bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well-Test Analysis in Gas-Condensate Reservoirs: Theory and Practice
Authors: Gringarten A.C. , Bozorgzadeh M. , Hashemi A. , Daungkaew S. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Gas condensate reservoirs exhibit a complex behavior when wells are produced below the dew point, due to the existence of a two-fluid system, reservoir gas and liquid condensate. Different mobility zones develop around the wellbore corresponding respectively to the original gas in place (away from the well),the condensate dropout, and capillarity number effects (close to the well).Condensate drop-out causes a nonreversible reduction in well productivity, which is compensated in part by capillarity number effects.
All these effects can be identified and quantified from well test data. Tests in condensate reservoirs, however, tend to be difficult to interpret. Build-up and/or drawdown data are usually dominated by wellbore phase redistribution effects and the main analysis challenge is to distinguish between reservoir effects, boundary effects, fluid behavior and wellbore phase redistribution perturbations.
The paper compares theoretical well test behaviors in vertical and horizontal wells as obtained from compositional simulation with actual behaviors selected from more than twenty different gas condensate reservoirs. An interpretation methodology is described, which uses time-lapse analyses with different analytical and numerical tools to identify the probable causes of the pressure data behavior: two-region and three-region analytical composite models to represent the various mobility zones around the wellbore; a voronoi-grid numerical simulator to represent discontinuous boundaries; a multilayered analytical simulator to account for the geological description, and a compositional simulator to verify the fluid behavior. It is shown that, in addition to the usual well test analysis results, it is possible to obtain parameters required for reservoir simulation and well productivity forecasting, such as gas relative permeabilities at the end point, critical oil saturation, and the base capillary number.
Well-Test Analysis in Low-Permeability Multilateral Wells
Authors: Gringarten A.C. , Sharma R. , Rajvanshi A.K. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Multilateral horizontal wells are used extensively in a number of reservoirs around the world, and particularly in the Middle- East. Development is often based on patterns of multilateral producers and multilateral injectors, and these, combined with complex reservoir geology, create well test pressure behaviors that are usually difficult to interpret. Ideally, well tests should be conducted one individual horizontal branch at a time and branch rates and producing lengths should be measured in order to decrease the non-uniqueness of the well test interpretations. In practice, this is not often possible and all branches are tested together. Low permeability reservoirs add to the difficulty, by reducing the information available within the normal duration of a build-up test. Although theoretical solutions for multilateral wells have been published in the oil literature, there are very few actual examples of well tests and even fewer detailed well test analyses.
This paper describes the analyses of well tests on several multilateral wells in a low permeability carbonate reservoir in the Middle-East. It is shown how a maximum of useful information can be extracted from the well test data, using a combination of techniques and tools, such as time-lapsed derivative analysis, analytical multiwell simulators, and deconvolution. Limitations and uncertainties in the analyses as a function of the data available are also discussed.
3D OBC Seismic Survey Design for Multiple Objectives
Authors: Painter D.J. , Al-Sharif S. , Qaradeh M. , Al-Kaabi M. , Furuya K. , Belaid K. , Al-Shateri A. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
ADMA-OPCO and ZADCO are performing an intensive 3D OBC (Ocean Bottom Cable)seismic survey offshore Abu Dhabi with the twin primary objectives of defining the Thamama reservoir in an undeveloped structure and defining the overlapping Mishrif reservoir in a currently producing field. Survey value is increased by the reservoir characterization information that can be extracted from the seismic data. The structural Thamama target has different seismic acquisition geometry requirements to those of the stratigraphic Mishrif reservoir. OBC acquisition has a huge range of potential geometries and value and costs. This paper describes the processes that were used to reconcile the technical and economic conflicts.
Experience from a previous 3D OBC survey highlighted the generic problems in the area:Source-generated noiseStrong multiple interferenceAcquisition footprint
New survey design had to overcome these plus deliver high-resolution data(80 Hz at target level) to attain the stratigraphic and reservoir characterization objectives within a finite budget.
Team identification of key objectives was critical for the implementation of the successful survey design. Analysis and review of various modeling processes(acquisition geometry, seismic processing responses, acquisition economics)guided the team to an affordable solution that meets the geophysical objectives of a high-quality, high-resolution survey.
The process has provided a methodology that will be used as a basis for evaluating of cost versus quality in future surveys.
3D Geological Modeling-While-Drilling for Geosteering
Authors: Najjar N.F. , Jerome T. , Alshammery M. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The drilling of horizontal and multilateral wells has grown rapidly over the last decade. Successful geosteering of these wells in thin reservoir layers requires an accurate reservoir model that is updated in real-time with incoming logging-while-drilling (LWD) data. 3D geological modeling-while-drilling workflows, which utilize geostatistical techniques, were developed to facilitate model updating, while improving the accuracy and reducing the cycle-time of the geosteering process. A data link between LWD tools in the field and Saudi Aramco's offices in Dhahran provides real-time information to quickly update the 3D earth model, enabling multi-disciplinary geosteering teams to make fairly quick decisions regarding well bore trajectory changes.
In the initial step of the modeling-while-drilling workflow, a sector model which includes the planned horizontal well and neighboring wells is extracted from the existing full-field 3D geological model. Downscaling is applied to generate a fine resolution model along the planned well path. Using nearby welldata, the model is subsequently populated with reservoir properties such as porosity and gamma ray by means of variograms and geostatistical techniques, for instance Kriging or Sequential Gaussian Simulation (SGS). Pseudo well logs could be extracted along the planned well path for comparison with LWD measurements.
The 3D earth model is continuously updated during the drilling phase by automatically loading and integrating LWD data transmitted from the field. Quick model updating is done both for the structural and petrophysical components of the model. The new well data and revised earth model are analyzed in real-time, allowing the multi-disciplinary geosteering team to quickly make changes to the planned well path and convey those changes to the drilling engineer at the rig.
Field examples in various geological settings will be used to illustrate the modeling-while-drilling approach. It is an extremely useful technique that can be utilized to optimize well path, maximize well productivity, and reduce rigwait time. In addition, it allows professionals from different disciplines, whether in the field or geosciences centers, to work together in an integrated manner so as to reduce costs and improve well placement.
Coupling Complex Multiphase Pumps Surface Constraints to Reservoir Models for Optimising the Future Management Plan of a Mature North Sea Field
Authors: Foucault Hugues , Charles Thierry , Fulton Jonathan , Jaffrezik Vincent 
Published: February 2016

Abstract
Reservoir simulation is traditionally one of the main tools used for reservoir management plan definition. The situation gets more complex when the surface network plays an important role in the production profiles definition and behaviours, at least for part of the field life, as a bottleneck. New products have just been commercialised (PipeSim™, GAP™, Resolve™, R2SL™) but coupling complex surface network representation with reservoir simulators still remains at its beginnings. This paper describes a multi stage approach to model the impact of the multiphase pumps constraints of a Northern North Sea Field on the production profiles. From the simplest representation (GAP™ model plus look-up tables) to the most integrated, the implications of this model on the field development plan will be presented and the key issues of such a coupling discussed.

Introduction

Production management new era
Understanding behaviours of reservoirs, wells and surface networks, and forecasting the production profile over the entire field life have always been challenging tasks for the petroleum industry. They are usually addressed using separate simulators for every node of the production chain.
In this situation, interactions and influence of upstream or downstream events on the results of each model are only approximately accounted for. Reservoir simulators model the production from sandface to the wellhead only through the use of Vertical Lift Performance (VLP) tables and have a limited modelling of the surface piping. So production network effects on the behaviour of the overall system are not fully acknowledged. This may have a direct impact on the evaluation of the production targets that will actually be achieved. On the other hand, production network simulators typically use surface network model analysis that fully accounts for those effects but can only model the reservoir with a simple «inflow» model: material balance, decline curves or even fixed productivity index.
However, for the last few years, significant developments have been implemented to allow the construction of fully integrated models. Various types of controller for coupling reservoir simulation and surface facility network have been introduced in the literature. Since end 2004, the research tools have been finally proposed on the market, launching a new era for the simulation of the production chain from reservoir to surface.
Operating Experience with the SplitMR Machinery Configuration of the C3MR LNG Process
Authors: Brimm Allen E. , Ghosh Samiran , Hawrysz Daniel 
Published: February 2016

Abstract
Efficiency and economics have motivated RasGas Trains 3–5 to implement a novel compressor-driver arrangement comprising both propane and mixed refrigerant (MR) compressors on a single shaft. One Frame 7E gas turbine drives the LP and MP MR compressors while a second Frame 7E drives the propane and HP MR machines. With minor control system adjustments after startup, the refrigerant compressors in RasGas Train 3 are operating reliably.

Introduction
The propane precooled mixed refrigerant (C3MR) process developed by Air Products has been the dominant process technology employed in the LNG industry for over 30 years. This process uses a propane refrigerant system to chill the feed gas from ambient temperature to about -33oC and a mixed component refrigerant (MR) to chill the gas to LNG temperatures. Because pure propane is used in the precooling refrigeration cycle, the minimum temperature of this cycle is limited to the boiling temperature of propane near atmospheric pressure. The total duty that can be transferred to the propane refrigerant is thereby naturally limited to heat that can be transferred within this range.
Because of the propane's limited temperature range, one of the characteristics of the C3MR process arrangement is that the MR refrigeration system requires nearly double the compression power of the propane refrigeration system. The actual difference depends on the number of propane stages, the ambient conditions, the environmental cooling medium, and other process arrangements. To drive these refrigeration compressors, early LNG plants used steam turbines that could be sized to fit the required service (e.g. Marsa el Brega).Later projects determined that gas turbines drivers were a more efficient and less costly option for driving the compressors.
For procurement, maintainability and sparing purposes, an operating facility would prefer to have each of the compression services driven by the same type and model of gas turbine driver. For the C3MR process, such an arrangement is typically inconvenient due to the inherent power consumption mismatch between the propane and MR services.
Sour Gas Treating for LNG Production
Authors: Al-Mohannadi Ahmad , Fieler Eleanor R. 
Published: February 2016

Abstract
Produced natural gas must be treated to ensure high efficiency removal of sulfurous contaminants before it can be processed into liquefied natural gas (LNG).The selection of processes for removal of H2S may be a straightforward decision with extensive supporting data available. However, when the produced natural gas feedstock contains significant mercaptan, COS or other sour components, the process selection and design may become extremely complex. Several issues including process selectivity, energy requirements, total sulfur recovery, hydrocarbon coabsorption, and impact on downstream facilities will be weighed in this poster.
When technologies are being evaluated for use in pretreatment of gas for LNG production for the first time, the extremely high reliability and strict specifications of the LNG process must be taken into consideration. Often the processes under consideration are provided by licensors, and evaluation of data from historical applications should be undertaken cooperatively by the licensor and the operator to ensure that all facets of the operation are well understood. This is particularly challenging since it is rare to encounter exactly the same compositions and conditions more than once in the midstream.
LNG facilities operating in Qatar have installed multiple processes to maximize sulfur recovery at minimum cost. Based on the operating data from these units, ExxonMobil in cooperation with RasGas Company Limited (RasGas) has developed dynamic models and modified processes to optimize the operation of the existing facilities and the design of future ones. This work is aimed at high reliability, high efficiency, environmentally sound process units that support maximum LNG production at the lowest supply cost.

Background
RasGas has extensive experience in operating gas sweetening and sulfur recovery units. In addition to moderate concentrations of H2S and CO2 that must be removed from the produced gas, a variety of mercaptans and other sulfur containing species compose up to 400 ppm of the gas. In RasGas Trains 1 and 2, Sulfinol-D was chosen as the gas sweetening process, and the acid gas stream was directed to an Acid Gas Enrichment unit before entering the Sulfur Recovery Unit. This system has worked effectively to achieve the very low levels of total sulfur (&lt; 14 ppm) required for the liquefied product.
Analyzing Microbial Improved Oil Recovery Processes From Core Floods
Authors: Kowalewski Espen , Rueslatten Ingun , Boassen Tony , Sunde Egil , Stensen Jan Age , Lillebo Bente-Lise Polden , Bodtker Gunhild , Torsvik Terje 
Published: February 2016

Abstract
Several mechanisms have been proposed to account for the increased oil recovery observed as a result of Microbial Improved Oil Recovery (MIOR) processes, both in laboratory experiments and field cases, but few of these mechanisms are verified. One of the reasons may be that these systems include living bacteria that ideally should be kept in a growing state during the investigations. This paper presents experimental results and a literature review where mechanisms are discussed, with main focus on changes in interfacial tension (IFT), wettability and permeability reduction during MIOR experiments. Special emphasis is put on wettability changes in a laboratory study of an MIOR core. The wetting conditions are studied by using an environmental scanning electron microscope (ESEM) that has been improved by modifying the cryogenic vacuum system for sample preparation. The ESEM equipment enables qualitative and semi-quantitative investigations of wettability changes after a core flood. The saturation profile in an MIOR core should show where the incremental oil is mobilized. An alternative technique for saturation determination is therefore presented, which is based on image analysis from electron images acquired in the same process as the wettability investigations. The number of cross sections with saturation estimations in this study is too few to make a reliable oil saturation profile (e.g., compared to a computer tomography scan). However, the average saturation from the images is close to the saturation calculated from the flooding process. The results of the study indicate that only small parts of the pore space have changed from their original strongly water-wet condition to a more oil-wet state.

Introduction
MIOR has shown significant potential for improving the recovery factor and should therefore be considered for implementation in producing oil fields and also in reservoir development plans. The technology is very cost efficient in a field case due to several reasons: When a water injection system is in use, the MIOR process can be initiated without major changes, thus the investment costs are low. Further, the use of biocides to limit the growth of bacteria producing H2S, and thereby causing reservoir souring, can be reduced since the MIOR process stimulates the growth of other bacteria which suppresses the growth of the H2S producing strains.
Hydrodynamic Conditions of Hydrocarbon Migration and Accumulation Exemplified by the Pomorsko, Czerwiensk, and Zarnowiec Oil Fields, Poland
Authors: Zawisza Ludwik Karol , Dylag-Wojna Elzbieta , Smulski Rafal Josef 
Published: February 2016

Abstract
The hydrodynamic conditions of migration and accumulation of hydrocarbons are exemplified by the Pomorsko, Czerwiensk and Zarnowiec oil fields in Poland.
According to Hubbert, under hydrodynamic conditions a buoyancy force and moving water exert major control over the distribution of water, oil and gas in a reservoir, causing the oil/water and gas/water contact to be tilted.
In this paper, a modified theory is advanced to define more precisely the position of potential oil and gas traps. The theory introduced here is more universal than Hubbert's theory because it accepts not only the groundwater motion (dynamic effect), but also the variability of the oil, gas and water density (static effect) and heterogeneity of reservoir rocks (capillary effect).
According to the presented method, to determine potential hydrodynamic entrapment of hydrocarbon, it is necessary to construct potentiometric maps for groundwater in terms of fresh water, maps of differential energy of oil or gas with respect to groundwater and maps of differential energy of oil or gas caused by capillary forces and then to add them up by superimposition.

Introduction
For determining hydrodynamic traps, Hubbert's potentiometric model of hydrocarbon accumulation is applied with its further modifications.
Potentiometric theory by M.K. Hubbert1 accounts for the influence of buoyancy force and hydrodynamic factor, related with the motion of groundwaters in a water-oil-gas bearing strata, on the locality of oil-water and gas-water contacts. M.K. Hubbert's theory disregards changes in the density of water, oil and gas, as well as the capillary pressure effect.
An original method of mapping hydrodynamic traps for oil is presented in the paper. It is a modification of the potentiometric theory by M.K. Hubbert.1 This novel approach accounts both for the influence of dynamics of groundwaters and also changes of reservoir fluids density values and the effect of capillary pressure values on the location of hydrodynamic traps. With this method it is possible to determine hydrodynamic traps location on a map, in 3D space, in the flowing water conditions.
Application of Real-time ESP Data Processing and Interpretation in Permian Basin "Brownfield" Operation
Authors: Oyewole Peter 
Published: February 2016

Abstract
Electrical submersible pump (ESP) operation, like many other segments of the oil industry, is recovering from having been drowned in large number of data, the aftermath of information technology revolution, and refocusing on effective utilization of reservoir and production data. This paper presents results of the application of real-time data processing and interpretation in a mature field (Permian basin) through operating and service company alliances. The process involves application of production system efficiency management coupled with newly developed advanced ESP technology and analysis tools-computer simulation software packages that could simulate actual ESP and downhole performance. Data are acquired from the wellsite using data acquisition panels and are sent over a secure network connection to a data hub. The data are also sent for intelligent real-time ESP data processing and interpretation. Well and reservoir monitoring, surveillance, analysis, and diagnosis are also performed. Active collaboration with producing companies at every stage of the process was encouraged through the formation of a new alliance. Finally, various recommendations and suggestions that could operate, optimize the ESP system, reduce well downtime, and prevent catastrophic and premature ESP failures were made.
This new approach to ESP operation reduces daily challenges in operating brownfields, such as keeping wells economically viable; solving production problems associated with operating mature assets in today's oil industry that is plagued with continuous declining of manpower resources. As might be expected, lease operating expense (LOE) and/or deferred oil production is reduced. Operational case studies and individual benefits are highlighted and included in this paper. This new approach is a significant departure from the conventional ways of operating ESP where service companies traditionally supply ESPs to producing companies to operate. This new alliance will have a decided influence on future ESP operation and the survival of many brownfields worldwide.

Introduction
ESP applications as a form of artificial lift method have continued to increase through the years, and significant growth is expected in the next decades as artificial lift requirements increase to a greater extent than current usage. ESP application covers all aspects of hydrocarbon exploitation. Its usage ranges from mature marginal onshore wells to high profile, deep-water subsea wells.