas reservoirs with two significant differences: condensate flow in the reservoir near the wellbore and significant liquid production over the life of the reservoir. These factors influence the number of wells and the size of the surface facilities and thus importantly the project economics. Significant liquid accumulation in the pore space around the wellbore, where larger pressure drop and gas flux are encountered, affects the gas flow due to two-phase flow. High gas flux can also lead to inertial non-Darcy effects and, along with multiphase flow effects, decreases the well deliverability. The flow behavior of gas condensate reservoirs leads to increasing liquid saturation (an imbibition process) around the wellbore. This is the reverse of typical gas-oil drainage processes such as gas cap expansion and gas flooding, in which the liquid saturation decreases. Reliable prediction of gas deliverability or liquid recovery over the life of a reservoir needs reliable information on flow behavior of both gas and condensate phases through the reservoir rock.
Collaborative APC Project Management
Authors: Singh Pawandeep
Published: May 2016

EXTENDED ABSTRACT

BACKGROUND

LNG Industry is in next era of optimizing and maintaining huge LNG capacities, where QATARGAS is contributing 42 MMTPA out of QATAR'S Visionary delivery of 77 MPTA LNG. Mega trains also brings together range of complex technologies and a challenge to automate and cruise control by these technologies with emphasis on reduction in emissions, better asset utilizations, energy efficient operations and controlled product specifications.

QATARGAS operates its world class facilities with state of art optimisation tools implemented on On-Shore facilities starting with Inlet reception unit, Condensate Stripper, Fractionation Units, Liquefaction Units, Acid Gas Treating Units, Scrub Column, Acid gas enrichment units and Sulphur recovery units.

QATARGAS operates its 7 LNG trains with 62 such large APC controllers and overall asset wide linear plant wide optimizer to negotiate and control various constraints within different units with an objective to maximize revenue with minimum energy index operating with the defined operating /optimisation envelop of operating assets.

DESCRIPTION

This paper clearly highlight the ways and methods of implementing world class APC applications, best practices in LNG Industry, skills sets required for successful project implementation, problem solving methodology adopted, tools assessment and evaluation methodology, New Collaborative Vendor Management, Training and Operations, Software standardization, measures of benefit and Futuristic Performance Analysis /Audits and development of Performance Systems.

Methodology Adopted

A detailed stepwise methodology was adopted for Project Management. Key milestones identified are as follows:-Step 1 : Functional Engineering DesignStep 2 : Offsite Testing on Dynamic Simulation platformStep 3 : Finalise Control Structure and implementation StrategyStep 4 : Real plant detailed control strategy designingStep 5 : Pretesting and Process Modeling at SiteStep 6 : Plant Test Data AnalysisStep 7 : Review Control Structure Real plant v/s simulated platformStep 8 : Implement and commission final control structure at siteStep 9 : Analyse and review the benefits of implementationStep 10 : Establish Performance KPI's
Study of Damage Evaluation of Hydraulic Fracturing to Reservoirs
Authors: Du Linlin , Chen Shouyu , Song Bo , Xiu Shuzhi
Published: May 2016

Classic hydraulic fracturing analysis is based on tensile strength of rock, failure criteria of fracture mechanics or Mohr-Coulomb criteria. The existing hydraulic fracturing theories consider little of permeability of fracture reservoir and effective fracturing range, which is exactly the purpose of fracturing. On the other hand, when evaluating effect of massive hydraulic fracturing (MHF), there may be lots of fracture initiation points and cracks due to large range of MHF, which brings huge challenges to numerical calculation of hydraulic fracturing.

MHF will have an effect on a large range of reservoir and accompany in-line micro-earthquakes, which indicate that lots of hydraulic fractures of different scales and directions are generated. Therefore, there will be difficulties to analyze cracking and propagating and estimate geometrical parameters by tensile criteria or fracture criteria. Even if the classic method is feasible, processing of element grid after rock failures will be a problem.

Aguilera (1995) considered shear failure criteria as failure criteria of rocks and proposes fracturing theory of divergent or branched cracks, and that explains the generation of in-line micro-earthquakes in hydraulic fracturing. But the present analysis is just a qualitative method but not quantitative method.

In fact, the basic goal of hydraulic fracturing is enhancing permeability of reservoirs as large as possible rather than producing one or two fractures. Analysis of fracturing effects is analyzing the influence of effective fracturing range on reservoir permeability. While the existing hydraulic fracturing theories just consider propagations and fracture initiations of one or two cracks but little of the quantitative estimation for effective fracturing range.

Hence it is necessary to find a better mechanical method to make up deficiencies of the existing fracturing analysis and overcome the difficulties of processing element grid after rock failures.

This study introduces continuum damage mechanics (Gurson damage model) to hydraulic fracturing, analyzes theories and techniques of hydraulic fracturing of porous reservoirs in terms of continuum damage mechanics and discusses damage effects of hydraulic fracturing to reservoirs. An analysis evaluation system of hydraulic fracturing continuum mechanics is set up, and by using damage theories, a method of analyzing hydraulic fracturing in fissured porous reservoirs is discussed.

Introduction

Hydraulic fracturing theories are divided into two schools (Aguilera, 1995): The conventional school believes that hydraulic fractures are perpendicular to minimum principal stress and the prior research is the discussion of one or two fractures' initiations and propagations near wellbore. Three problems mainly solved are (Gidly, 1995; Economides, 2000; Wang and Zhang, 1998): fracture criteria, the direction of fracture propagation and the geometry of hydraulic fractures. Fracture criteria includes tensile strength criteria and fracture mechanics criteria.
Integration of a Geospatial Framework With a Suite of Numerical Models for Operational, Environmental and Regulatory Aspects of Cooling Water Usage
Authors: Febbo Eric , Duggan James , Kolluru Venkat , Prakash Shwet
Published: May 2016

Use of complex mathematical models and geospatial information systems (GIS) has traditionally been a mutually exclusive process. Spatial and temporal modeling is performed using a suite of well-established numerical models for a particular domain or area of interest (AOI) and outputs are produced for the same domain framework. GIS, on the other hand, allows integration for managing, storage, analyzing, connecting to perihyls, output (ie. hardcopy, softcopy) map and image products along with visualizing data for interpretation in two dimensions (2D) and three dimensions (3D) from many sources and different formats. A GIS system can include; marine data: biota, sediment types, water quality, hydrodynamic data, and ecological sensitivity information, in addition to atmospheric meteorological data. The ability to project and integrate results from numerical models in a GIS system could potentially be a powerful spatial decision support system (SDSS) for operational aspects of coastal and offshore industrial activities to support environmental management and for regulatory reporting requirements.

The system would incorporate a web-based computing infrastructure where geospatial data can be accessible to many users with access controls set by data owners that are appropriate to needs. The vision is the implementation of integrated diverse multi-scale, multi-disciplinary spatial data with analytical and numerical models for environmental and industrial management. The initial SDSS developed in this stage of work integrates the physical and logical components of the modeling system into a GIS framework such that seamless interaction and functionality amongst existing GIS data sets and cooling water dispersion model scenarios can be further analyzed and visualized in a spatial format. The system will also have the flexibility to incorporate additional datasets, analytical or numerical models, and other decision making tools in the future. Such systems can assist users such as plant managers (adaptive management), emergency response teams (response planning and action) and policy advisors (impact assessment and planning). The recent emergence, although still in a nascent stage, of web-based, spatial referencing GIS tools show promise in many key aspects of environmental and operational management, research and public policy, including data storage, analysis, and decision making. Systems such as the SDSS developed in this work can help facilitate the use of these emerging technologies.
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

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

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

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

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

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

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

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

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

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.
TOTAL E&P Consideration of new Technologies in Rotating Machines to Respond to the Requirements of Future O&G Developments
Authors: QUOIX Bernard , GELIN Alain
Published: May 2016

Extended abstract

Introduction

To respond to ever more demanding and critical requirements dictated by the current and future developments of O&G fields, combined with harsher environmental conditions, TOTAL consider that innovation and introduction of new technologies are today unavoidable, and this is particularly true for rotating machines. Some examples to illustrate this tendency can be listed, such as:Reinjection pressures in the reservoir ever increasing, reaching 700 bar and more,Gas flows increasing and thus requiring more and more power,Ever increasing water depth: Today, it is almost ordinary to install multiphase pumps and soon high boost multiphase pumps and compressors at minus 1,500 meters of water depth and soon deeper,Less complex compression shaft lines (high speed motors, oil free, Active Magnetic Bearings, sealless), no HC emissions, for upstream applications,Remote Monitoring and Diagnosis,Harsher environment conditions (Artic, large ambient temperature range, offshore, corrosive contaminants, salts, sand, harmattan, etc.), isolated production sites,Wet gas with CO2 and H2S with selection of appropriate metallurgy,More viscous fluids to be pumped in multiphase conditions from the sea bed,Very large gas turbines for future all electric FPSOs and floating production facilities (LNG).

And of course all these new technologies are developed with the requirement of limiting CO2 and NOx emissions, increasing energy efficiency, and improving equipment reliability, while preserving safety of the people and the machines.

The famous "two machines two years" criterion which uses to be the golden rule in the past among most of the Majors is no longer applicable and thus superseded as conditions of new O&G developments, whether climatic, environmental, reservoirs, technological, are changing very rapidly. Therefore, TOTAL, have implemented a thorough qualification process to introduce innovations, allowing thus to lead the required technological evolution, to cope with the rapid market changes, to be able to respond to more and more complex projects, to be ready to implement these new technologies whenever required, reducing costs and increasing energy efficiency, while minimizing the associated risks.

The paper provides some examples of implementation of such new technologies in rotating equipment and describes the qualification process that is followed to declare these technologies fit for purpose.