bluuebunny/crossref_metadata_2025 huggingface dataset:
Horizontal Waterflooding in Shuaiba Carbonate Reservoir of Daleel Field in Oman: From Pilots' Performance To Development Era
Authors: Zhang Liping , Zhou Liqing , Al-Mugheiry Mohammed , Xu Kuangda
Published: December 2007

Daleel hydrocarbon field is located in Block-5 concession area in North Oman. The field produced oil from a Shuaiba carbonate reservoir for more than ten years in depletion mode initially with vertical wells and then horizontal wells.

Due to high depletion in the field and the need of redeveloping the field, horizontal waterflooding was selected as the best mechanism to achieve this after scrutinizing several alternatives.

To confirm the selection of the horizontal waterflooding, several pilots were implemented in selected areas of the reservoir, with closely monitoring the performance and behavior of existing and new wells. Pilot results show very favorable initial results in many cases as expected or even better.

Owing to these successful results, Daleel field is starting a new era in its history with a completely redeveloped horizontal waterflooding pattern of its two major producing blocks with the expectation to get the maximum recovery. In addition to this, the learnings from the pilot tests and the waterflooding experience gained will be the valuable adding to other blocks in Daleel field and other similar fields worldwide.
Destruction and Reconstruction of Well Patterns in Anisotropic Oil Reservoirs
Authors: Liu Yuetian
Published: December 2007

The mechanism of the anisotropic permeability effects on the well patterns and reservoir development are investigated by coordinate transformation, fluid flow analysis, and reservoir development concepts. The Anisotropy of reservoir permeability has destruction and reconstruction effects on general well patterns. The originally designed flooding units are broken up, and new pattern units are made up of the wells that belong to different original units. The behavior possesses strong randomness, and leads to the chaotic relationship among the injection and production wells, and uncertain productivity of the oil reservoirs. It interferes significantly the oil production and recovery. To prevent the well pattern destruction, well line directions should be either parallel or perpendicular to the principal direction of the anisotropic permeability (i.e. the fracture direction). To optimize the development effects of the anisotropic oil reservoir, the latitudinal and longitudinal well spacing of the well network are calculated from the principal values of the anisotropic permeability.
Increasing Production by Maximizing Underbalance During Perforation
Authors: Jan Badrul M. , Rae Graeme , Noor M. Ishenny , Suhadi An N , Bhd Enro Analisa Sdn , Devadass Melvin
Published: December 2007

The invasion of pulverized rock formation grains and the resulting "low-permeability crushed zone" is the primary cause of wellbore damage in perforated completions, as established by Behrmann et. al. In order to minimize this damage during the perforating process, it is necessary to provide a dynamic underbalance in the well that will deliberately induce flow into the wellbore for tunnel cleanup. Traditional well fluids have a limited application in depleted reservoirs as the lowest achievable density is on the order of 6.6 ppg. In many depleted reservoirs this density can represent an overbalance. It is not always desirable or operationally practical to provide this underbalance with a gas cushion, and therefore in order to achieve underbalance, it is desirable to engineer a stable fluid with non-damaging chemical properties that would have a significantly lower density. This paper reports on the formulation of super light completion fluids consisting of Shell Sarapar 147 synthetic oil [Shell MDS (M)], 3M™ Glass Bubbles as a density reducing agent and an appropriate rheology control agent. Laboratory tests show that density values as low as 5.0 ppg could be achieved. Similar mixtures were prepared and used in perforation operations for Talisman's Malaysia. A total of 72 barrels of lightweight completion fluids at about 5.5 ppg was pumped downhole and the perforation job completed successfully. Production history of the well shows a marked increase in production rate compared to neighboring wells, which produce from the same reservoir, but were perforated traditionally. This technology is not necessarily limited to depleted reservoirs. In normally pressured zones where permeability is extremely low, the fluid provides an opportunity to increase the available underbalance by an order of magnitude to assist cleanup.
Nonmetallic Unbonded Flexible Pipes for Deep Water
Authors: Bryant Mike , Bhat Shankar , Chen Bin
Published: December 2007

A new generation of lightweight, flexible, non-metallic, un-bonded pipes has been developed for use in subsea and deepwater floating system applications. These pipes are the first of their kind offering large savings in weight and cost to operators. In addition, the elimination of metallic reinforcements removes the associated corrosion concerns in sea water and the U-value of the pipe is improved.

The Flexible Fiber Reinforced Pipe (FFRP) is constructed from extruded polymeric layers reinforced with unbonded laminated glass-fiber tape stacks. The unique design allows the construction of lightweight flexible pipes with attractive features such as capability for high internal and external pressures, in a wide range of sizes varying from 2 inch to 16 inch. It is intended to be used in deepwater.

An overview of FFRP technology is presented in this paper. Typical designs of the pipe are described. A brief overview of qualification tests is provided along with a description of initial applications. This technology has the potential to be a ‘game changer’, enabling new, lower cost field development solutions in offshore areas around the world.
Nonmetallic Unbonded Flexible Pipes for Deep Water
Authors: Bhat Shankar , Bryant Mike , Chen Bin
Published: December 2007

A new generation of lightweight, flexible, non-metallic, un-bonded pipes has been developed for use in subsea and deepwater floating system applications. These pipes are the first of their kind offering large savings in weight and cost to operators. In addition, the elimination of metallic reinforcements removes the associated corrosion concerns in sea water and the U-value of the pipe is improved.

The Flexible Fiber Reinforced Pipe (FFRP) is constructed from extruded polymeric layers reinforced with unbonded laminated glass-fiber tape stacks. The unique design allows the construction of lightweight flexible pipes with attractive features such as capability for high internal and external pressures, in a wide range of sizes varying from 2 inch to 16 inch. It is intended to be used in deepwater.

An overview of FFRP technology is presented in this paper. Typical designs of the pipe are described. A brief overview of qualification tests is provided along with a description of initial applications. This technology has the potential to be a ‘game changer’, enabling new, lower cost field development solutions in offshore areas around the world.
Application of Dipole Sonic To Evaluate Hydraulic Fracturing
Authors: Tellez Oscar , Castellanos Julian , Casadiego Armando , Lopez Emiliano , Sorensen Federico , Kessler Calvin , Torne Juan Pablo
Published: December 2007

Hydraulic fractures are used worldwide to enhance oil and gas production. In many cases, the stimulation jobs cover multiple intervals and the evaluation of the individual zones is not a straightforward process.

In Colombia (Figure 1), it was proposed to HOCOL to run the crossed dipole sonic, inside casing before and after a hydraulic fracturing job, to evaluate changes in anisotropy due to the treatment. This paper presents the complete process, including the planning and evaluation of the logging and hydraulic fracturing, and the use of this technique to evaluate hydraulic fracturing effectiveness when multiple zones are open and fractured simultaneously.

Figure 1 Columbia's Upper Magdalena Valley.

The planning process includes the use of the dipole sonic to determine rock properties and the calibration process to adjust the computation of sanding potential and fracturing pressures.

The use of acoustic anisotropy in cased hole proved to be an effective method for evaluating the effectiveness of the fracture treatment and for defining the characteristics of the resulting fractures. This is an innovative technique; a second application well is presented in this paper including the results.
New Technologies and Applications for the Vertical Seismic Profile as a Lithostructural Tool and "Look Ahead" Mode
Authors: Hernández Gerardo , Campos Humberto , Pérez Rafael , Barrios Oscar , Bautista Ricardo , Brewer Robert J. , Torne Juan
Published: December 2007

Vertical Seismic Profile (VSP) technology is normally used to correlate seismic time to actual drilling depths. The introduction of new technologies for wireline tools has allowed accurate acquisition data from reflectors 500 to 700 meters below the deepest VSP level to as deep as 5400 m. The tools can tolerate temperatures up to 220 deg. C. The process of acquiring such information and analyzing it will be presented in this paper.

Selected wells will be presented as case studies for the "Look Ahead" technique. In all such studies, a "Look Ahead" VSP survey had been acquired in the intermediate phase of drilling a well, and the results were compared to the surface seismic data. After the well was completed, the VSP data was then compared to a synthetic seismogram. The results showed that the VSP was accurate, in depth, for the reflectors observed in the "Look Ahead" mode. These results confirmed that the technique was a good predictor of the depth of occurrence of litho-structural reflectors when this new technology tool is used.

More recent applications also show the value of the VSP survey as a litho-structural evaluation tool. An original litho-structural model interpreted a thin shale layer throughout a producing field. After the VSP was acquired, it was evident that the real shale thickness was at least twice the thickness interpreted for the original model. Another well drilled still later further confirmed the new, thick shale model.

The use of new technologies for VSP combined with good quality procedures in acquiring and processing seismic information has proved to be helpful in optimizing costs and making decisions especially when drilling exploratory wells.
Integration of In-Situ Fluid Measurements for Pressure Gradients Calculations
Authors: Dubost F. X. , Carnegie A. J. , Mullins O. C. , Keefe M. O. , Betancourt S. , Zuo J. Y. , Eriksen K. O.
Published: December 2007

Reservoir fluids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity, capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered, for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a greater number of data points, fluid samples and associated laboratory analysis.

Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density, fluid contacts, and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA) measurements to reveal possible reservoir fluid heterogeneities.

Although these fluid complexities have been largely recognized, conventional pressure-depth plot and pressure gradient analysis are still performed with traditional straight line regression schemes. This process may however be misleading as fluid compositional changes and compartmentalization give distortions in the pressure gradients, which lead to erroneous interpretations of fluid contacts or pressure seals. Hence the models imposed on the pressure data to calculate pressure gradients need to incorporate a rigorous mathematical approach to respect all data available, so as to follow an objective assessment of reserves and reservoir architectures.

This paper presents a method to use combined repeated pressure and in-situ fluid measurements to provide a simple model of vertical fluid distributions, looks at the different regression schemes that can be imposed on pressure data to calculate fluid gradients with their associated uncertainties and concludes on an optimal fit approach. This data integration then allows making assessments and quality control of the different measurements and conclusions about the relevant reservoir heterogeneities.

The method is illustrated with a published case study [1] from a North Sea appraisal well, where a large compositional gradient has been observed with in-situ fluid measurements. An equation of state is elaborated from a sample and its PVT experimental results, and a compositional gradient is parametized using the DFA observations at the different depths. A polynomial fit is then given to the distributed pressure measurements and the obtained fluid density variations are compared to the fluid model ones.
Development and Application of the Discrete Gradient Method for Nonsmooth, Nonconvex Production Optimization
Authors: Mason Thomas L. , Bagirov Adil , Klunder Jan , van Berkel Jean
Published: December 2007

Production optimization such as optimal gas lift allocation to maximize oil production can be a non-smooth and non-convex optimization problem. In this paper, we describe the derivative free Discrete Gradient Method (DGM), with local, global and multi-start search options for non-convex and non-smooth gas lift production optimization. Results of numerical experiments with published petroleum industry test problems show that the four variants of DGM are capable algorithms. Although the DGM is best suited for non-smooth and non-convex optimization problems, it can also be used to locate reasonable solutions for smooth convex gas lift optimization problems.
Implementing Real-Time Production Optimisation in Shell E&P in Europe—Changing the Way We Work and Run Our Business
Authors: Gerrard Carl , Taylor Ian C. , Goh Keat-Choon , de Boer Frank
Published: December 2007

In recent years advances in computing and control technology have enabled real time monitoring, surveillance and control of reservoir, well and process; Within the Exploration and Production (E&P) industry these technologies are increasingly being applied throughout all phases of oil and gas field development and production

Arguably least attention has been given to asset operations, where the rewards are actually harvested. "Smart" technologies can significantly increase value here, provided they are properly focused and implemented, and integrated into the facilities daily operations.

The successful implementation of smart applications requires new ways of working and different skill sets of the operators and support engineers. This is a particular challenge in mature assets, where the operational style has become embedded through time.

Fieldware Production Universe, "PU" is an application developed within the Royal Dutch Shell Group, ("Shell"). Real time signals from individual wells e.g. tubing head pressure, are processed by numerical "data driven" models to estimate three phase flow from individual wells. Total production from the facility is reconciled to individual wells using these estimates.

These flow estimates change the traditional process of periodically routing a well's production to a test separator; individual well flow information is available all the time and tests are performed only when necessary to validate or update PU models. A more advanced version of PU, PU-RTO also allows the use of the models for real time production optimisation.

To get from research to a fully implemented and sustainably used product is a lengthy and sometimes arduous task. Across the industry most operators can think of at least one system that has been "rolled out" but not been fully adopted and has "died" before it delivered it's full value. Reasons for failure are many, but often centre around support and delivery of true benefit to end users.

This paper discusses Shell's experience with, PU, and it's application for real time production optimisation on the Nelson platform in the UK sector of the North Sea. The paper describes PU, how the applications were implemented, some of the challenges faced during the implementation and the changes that have had to be made, resulting in a PU becoming a sustainable part of the "way we do business".
Observations and Quantitative Analyses of Waterflood Patterns in a Chalk Reservoir Using Seismic Data, Halfdan Field, Danish North Sea
Authors: Dons Thomas , Jørgensen Ole , Gommesen Lars
Published: December 2007

Reservoir pressure maintenance and sweep of oil with water are the main objectives of the Halfdan field water flooding. The lower mobility of water compared to oil in the Halfdan field facilitates an effective sweep of oil but means that the water injectors require larger reservoir contact area in order to replace voidage. In Halfdan this has been the focus from first development and has been obtained by controlled formation of 10,000-15,000 ft long injection fractures by injection at fracturing conditions. Modelling has indicated that conditions for propagating injection fractures along the horizontal injectors were present, but until recently a field-wide verification of the expected uniform sweep has been pending seismic identification of the resulting water flood.

After five years of production, a seismic survey was acquired covering the developed area. Analysis of the seismic data has revealed a strong signature reflecting the water flooding of the reservoir. The seismic imaging of the sweep patterns is observed directly in the 3-D data without any 4-D processing and is of an outstanding quality even compared to what is normally seen in dedicated time lapse seismic studies. The seismic observations confirm the modelled behaviour of the Halfdan field water flood.

This paper presents examples of the seismic observations made and discusses these in a rock physics context including fluid substitution and pressure effects on acoustic impedance. It is demonstrated how the seismic results together with simple analytical models add to the quantitative description of injection under fracturing conditions by facilitating measures of fracture height, connectivity and extent.
Simulations for CO2 Injection Projects With Compositional Simulator
Authors: Hurter S. , Labregere D. , Berge J.
Published: December 2007

The need for CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geological environments that has been the case previously. Often when the storage reservoirs are saline aquifers, exploration data for proposed injection sites are extremely sparse. The special behaviour of CO2-water/brine systems (mutual solubility and chemical reactivity) adds complex processes, such as dry-out, salting-out, chemical reactions to the dynamic model. Simulation in these situations is one of few means of assessing an injection site and testing various scenarios. The accurate description of physics and chemistry in numerical simulation tools is fundamental for understanding processes, as well as designing appropriate injection or mitigation strategies.

We present simulations of CO2 injection into saline aquifers with a fully compositional code that has been expanded and enhanced to include specific phenomena, such as drying-out and salting-out. The examples illustrate the importance of pre-injection studies, as the wrong injection strategy may severely impact injectivity, putting the project in jeopardy.
Expatriate Health and Welfare: The Hidden Costs of Getting It Wrong
Authors: Cox R. , Jeremijenko A. , Doig K. M.
Published: December 2007

The increasing globalisation of the Oil and Gas industry has resulted in the relocation of large numbers of expatriate workers, often accompanied by dependant families, to geographically, environmentally and culturally unfamiliar locations. In many cases, expatriate assignments are seen by the employee as an affirmation of their value to the company, and/or expatriate choice by the employer is based on recognition of previous high performance. While medical issues are usually well handled, the cultural, social, and family adjustment dynamics of the assignment and impact on the employee and dependants are often considered secondary to the work objectives and deliverables, if they are considered at all.

This paper considers several factors critical to the success of an assignment from a health perspective, and the effect these will have on the family and working life. It argues that assignment selection should be an integrated process which examines the suitability of the entire relocating family for the proposed assignment and suggests processes and methodologies to increase the likelihood of completing a successful overseas posting. It lists factors to be considered by the corporate health professional both in terms of the transferee, and in terms of the host country infrastructure.
Planning for an Ageing Workforce
Authors: Shammas E.
Published: December 2007

CAVEAT

This paper was written and will be presented prior to the StatoilHydro merger on October 1st and describes "as is" at the time of writing. Some policies and measures described may change after the merger.
Health Management—A Contractor's Point of View
Authors: Mika F. , De Sanctis S. , Consentino M. , Nicosia V.
Published: December 2007

Differently from many other activities in O&G industry, particularly those referred to QHSE, Health management has not been standardised yet across the sector. Only lately major initiatives are being undertaken at industry associations’ levels (i.e. Oil and Gas Producers Association, IPIECA, Intnternational Marine Contractors Association) to line up the companies, Oil companies and contractors involved in the business, on this issue.

Saipem, as on of the biggest upstream contractors, is working world wide often facing situations where different Clients operating in the same country or area have similar but yet different health related requirements, or that the same Client operating in different countries in is having different approach towards health issues management. In this condition and circumstances it becomes extremely difficult, complicated, time and money consuming for the contractor to satisfy the Client and to manage the subcontractors.

That is why, approximately a decade ago, Saipem took the decision to establish its’ own health management standards that will represent the minimum bellow which, regardless contractual requirements, the company will not go and will make it recognisable among both Clients and competitors. The results of this ongoing and never-ending process are as follows.
Optimizing Field Development Concepts for Complex Offshore Production Systems
Authors: Cullick A. S. , Cude Ron , Tarman Mehmet
Published: December 2007

An analysis framework is presented that unifies the subsurface and surface disciplines involved with developing offshore projects. The method treats the complex interactions between surface and subsurface aspects of a production problem as a single system. The framework optimizes and assesses the risks and uncertainties associated with facility concept selection and sizing, with consideration of relevant subsurface and surface uncertainties and risks.

There is considerable uncertainty in the subsurface; this manifests itself in terms of a range of reservoir deliverability and reserves. In many projects, this subsurface uncertainty is not properly conveyed to the surface teams who are charged with selecting the best facilities design for the project. Often, the result of this disconnect yield suboptimal facilities followed by expensive retrofitting. The framework presented automates optimization of the concept design with rigorous reservoir and facilities modeling.

Two case studies are presented, both with multiple reservoirs connected through a common pipeline network. The first case is a typical deepwater U.S. Gulf of Mexico project. The second case is more typical of a medium water depth development in northern Europe. Full scenario analyses of multiple production platform alternatives and number of wells optimization is evaluated within a context of reservoir volumetric and drive mechanism uncertainties.

This framework accomplishes the following: it links physics-based reservoir deliverability and expert-system based facilities screening tools with the economics analysis in a unified workflow, and it applies advanced non-linear optimization to deliver better decisions regarding facilities selection and sizing.
WindStore—Large-Scale Energy Storage Offshore
Authors: Boehme Thomas , Cammaert Gus , McCurry John , Judt Michael , Deckers Marie
Published: December 2007

WindStore is a research project focussed on Compressed Air Energy Storage (CAES) in the UK and Ireland, both onshore and offshore. CAES uses low-cost electricity at off-peak times or from renewable projects to compress air into a subsurface void or reservoir for storage. At peak times or when required, the compressed air and additional fuel drive a turbine to generate electricity.

The two existing CAES projects in Germany and the USA are located onshore and use solution-mined salt cavities as storage reservoirs. Offshore the storage options include voids such as steel vessels and salt structures, and porous media such as saline aquifers and depleted gas reservoirs. There are two major applications for CAES offshore. (1) Small projects of some 10 MW capacity could be operated on platforms to store the variable output from nearby wind, wave or tidal current generators and make offshore installations more energy-independent. The fuel usage of CAES is significantly reduced compared to single cycle gas turbines. (2) Large offshore wind farms are planned, for instance, in the southern North Sea where depleted gas reservoirs exist. A large-scale CAES plant of several hundred megawatt capacity could be built on a disused platform using the depleted reservoir for air storage.

This paper describes the applications and likely economics of small and large CAES plants located offshore with focus on the North Sea. It is outlined how CAES can allow a more economic use of high-voltage DC transmission links in future offshore networks.
Estimation of Fracture Spacing in Naturally Fractured Carbonate Reservoirs
Authors: Pérez-Rosales C. , Serrano E. , Moctezuma A. , Luna E.
Published: December 2007

Fracture spacing is an important concept for characterizing flow properties of naturally fractured reservoirs, since the main function of fractures that separate matrix blocks is transporting fluids through long distances; however, the estimation of fracture spacing presents some difficulties mainly due to the fact that fractures occur at different scales, going from microfractures in thin sections and minifractures in cores, up to macrofractures in geological outcrops. The scale of interest in this work is that used in reservoir simulation, which is of the order of feet or meters.

This article is based on the ideas developed in a previous paper, where a procedure to locate fractures is presented. That procedure, which makes use of resistivity data obtained through well logging, visualizes the fractures as highly conducting channels within a low conductivity medium (the rock matrix). By using a special way of data processing, it is possible to filter out data that are not associated with fractures, keeping only those data related to fractures. In this way, fracture spacing can easily be estimated. However, that procedure exhibits some uncertainties which must be overcome to make it a more reliable one.

In this work, a study is made to search for an improved procedure to estimate fracture spacing. For this purpose, fractures are considered at two scales: local scale which includes micro- and minifractures present in matrix blocks, and at reservoir scale which refers to fractures separating matrix blocks. These latter fractures, called principal fractures, constitute the main fracture network, and are the subject matter of this work.

Conductivity studies reveal that local scale fractures have a frequency distribution quite different from that of principal fractures. As it will be seen below, this fact facilitates establishing a procedure for estimating fracture spacing without uncertainties.

To make the ideas clear, an application to a carbonate reservoir is presented. The results obtained show that the improved procedure is a simple, reliable, and practical tool for establishing the distribution of fractures along a well, from which fracture spacing can be inferred.
A Cost-Effective and Safe Method for Transportation and Installation of Subsea Structures—The Pencil Buoy Method
Authors: Mork Henrik , Lunde Johannes
Published: December 2007

The patented Pencil Buoy Method has been developed for transportation and installation of subsea structures. Based on standard equipment onboard ordinary construction vessels in combination with tailor-made special equipment, a cost-effective method is developed.

The special equipment consists of a slender pencil shaped buoy, a passive heave compensator and associated rigging. The system allows for installation of various subsea structures such as Templates, Suction anchors and Manifolds, as well as for removal of subsea items.

The submerged cargo capacity of the system during installation ranges from about 60 tonnes to 370 tonnes including a recent enhancement including a new passive heave compensator. The capacity during subsea transportation ranges from about 150 tonnes to 370 tonnes. During transportation the system is designed to sustain a typical unrestricted summer storm, while during installation the criteria is equal or better than for typical heavy lift vessels.

This paper will present the main principles of the Pencil Buoy Method. The paper will mainly focus on the design aspects related to landing of structures on seabed including installing a structure into another, and will present data from a recent such operation.
Indigenous Peoples and Oil Companies: Respect the Differences
Authors: Bergman Michaela S. , Guldin Gregory Eliyu , Dennis Aaron K.
Published: December 2007

The search for oil is bringing petroleum engineers increasingly face to face with the world’s Indigenous Peoples. Simultaneously, Indigenous Peoples, conscious of the international value of resources such as oil, are becoming increasingly better organized, rights-savvy, and globally connected.

Acting in a socially responsible manner is important for the petroleum industry both from the perspective of ethics as well as from the perspective of reputation. This paper describes how Indigenous Peoples can be engaged on an equitable basis, giving them full respect, identifying how best to mitigate any potential adverse impacts and identify in a participatory manner how they can be enabled to benefit from any Project.

Work experience among Indigenous Peoples in Russia and throughout Asia leads the authors to identify the importance of ‘respect’ for Indigenous Peoples’ values and cultures. This can avoid multi-million dollar delays and maintain a company’s reputation.

Focusing on the Sakhalin II oil and LNG project in Russia’s Far East, the paper advises companies to create a special indigenous space within their corporate hierarchy; with Human Resources, Finance and External Affairs having to adapt their normal procedures and styles. By seemingly "giving away the store," but actually "giving face" to often marginalized economic and social actors, those in charge of the Indigenous Peoples strategy at Sakhalin Energy countermanded corporate logic while embracing a philosophy of cultural and ethnic partnership.

The paper describes what is considered to be best practice (in terms of international and national laws and policies). It then discusses how various contemporary projects in Far Eastern Russia and Indonesia, inter alia, attain these standards. Finally we shall propose a set of standards and best practices that should be adopted by professionals working in the Petroleum industry that take into account the concerns and priorities of Indigenous Peoples.
Multiphase Measurements and Sampling—Operating Experience
Authors: Joshi N. B. , Joshi B. H.
Published: December 2007

The multiphase meters are used both topside and subsea to measure the flowing conditions; pressure, temperature, volume flow rates of oil, gas and water. This real-time information is useful to several disciplines such as reservoir monitoring, production optimization, allocation and well testing. The new generation multiphase meters have been installed and operating for more than five years now. They are becoming more prevalent in the industry because of advances in their reliability and their utility to provide significant additional value. This paper describes the operational experience of multiphase meters using single and dual energy gamma-ray system. It discusses observed accuracies and maintenance processes. It will also discuss multiphase sampling; it's comparison with conventional sampling and also basic fluid property measurements. Illustrations of value addition with the use of multiphase meters in fluid measurement and allocation amongst stakeholders will be presented. It will show that with the use of multiphase meters, the allocation of produced fluids can be improved significantly and it's value addition can be easily higher than $5 MM per year. It will be presented that the capital cost as well as operational cost of the multiphase meter can easily be recovered by this value addition. In addition, the following topics and results will be presented (a) General operational and maintenance practices followed in the deepwater Gulf of Mexico (GoM), (b) Multiphase fluid sampling methodology and comparison with conventional sampling on fluid compositions.

This paper is intended to present hand-on experience of operating multiphase meters and discuss the related issues, challenges and advantages.
A Well Productivity Program in Pemex E&P Increases Oil Production in Short Time and at Low Cost
Authors: Arévalo-Villagrán J. A. , Gutiérrez-Acosta T.
Published: December 2007

In the last 18 months, within the five Exploitation Integrated Assets in the South Region of PEMEX E&P, a well management program coupled with multidisciplinary teams has been implemented obtaining 24.5 MMSTB of oil and 40.1 Bscf of gas from workover of 372 wells that were shut in or had production problems. With the implementation and surveillance of this program in the field was possible for these assets to increase the production of oil to over 136 MSTB/D and gas to over 257 MMscf/D. These increases in production has made possible to maintain a production near to 500,000 STB/D of oil and 1,360 MMscf/D of gas in this region, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit-to-investment ratio of 16 has been obtained. Additional hydrocarbon production greater than 111 MSTB/D of oil and 196 MMscf/D of gas have been identified from 353 wells. The successful implementation of this program was based on the application of selected technologies that contributed to the increase of well productivity from the selected fields. This paper presents the applied methodology and the current results obtained from this well management program to optimize the recovery of hydrocarbons of the identified opportunities within these assets units with minimum investments. In addition to the value added of production increase through this well management approach, the following benefits were obtained: learning and applying the team work approach of well management, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer of diverse technologies, methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate reservoirs studies.
Temporary Program of Multiphase Flow Measurement to Provide Well Performance Data: Study Cases
Authors: Arévalo-Villagrán J. A. , Gutiérrez-Acosta T. , Serrano-Lozano J. R. , López-Ramírez S. , Ferreira H.
Published: December 2007

The South Region of Pemex Exploración & Producción (PEMEX E&P) is running a key development plan to improve the reservoir management, well productivity and ultimate recovery of all fields in the region. A fundamental part of this project is gathering reliable well production data on real time and on regular basics. The South Region of PEMEX E&P in cooperation with the technical team of PEMEX E&P performed a full study of available technologies in well testing to select a system that meet the needs of the region while simplifying the field logistic and minimizing environmental impact. PEMEX E&P selected the use of multiphase flow meters (MPFM). The program scope includes 8,064 measurements at well heads and collection manifolds during three years. The preparation and use of this MPFM program for multi-rate well tests was carried out with variable gas-liquid ratio flowstream and systems capable to measure all types of flow regimes in fields producing from heavy oil to gas condensates. This paper describes the lessons learned about the practical reliability, accuracy, and operability of the MPFM meters. The paper illustrates with field results the benefits of implementing the multiphase metering in the region. MPFM meters have proved to be a reliable system to measure well productivity.
Reservoir Characterization from Material Balance Results Analysis
Authors: El Ela M. Abu
Published: December 2007

Oil production in Egypt is based on the development of mature fields with highly complex geological and reservoir characteristics; therefore, a great amount of creativity is required to operate these oil fields. One of the main elements for development of mature fields is to estimate the reserves and determine the amount and location of the remaining oil.

Material balance equations have been used in petroleum engineering for many years to estimate the original hydrocarbon in place. This paper documents the ability of using the analysis of the material balance results in the reservoir characterization and determination of the remaining oil location. The applicability of this work is confirmed by actual field case study (Shukheir Bay Field) in Offshore Shukheir Oil Company (an international joint venture company in Egypt). Such study is an original contribution to the knowledge of the material balance results analysis.
Asset Team Work Methodology for Increasing Recovery Factor in Declined Reservoirs: A History Case in Southwestern Venezuela
Authors: Angel F. J. , Askoul Y. E.
Published: December 2007

Reservoirs declination in Apure State, Southwestern Venezuela, demands a huge technical effort in reservoir modeling when finding drilling opportunities to increase recovery factor and maintain oil production at attractive economical levels. One of these reservoirs, Escandalosa Inferior of La Victoria Oilfield was discovered by LVT-18 in 1991 with 38 MMSTB of STOOIP and in 1998, the last of its four producing wells was closed, reaching a recovery factor of 14%.

An Asset Team revised and integrated geophysical, geological, petrophysical and production data to update Esc-Inf static model in 2005. No robust sedimentological model could be built because of cores absence; however, a facies and later a property distribution was designed with the help of well logs, regional knowledge and geostatistics.

The resulting static model led to visualize the opportunity to drill a horizontal well in the highest attic of the structure to reactivate the reservoir. STOOIP calculation for this new model yielded a value of 13 MMSTB with 7.8 MMSTB of recoverable reserves and 2.5 MMSTB of remaining reserves, which could be extracted by the new well and finally obtain a recovery factor of about 60%. The dynamic model showed a reaccommodation of fluids due to its 5 years of closure, and certified the current presence of oil in the attic where the well was previously visualized. The prediction made by the simulator for a 5 years scenario, with a production of 650 STBD, highlighted the economical feasibility of drilling this well.

Nowadays, the successful well LVT-46H is still active with 2 MSTBD and has accumulated 0.245 MMSTB, since its completion in 2006. These results validate the methodology presented in this work where data integration, the use of geostatistics and reservoir simulation are the main key for reactivating declined reservoirs and maintaining oil production.
Optimizing Hydrocarbon Pay Estimates Using the Magnetic Resonance Imaging Logs in Development Wells of El Furrial Field, East Venezuela
Authors: Fam Maged , August Howard , Maestre Milagro , Guevara Edgar , Mendez Milton , Rondon Luis
Published: December 2007

Optimizing production in mature fields depends greatly on proper reservoir characterization. After a certain period of production, a reservoir may exhibit changes in its properties because of changes in formation water salinity arising from water injection, left-behind residual oil in the rock, and changes in pressure regime. These factors, combined with complexities in the original reservoirs properties, such as rapid variations in permeability and oil viscosity, strongly affect the degree of uncertainty in evaluating and predicting productive zones when using only conventional logging methods.

These variations affect the responses of most conventional logs. Consequently, traditional log analysis models may fail to provide realistic evaluation results and may not achieve appropriate production forecasts. Common examples of such failures have been recognized when producing high water content from a zone believed to be hydrocarbon or when perforating an interval that does not produce.

New logging technologies, such as magnetic resonance imaging (MRI), demonstrate promising formation evaluation results in mature fields. The MRI technology helps to properly distinguish candidate production zones and provide key in-situ reservoir properties, including hydrocarbon type, reservoir quality in terms of permeability and porosity, and barrier zones. The ability of MRI to determine oil viscosity influences the selection and elimination of zones to be produced based on its fluids mobilities. Thus, MRI serves well in the selection of hydrocarbon producing intervals.

This paper discusses the effectiveness of applying the MRI technology in characterizing the reservoir fluid properties in the El Furrial field, East Venezuela. It also highlights the value of this technology in minimizing the cost of mis-identified zones for production or testing by identifying best candidate intervals. Verification of the MRI results with actual production testing and/or formation pressure measurements will be demonstrated in the article.
A Breakthrough Technology for Maximizing Water Injectivity and Asset Integrity
Authors: Horsup David I.
Published: December 2007

The importance of maintaining oil production has never been more critical than it is today. For many fields utilizing water injection to maintain reservoir pressure, the injection rate can decline over time due to the blocking of pore throats in the near well bore region. Remediation can be expensive, incur lost production and expose operations personnel to hazardous chemicals. Additionally, the material which blocks the pore throats, also deposits within the injection infrastructure resulting in significant asset integrity challenges. This paper describes a new technology that has been developed that can significantly increase water injectivity, potentially prevent well interventions, maximize production and preserve the integrity of the injection infrastructure.

Through extensive research, a new, patented multifunctional product has been developed that, when injected into the water injection system, cleans away deposits, prevents new deposits from forming and provides corrosion inhibition to the injection infrastructure. This paper discusses the fundamental research that was performed to develop this new technology, and the results of several field applications.
Upgrading Heavy and Extraheavy Crude Oil with Ionic Liquid
Authors: Nares H. R. , Schacht-Hernández P. , Ramírez-Garnica M. A. , Cabrera-Reyes M. C.
Published: December 2007

In this paper the effects of some ionic liquids elaborated with iron and molybdenum used to upgrade the properties of a heavy crude oil are discussed. The underlying objective is to increase the mobility of the oil in the reservoir reducing viscosity and improving the oil quality (e.g. diminishing the asphaltene and sulfur contents and increasing its °API gravity), using ionic liquids based on iron (10 wt%) and molybdenum (2 wt%) compounds, in a liquid phase homogeneously mixed with heavy crude oil in a batch reactor of 500 ml, at 673 K during 4 hours. The API gravity of a offshore heavy crude oil from the Gulf of Mexico increased from 12.5 until 20, kinematics viscosity decreased from 15,416 to 136.63 cSt at 288.75 K, asphaltene content was reduced from 28.65 to 10.82 wt%, while the sulfur was removed from 5.14 to 2.16%; and the distillation obtained by Simulated Distillation was increased from 48 to 71.2 vol%.

Content of aromatics and saturated compounds were increased through the conversion of asphaltenes and resins, which contents decreased from 16.81 to 13.8 wt% and from 28.85 to 10.82 wt% respectively. Finally, the content of total nitrogen was reduced from 780 to 633 ppm in weight which represents a reduction approximately of 20 wt%.

In this work upgrading of a heavy crude oil was obtained through the application of the thermal and catalytic hydrocracking with an ionic liquid. This ionic liquid could be applied into the reservoir combined with in-situ combustion process using unconventional wells in order to improve the recovery of heavy crude oil, producing an oil improved in-situ with lower viscosity, being easier their exploitation, increasing the productivity index in wells, and saving costs of transportation and refining at surface.
Gravity Drainage and Oil Reinfiltration Modeling in Naturally Fractured Reservoir Simulation
Authors: Ladron de Guevara Torres J. Ernesto , Rodriguez-de la Garza Fernando , Galindo-Nava Agustin
Published: December 2007

The gravity drainage and oil reinfiltration phenomena that occur in the gas cap zone of naturally fractured reservoirs are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results.

Gravity drainage and oil reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudo functions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in fractured reservoir simulation.

The modified dual-porosity equations were implemented in SIMPUMA-FRAC,1,18 and solutions were verified, with good results, against those obtained from the equivalent single porosity refined grid simulations. Same simulations, considering gravity drainage and oil reinfiltration phenomena, were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC.