bluuebunny/crossref_metadata_2025 huggingface dataset:
Exploration Performance of Northwest Europe
Authors: Thomas Rhodri
Published: December 2007

Despite having been explored for over 40 years, 3.6 billion barrels of oil equivalent have been discovered in the last five years in north west Europe. On average US$2.4 was spent on exploration for each barrel found in the offshore region. This unit finding cost is comparable to that in the deepwater Gulf of Mexico over the same period, one of the global hotspots for exploration.

The largest volumes of reserves were found in Mid Norway where 1 billion barrels of oil equivalent has been discovered in the last five years. Despite this apparent success, only one of the 11 fields found in the sector is currently expected to be developed before 2012. Gas export capacity from the region remains an issue.

The North Sea itself attracted 75% of the exploration expenditure over the last five years and 2 bn boe of reserves were discovered. Finding costs ranged between US$2.5/boe for the Norwegian North Sea to US$3.5/boe for the UK Southern Gas Basin. Although significantly higher than the US$1.5/boe unit finding costs in Mid Norway, over 50% of these reserves are expected to be developed within five years.

Industry cost inflation and lower discovery sizes have resulted in the finding costs of the last five years doubling from the previous five. However, with a record number of exploration licences being held, US$2.5 billion being spent on exploration last year and substantial finds still being made, there will be many more exploration success stories to come in the region.
Identification of Bypassed Oil For Development In Mature Water-Drive Reservoirs
Authors: Choon Tan Teck
Published: December 2007

An integrated bypassed oil identification methodology was developed and successfully applied to identify and quantify the presence of bypassed oil opportunities in mature water-drive reservoirs in an offshore field in Malaysia.

A 3D reservoir static model was first built as part of the geological review. Reservoir performance review was carried out in conjunction with material balance and average fluid contact movement calculations to understand the drive mechanism and to estimate the current fluid contacts. Performance matching was carried out with an analytical 1D 2-phase Buckley-Leverett model to assess the potential scope of recovery with additional development. Together with dynamic production data animation on 2D maps, a good view of the production-drainage–water influx pattern progression with time was obtained enabling a first pass identification of bypassed oil opportunities. Well performance data were then used to estimate the likely local fluid contacts in the area or sand layers of the completions. The inferred fluid contacts defining the identified bypassed oil were further calibrated with fluid contacts seen in recent wells and crosschecked with 3D seismic features where possible. Bypassed oil-in-place volumes were calculated using the saturation-initialized 3D static model.

The methodology had been successfully applied in reviewing 14 highly matured water-drive oil reservoirs with small to large initial gas caps. The emphasis of this paper is to describe how it can be applied to locate bypassed oil. Although the field concerned had undergone 8 previous phases of development campaigns, application of the approach had led to identification of a substantial number of potential recovery opportunities for further development consideration.

The approach can be applied for systematic identification of bypassed oil opportunities in water-drive reservoirs where detailed dynamic simulation is not justified. It furnishes a comparatively quick fit-for-purpose approach to identify further development opportunities and furnish input for the planning of detail dynamic simulation where the remaining opportunities scope is large.
Subsea Raw Seawater Injection System—A World First
Authors: Rogerson Neil , Laing Tony J. A.
Published: December 2007

Canadian Natural Resources International (CNR) recognises, for the Columba E development, the benefits of using state of the art subsea technology to enhance production by means of optimising raw seawater.

The application of raw sea water injection offers an alternative to conventional topside water injection, minimising many recognised perceived topside challenges; such as topside weight and space constraints, availability of purified water, pipeline transportation from the platform to the satellite and the associated infrastructure installation and commissioning.

Subsea raw sea water injection has been developed over the last decade by Framo Engineering using the proven methods within their subsea pumping technology. Whilst a new application, subsea pumping technology is in operation across a number of fields world-wide with proven reliability and runtimes in excess of 700,000 hours. Extensive testing of key elements of the system further enhanced the confidence in the robustness and reliability of the complete system package. The system package included a Pump Control Module topside, umbilical and the Framo Dual Pump Station. This system approach ensured that there were minimal external interfaces and the technology resided as the responsibility on a single supplier.

This built confidence for CNR to commit to the world's first raw seawater injection system and that such a project could be delivered in an appropriate manner.

Subsea raw seawater injection offered a viable solution, adding significant injection capacity, with a significantly reduced impact to existing production facilities. In addition, the possibility to recover and re-deploy the system later in field life, either on the same development or in another area adjacent to the host adds further to the attraction to the system.
Practical Use of New Microbiology Tools in Oil Production
Authors: Skovhus Torben Lund , Højris Bo , Saunders Aaron Marc , Agerbæk Mikkel , Larsen Jan
Published: December 2007

Culture-based methods of traditional microbiology applied to the microbiological processes involved in souring of oil fields and microbiologically influenced corrosion (MIC) pose a threat of yielding inadequate and contradictory results. Any cultivation step will almost certainly alter the population characteristics and thus also the results on which any evaluation will be based. The need for in situ cultivation-independent methods has over the past ten years facilitated the development of several analytical methods for determination of bacterial identity, quantity, and to some extent function, applied directly to samples of the native population. This development has so far been fairly limited regarding practical application and it has only recently been transferred to the offshore industry.

In this paper, we demonstrate the features and benefits of applying these novel techniques to two situations often encountered in offshore oil production in the North Sea.

The new microbiology tools are based on the detection of genetic material in bacteria. The methods include direct count of specific groups of bacteria with microscopy (e.g. FISH). Additional methods (e.g. qPCR and DGGE) are based on direct extraction of cell genetic material (DNA/RNA). The paper will briefly describe these novel molecular techniques.

By documenting bacterial population shifts related to water breakthrough in a nitrate treated reservoir, we showed that key bacterial populations can be identified and thereby lead to the creation of new and strengthened surveillance strategies on souring bacteria in these systems.

Also, we have shown that by applying these novel techniques to aggressive corrosion attacks, especially under deposit corrosion, molecular techniques are a powerful tool in identifying the most probable corrosion process.

These examples will be described and related to the offshore operation. Special focus will be given to the use of the new and improved microbiological data in relation to designing and testing remedial actions towards oil field souring and MIC.
The Use of Point Cloud Data on Brownfield Projects
Authors: Fairweather Colin K.
Published: December 2007

The first challenge on every brownfield project is to identify the current status of the plant. Drawings and engineering data for the plant are often out of date or unavailable, and many of the older plants have no 3D CAD data available. Various survey techniques have been used over the years, but they tended to be man-hour intensive, produced unreliable data, and were slow in making information available to the design team. Laser scanners delivering point cloud data (PCD) avoid these problems, and, with the ability to reference PCD in the 3D CAD world, make producing a clash-free design in brownfield projects much easier. After testing the Laser Model Interface (LMI) prototype from AVEVA in July 2005, AMEC has now used the LMI on projects offshore around the regions, bringing a new dimension to PDMS brownfield projects in the oil and gas industry. The use of PCD within the PDMS environment has given AMEC the opportunity to reduce project costs, shorten schedules, and improve safety.
Engineering Management Skills: The Present and the Future for Technical Graduates
Authors: Dickson B. R. , Grant C. D.
Published: December 2007

Norman Fortenberry, director of the U.S. National Academy of Engineering's Center for the Advancement of Scholarship on Engineering Education, said that the move toward interdisciplinary engineering curricula is definitely a trend. "It is in response to an increasing consensus within the engineering education community," he said, "but more importantly in the employer community." [1] How does this fit with one of the most relevant degrees to the Oil & Gas exploration and Production Industry-Chemical Engineering?

In reviewing the Personal Skills in Chemical Engineering Graduates, B R Dickson and C D Grant from the University of Strathclyde, Department of Chemical and Process Engineering, Glasgow, Scotland-suggest that the development of skills within degree programmes can meet the needs of employers, yet there is still further work to be done that a relevant post graduate qualification could provide.

In this paper, transferable' (or ‘personal’) skills are defined as the five key skills of: communications; team-working; problem solving; numeracy and IT skills; self-learning. It shows, with some specific examples, that there are ample and varied opportunities to develop these skills within most engineering programmes. The paper then attempts to identify whether the skills possessed by new chemical engineering graduates match the requirements of employers, using two recent comprehensive surveys, including a major survey of chemical engineering graduates with a few years in employment. The paper concludes with some views for further "on the job" training options that could be made available to the technical mangers of the future.
Transient pressure analysis of 4D reservoir system response from permanent down hole gauges (PDG) for reservoir monitoring, testing and management
Authors: Zheng Shi-Yi , Li X. G.
Published: December 2007

One of the key objectives doing well testing is to derive effective reservoir properties, such as permeability, to provide input for reservoir simulation. Traditional approach in well test analysis is first, to separate transient pressure draw down and build ups' due to constant flowing rate, then analyze them by forcing a pre-selected model to derive effective reservoir permeability through an inversion process. However, the results obtained this way are not really dynamic or at most is "pseudo-dynamic", because these are based on the fact that a continuous signal was broken into discontinuous signals. Some information (more than a changed permeability value) of the reservoir system response may already lose, while uncertainties were increased or multiplied in the process of data evaluation and analysis.

This paper presents a new approach, which will allow for continuous reservoir system response analysis and interpretation. Therefore the information derived from such analysis can reflect the real time, dynamic changes of the reservoir. This has been proved more powerful in analyzing transient pressure, particularly for that from permanent down hole gauges (PDG).

Numerical well testing procedures, assisted by neural network method, were used to analyze the data from simulated and field cases in a continuous, systematic fashion. First, the flowing rate history was recovered from the measured transient pressure. Transient pressure histories are then reproduced through simulations of both well test forward model and neural network black box model. A match between measured pressure response (PDG data) and re-produced transient pressure histories will then be made, to achieve the ultimate goal of well testing – real time reservoir monitoring, model calibration and reservoir management. This final matching process was named "guided (by neural network model) history matching".
Removing the Effect of Reservoir Fluids on Porosity Estimated from Seismic Data. A Study on Aboozar Oilfield, North-West Persian Gulf
Authors: Asgharzadeh M.
Published: December 2007

The problem addressed here is based on a study of Ghar reservoir formation in Aboozar oil field. During this study data from 10 vertical wells together with a 3D (3 Dimentional) seismic dataset have been used to investigate the effect of reservoir fluids on porosity estimation.

Due to the existence of a low density HC (Hydrocarbon) in the reservoir, propagation velocity of seismic wave and density of the reservoir is significantly lowered. This will introduce two main problems. First is time to depth conversion of the bended reflectors below the reservoir. The second problem which is the topic of this study is encountered when characterizing reservoir porosity.

Common believe is that the more porosity a rock contains the less AI (Acoustic Impedance) is derived from inversion. As a result more often porosity and AI is cross plotted at the well locations and some times good correlation is achieved. This happens where rock skeleton is very stiff. Where rock framework is loose, estimated AI is strongly affected by the presence of hydrocarbons. In this study, important observation is at the time one applies the linear regression to inversion data. The resulting porosity volume is severely biased by low density fluids inside the reservoir. Above pulled-down OWC (Oil- Water Contact) signature, very high values of porosity are estimated which are erroneous. If we bring more seismic attributes into the analysis and use neural network methods to find the relationship, surprisingly erroneous high porosity zone above OWC is removed; an homogenous porous reservoir rock appears.

As a conclusion, care should be taken when characterizing loose sands containing low density HC. Low AI should not be interpreted as high porosity by use of simple cross plotting. Instead, application of more seismic attributes will remove the effect of hydrocarbon on porosity estimation and results more correlaion between estimated and measured porosity.
Fluvial Reservoir Architecture Modeling and Remaining Oil Analysis
Authors: Jiang Xiangyun , Wu Shenghe , Yu Diyun
Published: December 2007

Most of the mature oil fields in east China are in a stage of high water cut. For these oil fields, the reservoir characterization and remaining oil study need fine scale geological models. A study of reservoir architecture can provide such a fine model. In this paper, we focus on the architecture modeling of fluvial reservoir. Fluvial architecture contains hierarchical bounding surface and architecture elements. This architecture model provides information to analyze the reservoir heterogeneity caused by hierarchical bounding surfaces. Previous architecture studies were conducted on outcrop and modern river deposits. We use the 7th block of Gudong oil field in China as an example to analyze the subsurface reservoir architecture and distribution of remaining oil.

Gudong oil field has been exploited for 30 years. A total of 1070 wells have been drilled and the well space is 150mx150m. Data are abundant and includes core data, horizontal wells, logging data, production data and surveillance data, all of which are used for the reservoir architecture study.

We use the method of "fitting geological model" for the architecture study. Using results of outcrop and modern river deposit studies and paloe-environment analysis, we build the geological patterns of meandering and braided rivers. Based on our analysis, the geological pattern of internal point bar has the following characteristics: (1) parallel-inclined lateral accretion intercalation; (2) 200m width of single lateral accretion body; (3) 3~5 degree dig angle of lateral accretion surface. Our study also shows that the geological pattern of the internal mid-channel bar, which is confirmed by the production information and pair wells data, is asymmetrical intercalation and 2~5 degree dip angle of intercalation surface. Guided by geological patterns, we establish the internal architecture models of Ng522 layer and Ng64 layer in this study area.

Using the internal point bar and mid-channel bar models, we analyze remaining oil and establish different remaining oil distribution patterns. Our analysis shows that the matching relationship between intercalations and perforated intervals is the main factor that influences remaining oil distribution of a sand body. This provides a new way to find remaining oil in a mature oil field.
Predicting Accelerating Subsidence Above The Highly Compacting Luconia Reservoirs, Offshore Sarawak Malaysia
Authors: Dudley J. W. , van der Linden A. J. , Mah K. G.
Published: December 2007

Sarawak Shell Bhd has a number of offshore gas fields that produce from the Luconia carbonate formation, which can exhibit high compressibility pore collapse deformation. Recent accelerated subsidence has been observed at several of these fields, which extrapolates to final subsidence values well above previous estimates. This paper describes a geomechanical study involving core work to determine if the Luconia formation compressibility is sensitive to brine flow from the rising aquifer, and a 3D geomechanical finite element model developed to predict future subsidence and lateral movements for the F23 platform.

Compaction tests were performed on Luconia core from three different gas fields. Tests on twin plugs were conducted - one plug undergoing a standard uniaxial constant-lateral-strain compaction test, while it's twin has several pore volumes of simulated formation brine flowed through it (at virgin in-situ stress conditions) prior to the compaction loading. Four sets of compaction tests on twin plugs were completed. The higher porosity samples showed characteristic pore collapse behavior, consistent with previous measurements on Luconia mouldic limestone core. No sensitivity to brine flow was observed. In situ compaction logs in the field also do not show increased compressibility in sections flooded by the rising gas-water contact. The geomechanical model uses a relatively simple structural model comprised of two overburden, the Luconia carbonate, and one underburden formations. A non-linear deformation model for the Luconia formation captures the accelerating pore collapse response observed in the core and in-situ compaction measurements. The model is calibrated to GPS-measured platform subsidence, and is consistent with measured core and field compaction properties. The results predict that platform subsidence rates with depletion would level off, with a maximum subsidence of 18.5 +/− 1 feet at an abandonment pressure of 300 psi. Platform subsidence in the two years following the work continues to follow the predicted values.

This work illustrates the importance of integrated geomechanical core testing, field monitoring measurements and modeling to accurately predict compaction and subsidence effects in highly compacting environments.
Saltire Field: Flying The Flag for Mature Field Redevelopment
Authors: Ballantyne Grant , Daini Olugbenga , Mills Rob , Morrison Kerr , Slater Julian
Published: December 2007

Interest in the operation of mature fields in the North Sea has significantly increased due to the quantity of reserves still locked away in these fields. The wave of change in operatorship from the major oil companies to independent oil companies combined with the current high oil price has rejuvenated interest in recovering more oil from mature fields.

This paper shows how good oil field practice can enhance the production from a mature platform. A three pronged approach of facilities reinstatement, a concerted wellwork campaign coupled with good reservoir management has resulted in increased oil production from the Saltire platform.

The wellwork campaign consisted of low capital well interventions such as the identification and preferential isolation of high water cut zones, gas lift optimisation and strategic optimisation of available water injection to enhance sweep efficiency.

The incremental production achieved on Saltire proves that minor well interventions, often viewed in isolation as non material, when planned and executed as a concerted campaign can result in a significant increase in oil production and extend life of field by many years.
Viscoelastic System as an Alternative to UBD for Drilling a Severely Fractured Limestone Reservoir
Authors: Blanco J. , Ocando D. , Lanza A. , Rendon R. , Rodríguez F. , Caligiore A. , Acosta J. , Carrero N.
Published: December 2007

This document presents the drilling operations protocol designed to reach a depleted limestone carbonate reservoir, located in the Borburata Field in Southern Venezuela(Fig 1), with the use of a new viscoelastic fluid developed by PDVSA Intevep. This limestone reservoir has a very low pore pressure (about 3.0 ppg equivalent density) and it is characterized by vugular porosity and micro-fractures. Previously, when drilled with conventional fluid systems, severe fluid losses occurred; therefore, the best available alternative was Under Balanced Drilling (UBD)1. However, UBD service was a heavy burden on the drilling costs and represented a more complex and risky operation than using a conventional drilling fluid system. In order to have an alternative to UBD, a water-base viscoelastic fluid system was designed to avoid fluid losses in an adverse environment of very high overbalance (about 3,000 psi), very high temperature (about 300°F) and variable pore size due to the presence of vugs and microfractures. Viscoelastic drilling fluid systems have been used because they have excellent fluid loss control properties. However, for this application, the commercial viscoelastic fluids available did not comply with the extreme conditions found in this reservoir. A new formulation specifically designed for these severe conditions was proposed, tested in the laboratory, and evaluated in the field. It resulted in the elimination of fluid losses and allowed the access to this complex reservoir without requiring the UBD service. This result represents significant savings when compared with previous wells drilled in the same reservoir.
Downhole Fluid Analysis and Sampling Establishes Compositional Gradient in a Deep Water Gas-Condensate Reservoir
Authors: Seth G. , Zope D. , Deka B. , Ghosh B. , Joshi S. , Kundu D.
Published: December 2007

The paper demonstrates how to establish a compositional gradient in Dhirubhai-26 (MA) retrograde gas-condensate reservoir situated in a deep water territory of KG Basin, India, with the help of real-time Downhole Fluid Analysis (DFA).The reservoir consisted of an oil rim sandwiched by a large gas cap and bottom water. Very low contamination samples were captured downhole, using a Wireline Formation Tester (WFT), in Single Phase PVT bottles. This success was achieved through the combined use of DFA results, PVT data and a tuned Equation of State (EoS).

PR Peneloux (T) EoS was tuned to the PVT data and used to populate the PVT properties of the reservoir. The resultant fluid composition versus depth was correlated to the DFA results to verify the EoS simulated compositional gradation. Subsequently a reliable GOC was established using the combined result of WFT pretest derived gradients, PVT property derived gradients and saturation pressure curves. Establishing the existence or non-existence of compositional gradient and reservoir compartmentalization in this reservoir were key prerequisites for the formulation of an optimum Field Development Plan (FDP) and estimation of the associated financial implications.

The methodology adopted in this paper is applicable to any gas-condensate reservoir that exhibits similar PVT properties. It would help to evaluate a more accurate in-place reserve estimate and reduce the reservoir risk, which in turn would lead to an optimum FDP (that would maximize the oil recovery and returns).

The paper highlights the value of wireline conveyed DFA tools and latest wireline sampling methods coupled with a tuned EoS for an accurate PVT description of complex reservoir fluids. It can not only detect the presence of compositional gradients at an early time but also help refine the PVT model to establish the gradation in composition, thus providing a cost-effective solution for deep water ventures.
Conflicting Views: CO2 Corrosion Models, Corrosion Inhibitor Availability Philosophies, and the Effect on Subsea Systems and Pipeline Design
Authors: Marsh J. , Teh T.
Published: December 2007

This publication examines the influence of different corrosion models, corrosion availability philosophies, corrosion control philosophies and standards on materials selection and corrosion allowance design criteria for subsea systems and pipelines. These differ enormously from operator to operator and national authority to national authority. The result is that for the same nominal environmental conditions, pipeline and subsea systems designs can vary enormously, depending on who is the client and where the facility will be situated. Also, it results in designs that would be deemed as entirely acceptable for operation in one area of the world, but which would be considered as unsafe for operation in another.

This publication discusses the nature of these influences, and the effect on subsea system materials selection and corrosion allowance. It also discusses the conceptual conflict between what can be designed for in theory, and what experience tells us has actually been achieved in practice. Finally, it discusses the approach that Ionik Consulting would take in formulating solutions to these issues.
Integration of Pore Pressure/Fracture Gradient Prediction Methods and Real-Time Annulus Pressure Measurements Optimizes Drilling in Deltaic Environments
Authors: Greenwood Jeremy A. , Abdallah Mohamed
Published: December 2007

Pore pressure and fracture pressure prediction represent one of the largest challenges in drilling in deltaic environments. They place constraints upon the design and ultimately on the cost of a well. They can also be a source of significant amounts of non-productive time in the drilling operation. Inaccurate estimates of formation pressure can significantly increase the costs of a well — from over-engineering the well design, taking kicks, differential sticking, and lost circulation, to losing hole sections.

The pore pressure and fracture gradient prediction model described in this paper has been applied in numerous wells drilled in deltaic environments, both on and off shore and in ultra deep water, with outstanding success.

Using a balanced stress strain algorithm not dependent on geologic age or burial environment, an accuracy that is better than ½ ppg can normally be achieved. Utilizing pressure while drilling (PWD) measurements alongside the pore pressure/fracture pressure prediction provides both a method of verifying the pore pressure and fracture pressure predictions and managing the drilling fluid static and dynamic pressures. Such information also provides an improved method of optimizing many aspects of the drilling process.

This paper will compare the pore pressure/fracture gradient methodology utilised here to other commonly used pore pressure methodologies and will illustrate the development and calibration of the model within an actual deltaic environment. The benefits achieved through the integration of these models with real-time PWD measurements, in optimizing the drilling process, will also be described. Finally, the latest developments in downhole sensor technology which may further improve this process will be discussed.
Effect of the Visco-elasticity of Displacing Fluids on the Relationship of Capillary Number and Displacement Efficiency in Weak Oil-Wet Cores
Authors: Wenxiang Wu , Demin Wang
Published: December 2007

In the past, the elasticity of the displacing solution was not considered when the influence of capillary number on displacement efficiency was studied. Recent years, the theory that the visco-elasticity of flooding fluid can increase displacement efficiency has been gradually accepted, but the present research level can not quantitatively describe the effect of elasticity on elasticity. In this paper, the first normal-stress difference was used to characterize the elasticity of polymer solutions, the influence of capillary number on displacement efficiency and residual oil saturation after flooding by different visco-elastic polymer solutions is studied through experiments on weak oil-wet artificial homogeneous cores. Also, at the same capillary number, the influence of the visco-elastic property of polymer solutions on displacement efficiency and residual oil saturation is studied. A set of curves of capillary number versus displacement efficiency after flooding by different visco-elastic polymer solutions is obtained. The results show that the capillary number and visco-elasticity both influence the displacement efficiency and residual oil saturation. Under conditions of same capillary number, the higher the visco-elasticity of the polymer solution, the higher the displacement efficiency, the lower the residual oil saturation, the visco-elasticity of polymer solution can significantly increase recover efficiency and lower residual oil saturation.
From "Forget It, It's Illegal," to "Yes, but…": The Saga of Carbon Underground Storage Regulatory Framework
Authors: Garland Emmanuel
Published: December 2007

Marine underground storage of Carbon dioxide (CO2) is now recognized as one of the techniques which could significantly reduce CO2 emissions. It has not always been the case. Five years ago it was uncertain whether a consensus could be reached or not on a realistic regulatory framework for offshore application.

Carbon capture and storage slowly emerged from other alternatives. Opponents moved from refusal to acceptance on conditions: having failed to have the proposal rejected on the grounds that marine underground storage of waste material was illegal, some opponents still use safety and environmental arguments against the concept, and require exorbitant characteristics and guarantees with a view to make that technique uneconomical or impracticable. Industry managed so far to pass the message to the regulators to ensure a favourable outcome, but there is still a long path to go.

In its second part, the paper describes current international legal status: it includes the London Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (LC72) and its 1996 Protocol thereto (both instruments are valid, but in different countries), OSPAR, the regulating body for the North-East Atlantic (which includes the North Sea), and the European Union which is supporting several projects on this issue but has not yet taken a formal definitive position on it.
Integrated Property and Fracture Modeling Using 2D Seismic Data: Application to an Algerian Cambrian Field
Authors: Ouenes A. , Klepacki D. , Royer T. , Boufrioua A. , Mouhouche E. , Hamoud M. , Djermouni K. , Harhad H.
Published: December 2007

The use of 2D seismic lines to derive integrated 3D reservoir models remains a major challenge for the E&P industry. The use of 3D seismic in developing 3D reservoir models is well established, but there remain areas where 3D seismic is rare and 2D seismic lines are abundant. This paper describes a unique workflow that fully utilizes the data available in the 2D seismic lines. The first step in the workflow is to interpret key seismic horizons and use them in inversion and spectral imaging. The second step consists of interpolating the 2D seismic attributes over the entire field and creating pseudo-3D seismic cubes. The third step consists of using the various pseudo-3D seismic cubes to derive 3D geologic and fracture models. The fourth step is to use the derived models in a reservoir simulator to verify the validity of the models and to design reservoir management strategies to optimize recovery

This workflow was applied to a complex fractured field in Algeria which produces from a Cambro-Ordovician reservoir. Twenty-one 2D seismic lines were used in the project to derive a new structural interpretation and to create three pseudo 3D seismic attributes. These seismic attributes were used as input in REFRACT™, Prism Seismic fracture modeling software, to create geologic and fracture models. The resulting porosity and permeability models were input in the Eclipse™ reservoir simulator software. Ninety percent of the well performances were matched, confirming the reliability and accuracy of the derived geologic and fracture models and the usefulness of the workflow.
Dynamic Modeling of Multiple Regionally-Extensive Reservoirs Using a Unified Fluid Description
Authors: Dindoruk Birol , Al Kindi Azhar
Published: December 2007

A novel approach to perform basin scale compositional simulations for a group of Gulf of Mexico reservoirs has been conducted. The main objective of such an effort has been to integrate reservoirs with potential dynamic communication through a single sensible initialization model in the simulator. In the past, some of these reservoirs were modeled stand alone, and the current information has forced us to connect multiple reservoirs that are connected laterally. Performance of three Gulf of Mexico (GOM) reservoirs was assessed using basin-wide compositional dynamic simulation approach. Like many reservoir simulation projects, at the initial phase of this project, "isolated" performance prediction of the subject reservoirs was considered, mainly due to unknown lateral connectivity and the differences in the discovery dates. In later years, there was a need to predict the unified system performance based on surveillance data, and to be able to test the possibility of the connectivity of the multiple reservoirs and reservoir segments.

In addition to the surveillance production data, we have also gathered data based on basinwide analysis and geochemisty that focused on reservoir compartmentalization. Such data confirmed well responses and helped us to initialize the reservoir correctly. Along with the analysis of the particular case to be discussed here, the reasons behind the graded oil/gas reservoirs will also be discussed and will be provided to highlight the broader implications of field observations as well as some of the ideas presented in the literature.
Generation Y in the Oil Field: Are We Ready?
Authors: Rajan Surya
Published: December 2007

Often known as Net Generation, MyPod Generation, Millenials, etc., the latest crop of oilfield workers is characterized by a much higher level of technology simply growing up than earlier generations ever experienced in a lifetime of training and professional experience. Born in the 1980s through the end of the millennium, this generation grew up with cell phones and IMs, MySpace and iPods, and during their impressionable years bore witness to the first Gulf war, September 11th bombings, and then the second Gulf war.

Oilfield work culture is often described as "traditional". Early adoption of most technologies – particularly in terms of electronic communications – tends to be dampened by common oilfield factors such as anti-trust and anti-competitive concerns, financial controls, and general security practices.

We lag in terms of encapsulating field operational knowledge into computerized automation packages ready for handover to the thumbs seasoned on Nintendo controls. In the R&D centers we’re still not rich in 3-D visualizations and touch-screen control centers. External instant messaging is usually blocked. Technology aside, Generation Y workers are aggressive and result-focused, ready to step up as our peers. Our ability to attract and retain talent in the oilfield may very well be hampered by our stodgy image. Our approach towards adoption of technology has been pragmatic, heavily influenced by hard short-term economics. The drivers may be turning more strategic than ever before. As we face harder E&P challenges, technology development and adoption is becoming an imperative. Leaders and executives in the oilfield will have to understand the changing face of the workforce, and steer cultural shifts to not just open jobs for Generation Y, but embrace their potential and allow them to bring explosive productivity to the oil industry in partnership with expert veterans of the industry.

The analysis presented here explores shaping influences and determinant characteristics that distinguish Generation Y. Based on that, needs of that workforce segment are compared with the state of the oilfield and the remainder of its workforce, arriving at recommendations strongly rooted in partnering and relationships.
A CO2-Rich Gas Well Test and Analyses
Authors: Xu Q. , Weir G. , Paterson L. , Black I. , Sharma S.
Published: December 2007

This paper reports on the planning, operation, results and analysis of a carbon dioxide (CO2) well test performed on Buttress-1, a CO2-rich gas well located in the Otway basin, Victoria, Australia. A field-scale study of CO2 sequestration is planned by the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) in this area, which will involve, inter alia, taking CO2 from the Buttress reservoir and injecting it into a nearby depleted gas field. Understanding the production characteristics of the well and gas initial in place of the field is important to the success of this project. Testing comprised of a multiple rate test and extended drawdown test in order to determine general well and reservoir characteristics, such as the well deliverability, the non-Darcy coefficient and the average reservoir permeability and volume.

The well test operations were challenging, as there have not been many instances where CO2 wells have been flow tested in the past. Hydrate formation, flow assurance, and environmental concerns, such as noise control, soil contamination, and safety level of CO2 were considered in the operation. Operations were completed successfully with no incidents and the required data were obtained successfully.

Compared to the wealth of experience developed over many years in testing oil and gas wells, the collective experience in CO2 well testing is limited. The distinguishing features between this test and those of a typical natural gas well test need to be emphasised. Although, in general, flow testing a CO2 well should be similar to testing a natural gas well, differences in the thermodynamic properties of CO2 affect the analysis of the well test considerably. In particular, the non-Darcy effect can be more pronounced and the wellbore and surface flow can involve dramatic phase changes, such as the formation of ice. In addition, since CO2 is more compressible than a typical natural gas, the accurate measurement of the flow rate becomes more challenging. It is also apparent that the use of pseudo pressure, as opposed to simpler methods of dealing with the pressure dependency of key properties, is essential to the successful analysis of the pressure response to the CO2 production.
Laboratory Testing of Downhole Gas Separators
Authors: Bohorquez R. , Ananaba V. , Podio A. L. , Lisigurski O. , Guzman M.
Published: December 2007

The objective of this paper is to provide insight on the design of downhole gas separators based on laboratory studies of various designs. A downhole gas separator, also known as a gas anchor, may be installed below the pump to separate free gas from the produced liquid. The gas that is separated downhole is produced through the casing-tubing annulus and the liquid is produced through the tubing. Unfortunately inefficient gas anchors are common and an acceptable guide for their optimum design does not exist.

Laboratory testing of downhole gas separators has been ongoing since January 2005 at the University of Texas at Austin using an instrumented full scale model of a wellbore and separator constructed with clear acrylic pipe to visualize the fluid mechanics of the separation process. An air and water mixture is injected through the well's perforations. The air and water flow rate measurements are used to measure and define a performance plot of each separator design. Both continuous and intermittent flow conditions were applied in the tests. The separator designs that were tested differ in entry port configuration, size of dip tube and relative position of the separator with respect to the well's perforations. Based on the results of the tests, a new separator design that includes the effect of centrifugal forces to separate the gas and liquid phases was developed.

The results show that, for the conditions in the laboratory, 100% separation was achieved whenever the entry ports were located 1 to 2 feet below the bottom-most casing perforation. The entry port geometry does not appear to have a significant impact on the separator efficiency as long as sufficient flow area is present. The efficiency of all gravity driven separators was limited by the liquid velocity inside the separator annulus. When the liquid velocity inside the separator averaged approximately 6 in/s or less, an almost to complete gas separation was achieved. On the other hand, the centrifugal separator had a liquid capacity 70% greater than any of the gravity driven static downhole gas separators.
Reservoir Management Challenges of the Terra Nova Offshore Field: Lessons Learned After Five Years of Production
Authors: Haugen E. , Costello J. , Wilcox L. , Albrechtsons E. , Kelly I.
Published: December 2007

The paper describes reservoir management challenges during the first 5 years of the production from the Terra Nova oil field, located offshore Newfoundland and Labrador, Canada. The purpose of the paper is to share lessons learned in the appraisal strategy, data monitoring, subsurface modeling and production management of this subsea/ floating, production, storage, offloading (FPSO) development. The material covers appraisal history, reservoir description, production history, reservoir monitoring, reservoir management, lessons learned and future challenges.

The paper will discuss the need for a balanced approach regarding development and delineation of the resources. Since there is no gas export from Terra Nova or any of the Grand Banks fields, surplus gas has to be re-injected. The Terra Nova depletion plan requires that the production from the water injection region and the gas flood regions be balanced for optimum pressure management. The relative richness of the injection gas from the Terra Nova production process has the potential to create miscible gas-oil conditions. We will discuss how slim tube experiments and compositional tracking of the fluids have demonstrated benefits to the oil recovery by operating the gasflood at a reasonable pressure. The Terra Nova field lies not only in a harsh environment but also in an immature, low infrastructure area. This has led to additional challenges regarding reservoir management and future development.

Production behavior and history matching have shown that seismically defined fault blocks are transmissible rather than sealing. The presence of leaky faults is beneficial for oil recovery, but presents challenges for precise reservoir simulation modeling and history matching. Terra Nova has extensive amount of data from bottom hole pressure gauges, wireline formation pressures (e.g. RFT/RCI), water cut trends GOR trends, gas tracers, etc. The paper discusses how these data have been integrated in the reservoir management process. Various history matching approaches will be discussed; both manual history matching and assisted techniques (experimental design).

This is to the best of our knowledge the first SPE paper from the Grand Banks oil province that describes integrated reservoir management challenges particular to this region.
Experimental Study of Critical Flow Rates in the Tubing-Casing Annulus of Natural Gas Wells
Authors: Girija E. G. , Christiansen R. L. , Miller M. G.
Published: December 2007

Removal of water and hydrocarbon liquids from gas wells is increasingly recognized as an important topic for mature gas reservoirs. Accumulation of these liquids in the bottom of a gas well is often referred to as liquid loading. Liquid loading limits current productivity of 90% of the natural gas wells in the USA. Liquid loading first appears in the casing below the end of tubing (EOT). One way to reduce loading below the EOT is to install dead-end production tubing to the bottom of the perforations and force the gas to flow from the perforations through the tubing-casing annulus up to a cross-over connection near or above the top of the perforated interval. We conducted tests in a flow loop to evaluate such flow.

The primary objective of our tests was to determine the critical flow rates for two phase flow through tubingcasing annulus using two different tubing sizes (2.88-inch-OD and 3.50-inch-OD) in a 4.00-inch-ID casing. Secondary objectives were to develop a method to predict critical flow rate, to identify the flow regimes that exist at the critical flow rate, and to evaluate the mode of liquid transport.

For gas-water flow in vertical tubing, the Turner-Hubbard-Dukler (1969) prediction for critical flow rate (without the 20% correction) is very close to what we observe in our flow loop. However, the critical rates for flow in the tubing-casing annulus were found to be 20 to 50% less than predicted by multiplying the Turner-Hubbard-Dukler (THD) critical velocity and the annular cross-sectional area. It was observed from the tests that two types of flow regimes could occur at the critical flow rate: annular flow regime and transitional annular flow regime.

In flow through an annulus, the film thickness on the casing wall is larger than the film thickness on the tubing wall. Theoretical analysis for one-phase flow shows that the maximum velocity in tubing-casing flow is closer to the tubing. We believe that this observation also applies to two-phase flow and that the higher velocity near the tubing pushes liquid toward the casing, which results in the observation of thicker liquid films on the casing wall.