bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computer Simulation of Thermohydrodynamic and Technological Processes in Active Subsea Oil Pipelines
Authors: Thuc Phung Dinh , Karimov Marat F. , Karimov Zoufar Ph. 
Published: December 2007

Abstract
Here generalized analysis is given for transport of highly paraffin and highly congealing oil taking into account layout, technology of transport and construction features of subsea oil pipeline.
In accordance with results of physical experiments for active oil pipelines the generalized mathematical model was made to explain thermohydrodynamic regime of telescopic construction oil pipe operation for paraffin and highly congealing oil transport.
Thermohydrodynamic and mass exchange process in subsea pipelines are explained by differential equation system: flow (1), continuity (2), energy (3), heavy hydrocarbon fraction concentration forming wall depositions (4), adsorbtion kinetic and hydrodynamic desorbtion of wall oil depositions (5).
Based on mathematical model of existing subsea oil pipeline, new computer method was created for analysis of thermohydrodynamic and technological process while transporting highly paraffin and highly congealing oils. There was developed respective software package allowing to study both steadied and unsteady transport process in wide range of thermobaryc and technological parameters change characterizing oil pipeline operation.
Proposed method of analysis is intended for designing of new pipelines and modification of old subsea oil pipelines and change of transport technology in active pipelined, i.e. optimization of transport parameters and determination of oil pipeline safe operation limit eliminating critical transport regime-telescopic pipeline "freezing".
Digital experiments have shown that in certain technological transport condition the critical operation regime starts proceeding from intensive heavy hydrocarbon depositions (in solid phase) at inside pipeline surface. It is accompanied by spontaneous (uncontrollable) decrease (due to hydraulic resistance) of pipeline throughput. This process (if timely special measures are not taken) will result in full transport stoppage and subsequent pipeline "freezing".
Based on analysis of different technological parameters influence on thermohydrodynamic pipeline operation regime, there were considered and proposed method of thermal, hydrodynamic and chemical influence on wall depositions which allow to eliminate critical pipeline operation regime at different flow rates.
Here the results are given for digital simulation of pipeline operation in form of diagrams.
Luanping Fan-Deltaic Outcrop Geostatistical Characterization & Application to NY Oilfield, China
Authors: Liang Chen , Mu Longxin , Jia Ailin , Huang Shiyan 
Published: December 2007

Abstract
Fan-deltaic environment offers a particular challenge for geostatistical modelling. Over the past decades, geostatistical methods are widely accepted and applied to simulate sedimentary microfacies. In this study we have selected Sequential Indicator Simulation (SIS) to generate our model and perform sensitivity analysis. Luanping fan-deltaic outcrop has been selected as a case study. The outcrop is located in Hebei province, China. The main outcrop cut by road is an excellently exposed study area, whose length and height are 1300 meters and 230 meters respectively. The orientation is nearly east-west. It was deposited from upper Jurassic to lower Cretaceous. Based on outcrop studies, 16 types of microfacies have been classified and for simplicity, they have been finally combined into 6 types of microfacies in stochastic simulation.
The 2-D grid of 470 ×290 (ΔX=2.5m, ΔY=0.8m) has been designed to establish a single deterministic (prototype) model of Luanping fan-deltaic outcrop. The model honors all existing data and represents a realistic geological interpretation as closely as possibly. The input data of SIS are extracted from prototype model at different well spaces of 100,200,300,400 and 500 meters. As a result, microfacies simulations are constructed under different well spaces. Comparing these simulations with prototype model, prediction accuracy and uncertainty analysis are presented in this study.
The study shows geostatistical tools can well reproduce prototype model of Luanping fan-deltaic outcrop. The prediction accuracy is largely relied on variogram model and proportion of each microfacies. Moreover, SIS can also reflect the microfacies distribution law of fan-delta, especially fan-deltaic plain can be reproduced under less information. Finally the results are applied to NY oilfield, China successfully.
A New Approach to 3D Reservoir Simulation: Effect of Interfacial Tension on Improving Oil Recovery
Authors: Mulyadi H. , Amin R. 
Published: December 2007

Abstract
The importance of this simulation work was the incorporation of the experimental interfacial tension (IFT) and oil spreading coefficient parameters measured in our laboratories. The effect of IFT was incorporated into the simulator through relative permeability curves measured under positive and negative spreading coefficient for the three-phase reservoir system: oil, water and gas.
The oil spreading phenomena was tested on a black-oil reservoir located in Australia. The reservoir descriptions used in the model were validated by comparing the simulated results with the actual reservoir performance and its production parameters. A more severe test is to have the simulator compute the past performance of each individual wells, as well as historical pressures and fluid saturation distribution. The models incorporating permeability distributions has shown a far superior history match of primary and waterflood performance at a pressure below the original reservoir pressure (positive spreading coefficient) matching and confirming the core flooding results. Good history match was also obtained on individual well basis.
The work has shown that a substantial increased in the oil recovery can be achieved by operating the black-oil reservoir below its bubble point to ensure a positive spreading coefficient system. This allowed a balance between viscous force and gravity force for the oil to form a thin continuous oil film. Thus, ensuring continuity of the oil flow as it is being produced. The scheme has demonstrated that the oil recovery could be improved by as much as 15%.
Clean up and Well Testing Operations in High-Rate Gas-Condensate Field Result in Improved Sand Management System
Authors: Kaura Jiten Devender , Macrae Alex , Mennie David 
Published: December 2007

Abstract
During development of high pressure/high temperature (HP/HT) gas wells in Oman, clean-up operations that remove up to 10 tons of proppant fracture material from individual gas wells have become routine. The continuing development of fracturing, clean up and testing processes in the HP/HT well-testing environment has provided a unique opportunity to fulfill the need for enhancement of proppant clean-up equipment and methods.
Efforts have been concentrated on improving clean-up times, equipment efficiency and refining the design of the desander/filter sand management system (SMS). As a result of the improvements, the clean-up and testing processes have undergone significant modification.
During the initial phase of the project, numerous challenges had to be overcome, and improvements were made in the solids clean-up process. This paper will describe how proppant and other solids materials were managed during the wellbore and formation clean-out process.
A Study of Removal of Organic Formation Damage by Experiments and Modeling Approaches
Authors: Ju Binshan , Luan Zhian , Wu Zenggui , Lu Guangzhong 
Published: December 2007

Abstract
The precipitation or block of asphalts, asphaltene and other or-ganics in the porous media near the wellbole will reduce per-meability due to change in temperature, pressure and compo-sitions of reservoir oil. Injection of organic aromatic solvents and soaking is one feasible method to remove the precipitates. The objects of this paper are to confect economical and efficient solvents and optimize injected rate, volume and soak time of solvent. To obtain the objects, core flooding experiments by solvents are conducted to select optimum solvents and a simulator to remove the formation damages caused by organic deposition by soaking of aromatic solvents is developed. The influences of different injected rates, volume and soak time of solvent are simulated to improve the permeability of the damaged region. And the permeability is also predicted after soak. A project to remove organic formation damage near the wellbole by injection aromatic solvents started Nov, 1998 at an offshore oil field in China. And the production of the first well increased from 90t/d to 270t/d after injection solvent U-01 selected by core flooding experiments. The simulated results coincide well with the data from the oilfield.
Well Testing in the New Millennium — Real Time
Authors: Finley Douglas B. , Pahmiyer Robert C. 
Published: December 2007

Abstract
As oil industry technology has advanced, increasing emphasis has been placed upon accomplishing operational objectives more safely and efficiently. In pursuing these goals, operators and service companies have investigated the advances made in other technological fields, and many innovative applications have found their way into oilfield operations to accomplish these objectives.
One of the most notable technologies for improving and disseminating information is "Real Time Operations." Real Time Operations or RTO in the oil industry is already a reality in certain geographical areas. Specifically, data from drilling operations such as Formation-Evaluation-While-Drilling are already being "beamed" real-time back to the operators, assisting them in making optimal operating decisions. The advantages are clear when one considers that in the past, the subject matter expert had to be present at the well site in order to carry out any type of real time analysis or control during an operation. This advantage becomes particularly beneficial in remote areas.
Cost savings from RTO vary according to the particular service and wellsite location, but with increasing emphasis on deeper waters, high pressure/high temperature (HP/HT) environments, and remote areas, the value of RTO becomes more evident.
This paper will present a synopsis of oilfield RTO and how it is applied to drill tem testing and well testing. A classification system is proposed for delineating the different types of RTO that are available. Several RTO case histories are presented to support the applications. A discussion concerning the added-value generated as well as the relative cost-savings will be shown by the case histories.
The capability to carry out real-time analysis remotely can positively effect cost efficiency and allow state-of-the-art testing to be performed in areas that would not previously have been feasible. In addition to the present usage of RTO in the oilfield, this paper will discuss what RTO capabilities can provide, in both the near-term and in the distant future.
The Integrated Production Database in Unocal Indonesia
Authors: Chatterjee Debasis , Palar Steve , Rothenberg Louis 
Published: December 2007

Abstract
Unocal has been a leading developer of Indonesia's energy resources for more than 30 years. In the late 1960s, Unocal Indonesia signed one of the world's first production-sharing contracts with Pertamina, Indonesia's national oil company. Currently, Unocal Indonesia operates 11 producing oil and gas fields offshore East Kalimantan, including Indonesia's largest offshore oil and gas field, Attaka, which the company discovered in 1970. The cumulative production of Unocal Indonesia to date is 890 MMB of oil and 1.87 TCF of gas.
Each day, a wealth of data related directly or indirectly to the volume of hydrocarbon production is collected at various points of oilfield operations. These data are transmitted to Unocal Indonesia's office via e-mail and are further processed for plant balance, gas allocation and monthly allocation. The raw and processed data can be accessed via Unocal Indonesia's Intranet for further data analysis and usage in simulation, mapping and general surveillance.
Until recently, a suite of four separate computer systems managed the production data. In 2000, Unocal Indonesia's Petroleum Engineering department decided to streamline the heterogeneous and proprietary solution by adopting a commercial master database and data management solution similar to the parallel data management effort in the Geological & Geophysical (G&G) domain. This effort is in line with the vision of knowledge management that can be created by integrating business processes and sharing information to manage the life cycle of Exploration & Production (E&P) assets.
This paper describes an integrated G&G and production data management system based on the Finder data management system and details how such a system improves employee productivity.
A phased approach has been adopted for implementation of the solution. The first phase involves consolidation of the legacy databases into a commercial master database that is built on an industry standard data model. In the second phase, the field data capture process will be improved and the current proprietary allocation and balance system will be replaced with a commercial solution.
The final result will be a single data repository providing Unocal Indonesia staff with validated, approved and easy-to-use data that is accessible via built-in data browsing facilities and inter-application data exchange utilities. In addition, the commercial system will require a smaller support staff, thereby freeing up more Unocal Indonesia team members to focus on maximizing the production and the recovery of reserves.
Estimation of Formation Hydraulic Properties from Analysis of Regular Operations Data
Authors: Silin D. B. , Tsang C.-F. 
Published: December 2007

Abstract
We propose to use regular pumping rate - pumping pressure data for estimating the formation hydraulic properties in the vicinity of wellbore without interrupting the operations. A distinctive feature of our analysis is that we account for the effects of pumping preceding the test interval. We derive our model from the same assumptions as in a standard pressure draw-down or pressure build-up test analysis. We introduce an additional parameter characterizing an effective pumping rate prior to the test. This parameter is of crucial importance for our procedure because there is no shut-in period preceding the test during regular operations. Moreover, we demonstrate that accounting for this parameter does affect analysis of a traditional pressure draw-down or build-up test as well. Our method produces good data matching, and the results are stable with respect to the selection of the portion of data for fitting. We derive our conclusions after analyzing almost entire data set, rather than only a portion of the pressure fall-off or build-up curve. This makes the results more reliable and stable with respect to measurement errors.
The new method we have developed is implemented in a code named ODA (Operational Data Analysis). This program incorporates a special curve-fitting procedure which we designed for our method to significantly simplify the problem and reduce the amount of computations. Therefore, the analysis can be preformed on a laptop computer.
Surface-Geometry and Trend Modeling for Integration of Stratigraphic Data in Reservoir Models
Authors: Xie YuLong , Cullick A. Stan , Deutsch Clayton V. 
Published: December 2007

Abstract
Accurate prediction of reservoir performance depends on an accurate estimate of the subsurface structure, lithofacies, associated petrophysical properties, and fluid distribution. Often the reservoir heterogeneities that are controlled by stratigraphic architecture and sedimentological trends are difficult to predict, particularly at subseismic resolution and far from well control. An ongoing challenge in subsurface modeling has been the utilization of analogs of complex geology along with seismic and sparse well data to predict the natural geologic complexity in models of the subsurface.
Time surfaces provide very important constraints on the geometric connectivity and continuity of facies and petrophysical properties in reservoirs. Such time surfaces are a suitable framework for facies and petrophysical properties modeling. Instead of modeling each reservoir later as a whole, the elementary sediment units are more easily modeled separately; the final composite model will show realistic heterogeneity patterns consistent with the underlying physics.
This work presents a hybrid deterministic, rule-based, and stochastic technique to generate surface models. These surface models are utilized as a framework to preserve sediment trends and honor analog and well data. Petrophysical properties are modeled for each sediment unit to reproduce trends. Finally, the individual sediment units are assembled into a reservoir model.
The surface model is created stochastically with parameterized surface templates. The shape, extent, height, orientation and regularity of the surfaces are controlled by user-specified distributions. The location of each surface in the reservoir is chosen on the basis of previous events. The addition of each surface is based on sedimentological rules. Conditional Gaussian simulation is used to ensure that the surfaces reflect realistic uncertainty through undulations and that well data intersections are honored.
The surface model divides the reservoir layer into sediment units. From geology and well data, trends are parameterized with mathematical functions as trend templates. Residuals are characterized after removing the trend. For each sediment unit, a trend and a residual model are generated stochastically. The observed well logs serve as conditioning data to guide the deployment of trends and to condition the generation of residuals. The model of each sediment unit combines its trend plus residual. The final reservoir model is obtained by assembling the separate sediment units.
A New Material-Balance Equation for Naturally Fractured Reservoirs Using a Dual-System Approach
Authors: Penuela Gherson , Idrobo Eduardo A. , Ordonez Anibal , Medina Carlos E. , Meza Nestor S. 
Published: December 2007

Abstract
The complexity associated to naturally fractured formations constrains reservoir engineers to use simplified versions of the Material Balance Equation for determining the initial hydrocarbon in place and predicting reservoir performance. Although in particular cases a limited variant of the MBE may end up in small volumetric errors, the risk of using it is extremely high.
In this paper, a new material balance equation for naturally fractured reservoirs is presented by using an original mathematical model that considers an initially-undersaturated black-oil fluid in a porous medium composed of interdependent matrix and fracture systems.
The proposed equation leads to an improved method of modeling naturally fractured reservoirs by considering the compressibility difference between fractured and matrix systems. Particularly, the analysis displays its capability in reservoirs that have similar storage capacity in matrix and fractures. Modeling separate estimates of oil accumulation have significant economic implications. Poor fracture-matrix communication will give initially high oil rates that drop quickly because oil is basically produced from the fracture network. Pore pressure reduction due to production will tend to close fractures leaving behind considerable oil reserves in the matrix system. Estimates of original oil in-place both in the matrix as well as in the fracture system will help reservoir and production engineers to decide on exploitation strategies for these complex reservoirs.
Our proposed equation has been applied to synthetic as well as field examples. Synthetic examples are used to validate the approach and examine the sensitivity to the average fracture compressibility. The field example is from El Segundo field, a low porosity carbonate reservoir in Colombia. Our example includes 8 producers located along the main fracture trend of the field and illustrates the feasibility of the approach for large-scale field applications.
A New Diagnostic Method for Prediction of Producibility and Reserves of Wells Producing from the Monterey Formation Using Well-Log Data
Authors: Wylie Ursula M. , Ershaghi Iraj , Christensen Karen 
Published: December 2007

Abstract
Formation evaluation using well log data is primarily a prediction tool for the purpose of identifying porous and permeable zones containing movable hydrocarbons. When the lithology is complex or the productivity is controlled by fracture density and the well log data are limited in scope, underestimation of productive intervals can occur. This paper is a unique study on relating more than 28 years of actual production history to the initial well log responses. This retrospective approach is the basis for presenting a diagnostic approach to predict producibility and reserves for other wells in the field under study or in other neighboring fields with similar geology.
The focus of the study is well log responses in the Monterey Formation of California Offshore. The geology of this formation is regarded as a prime example of a heterogeneous matrix system and a lithology-dependent fracture network. Lithology of the Monterey Formation is heavily influenced by the diagenetic stage of biogenic silica comprising the bulk of the geologic column, the detrital content and calcareous component. The particular field selected represents typical lithological and diagenetic stages observed in surrounding fields. As such, the proposed approach has merits for application to other fields. Geographically the Monterey type sediments extend from Baja California and all the way along the Pacific Rim to Japan8. Extension of the lithological patterns observed and the productivity correlations in surrounding fields can lead to eventual development of a more general correlation for widespread exploratory or development wells in this type of formation.
Transient Dual-Porosity Behavior for Horizontal Wells Draining Heterogeneous Reservoirs
Authors: Verga F. M. , Beretta E. , Albani D. 
Published: December 2007

Abstract
In the literature it has been shown that a bilinear flow regime, characterized by a quarter slope line on the logarithmic derivative diagnostic plot, can arise for horizontal wells draining fractured or layered reservoirs with transient dual-porosity behavior during the intermediate linear flow period. In the case of layered reservoirs the bilinear flow is a result of the linear flow in the more permeable layer toward the well and of the linear flow from the less permeable layer by which the more permeable layer is fed. In the case of fractured reservoirs the bilinear flow occurs as a result of the linear flow in the fracture planes and of the linear flow from the matrix toward the fractures. Therefore, bilinear flow is expected to end in relatively short times.
However, bilinear flow was also observed for a long period in the case of two horizontal wells draining a layered, heterogeneous limestone reservoir. The reservoir is characterized by matrix porosity only but highly permeable subvertical zones have been detected due to consistent mud losses occurred during well drilling, and by well logging. The two wells are drilled in the more permeable layer of the depositional sequence encountered at each well location.
A 3D numerical model of the reservoir was set up accounting for reservoir heterogeneity in an attempt to reproduce the pressure trend observed during well tests, which consistently showed a quarter slope pressure derivative. Results showed that the vertical heterogeneity would not lead to a bilinear flow regime although the permeability contrast between layers could locally exceed two orders of magnitude, probably because such contrast would not keep constant throughout the reservoir. The quarter slope pressure derivative could only be reproduced when the horizontal heterogeneity was accounted for, assuming that the more permeable subvertical zones would intersect the whole oil-bearing formation.