bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Reserves Booking Guiding Principles for Sound Reservoir Management
Authors: Vikas Shree , Zammerilli Anthony , Ranganathan Raja
Published: December 2007

Reporting of reserves or "reserves booking" is an important issue in reservoir management. Despite this fact it is not practiced in a consistent manner by field operators, royalty owners, the Government, the investing community, and other stakeholders in the oil and gas industry. Furthermore, the Securities and Exchange Commission (SEC) and Financial Accounting Standards Board (FASB) statements on this issue are fairly vague, leaving much to individual interpretation of the rules. This inconsistency in reserves booking is due in part to the lack of a well-defined set of guidelines and is exacerbated by geologic and market uncertainties.

In this paper, we investigate approaches to improve reserves booking procedures making use of the 14th update of NRG Associates database "The Significant Oil and Gas Fields of United States". Data from all the gas fields discovered in the year 1990 were taken to arrive at an average representation of the reserves booking practice. In addition, two fully developed fields in the Rocky Mountain region and the Gulf Coast region were taken to investigate individual field level reserves booking practices.

Our results indicate that reserves booked increases more than linearly as a function of drilling. These results are confirmed by conversations with industry experts and support the conclusion that players in the industry tend to be conservative, delaying reporting of reserves. This is contrasted with the "diminishing returns" concept where there is a large increase in knowledge (i.e. reserves booked) during the initial phase, and then beyond a point, the gain in knowledge is less than proportional to the gain in effort spent (i.e. drilling).

In order to arrive at a compromise "best practice" for booking reserves, we recommend a linear relationship and propose that reserves booked from the field should be directly proportional to the number of successful development wells drilled. This will help in capturing the true Finding and Development (F&D) cost of different basins and their relative competitiveness.
Performances of Openhole Completed and Cased Horizontal/Undulating Wells in Thin-Bedded, Tight Sand Gas Reservoirs
Authors: Göktas B. , Ertekin T.
Published: December 2007

With the recent advancements in drilling technology, drilling undulating wells, which specifically target various zones in a reservoir, has become a rather routine application. In accordance, drilling engineers are able to steer the well to coincide with pre-established sinusoidal trajectories. This advancement in drilling practices calls for the enhancement of our understanding of the production characteristics of undulating wells. This paper provides an in-depth comparative analysis of production performances of open-hole completed and cased horizontal/sinusoidal wells.

Horizontal wells offer great advantages in thin-layered, tight sand gas reservoirs as they increase the productivity through a larger contact area with formations. In this study, a comprehensive performance comparison of open-hole vs. perforated horizontal wells in thin, tight sand gas reservoirs is presented. This is accomplished using a 3-D, single-phase flow model, which is capable of accommodating vertical, horizontal, undulating, perforated, and fractured wells. Effects of drilling damage and crushed zones are considered in the simulations. The parametric study presented in this paper includes various phase angles, shot densities, perforation lengths, and number of fractures. Additionally, the study considers effects of uneven perforation lengths on the topology of the flow fields generated around the perforations. The flow performance comparison is further extended to undulating wells in thin-layered, tight sand gas reservoirs with shale streaks. In the presence of shale streaks, it is observed that undulating wells, which penetrate individual isolated layers, perform more effectively than horizontal wells.
Use of Prior Information in Gradient-Based History-Matching
Authors: Brun Bertrand , Gosselin Olivier , Barker John W.
Published: December 2007

This paper demonstrates how certain geological constraints can be imposed during gradient-based history matching by use of a prior term in the objective function. We extend an existing method of parameter selection (gradzone analysis) to the case where the prior covariance matrix is non-diagonal. We show that the parameter selection can be made independently of the weight assigned to the prior information, and illustrate how the shape of the gradzones is modified to re ect the correlation structure of the porosity or permeability fields. Finally, the use of the prior term to preserve a relationship between porosity and permeability during the history-matching process is demonstrated.
A Successful Case On Environmental Permit
Authors: Fontanelli G. F.
Published: December 2007

In Brazil, gas and oil exploration and production (E&P) is ruled by environmental laws that do not meet its characteristics of integrated and sequential development of its activities. Thus, every well drilling, for instance, must be licensed. On the other hand, there are mechanisms predicted in general and basic laws by which the industries may have easier ways to get environmental permits, taking into consideration the activity types. Unfortunately, this has not been observed by environmental control agencies, by this way becoming the issue ‘environmental permits in Brazil’ hard and ‘heavy’.

In 1998, E&P in State of Espírito Santo (called in this paper as Company), Brazil, got success in dealing with the state environmental agency (EA) about validity conditions of a future permit. The new permit, issued by the end of 1998, comprises Company's usual onshore E&P activities, and determines that they could be developed without individual (site) permits.

This paper shows, via case study, how the agreement was established and how the negotiations between Company and the government EA were carried out. This agreement ended in a global E&P permit that allows usual E&P activities be started regardless of government formal approval, provided EA be communicated 30 or 60 days before the beginning of the activity. After this lack of time, the activity can be developed. The activities are in general well drilling, seismic survey, oil and gas production and increasing of oil and gas pipeline capacities.

The main conclusion that comes from this paper is that an enterprise should use strict ethical principles when talking to an EA. This results in a relationship of confidence between the parts, and occasional difficulties that usually appear in this kind of process are more easily solved.
Feasibility 0f Monitoring CO2 Sequestration in a Mature Oil Field Using Time-Lapse Seismic Analysis
Authors: Fanchi John R.
Published: December 2007

A goal of CO2 sequestration is to provide economically competitive and environmentally safe options to offset projected growth in baseline emissions of greenhouse gases. The sequestration of CO2 in subsurface formations is a gas storage process. Among the issues that must be considered in a gas storage project are verification of injected gas inventory and monitoring of injected gas migration. This paper uses an integrated flow model to assess the feasibility of monitoring CO2 sequestration in a mature oil field using time-lapse seismic analysis.
New Developments in Aerated Mud Hydraulics for Drilling in Inclined Wells
Authors: Sunthankar A. A. , Kuru E. , Miska S. , Kamp A.
Published: December 2007

When drilling with aerated drilling fluids, bottomhole pressure is a strong function of gas-liquid flow patterns. The existing methods of predicting flow patterns are mostly based on the extrapolation of results from pipe flow to flow in annuli. Due to non-linear relationships between flow rate, pipe size and pressure drop, this practice may not be appropriate to apply in drilling operations. Therefore, in order to verify the applicability of the existing practice, the present study focuses on the flow of aerated drilling fluids through an inclined annulus, typical for drilling operations in directional wells.

Extensive experiments were performed in a unique fieldscale low-pressure flow loop (8 in × 4.5 in annular geometry, 90 ft long) in inclined positions (15°, 45° from vertical) with (100 rpm) and without drillpipe rotation. The liquids used were water and aqueous polymer solution (CMC+XCD+water), at flow rates in the range of 100–360 gpm and air in the range of 8–85 scfm (for 15°) and 250–1150 scfm (for 45°). Gas/liquid ratios were chosen so as to simulate similar gas/liquid ratios under downhole conditions, correcting for the fact that the actual pressure in the flow loop was much lower than the bottomhole conditions. Measurements of pressure drop and average liquid holdup over the entire annular section were carried out. To our knowledge, no such data has been published before.

The two-phase flow patterns were identified by visual observations. Bubbly flow and the slug flow are the two flow patterns observed over the ranges of the chosen test matrix. The presence of slug flow does not justify many of the existing simulation practices, which assume homogeneous gas-liquid flow.

Also, the flow pattern boundaries proved to be shifted as compared to pipe flow. The transition between bubbly flow and slug flow (for 15° inclination) was observed at a void fraction of 0.32 as compared to that reported for pipe flow (0.25). On the contrary, for air-aqueous polymer fluid flow, it was the same as for air-water pipe flow (0.25). For flow with drillpipe rotation, churn flow was observed instead of slug flow due to the churning of slugs by the rotating drillpipe.

While there was no significant effect of drillpipe rotation on the pressure drop for air-water flow, the pressure drop decreased in case of air-aqueous polymer fluid flow with drillpipe rotation. A higher pressure drop was observed in case of air-aqueous polymer fluid flow as compared to air-water flow.

An existing unified pipe flow model1 was modified based on the experimental results and was also evaluated against experimental and field data. The comparison shows that the pressure drop prediction by the modified model for inclined wells is better than some other existing models, though it still under-predicts the experimental pressure drop measurements.
Slickline-Deployed Electro-Mechanical Intervention System, a Cost-Effective Alternative to Traditional Cased-Hole Services
Authors: Foster Jerry , Clemens Jack , Moore Darrell
Published: December 2007

During the '90s, the introduction of battery powered electromechanical intervention tools increased the versatility of slickline service and changed its image from a simple method that performed mechanical workovers to a complex service technology that could provide safe, cost-efficient alternatives for: locating downhole tubular goods/profilesproducing quality logs from downhole memory surveys at half the cost of traditional servicesaccurate depth measurement for support of all new completion technologiessetting packers without explosivesperforating or cutting tubing or casing.

Slickline has again expanded its capabilities. In addition to its proven performance for well remediation, maintenance, and pressure control applications, the new enhancements to the self-powered slickline tools can now be used to perform diagnostic and conformance control functions requiring memory production logging.

Applications that require electrical initiation or mechanical manipulation at the tool interface can now be performed with slickline and battery power, insulating the tools from the surface equipment. Mechanical signals transmitted through the wire control the tool start and stop functions and provide real time position telemetry. As a result of the advances in service tools, slickline has increased the scope of its services without a compromise to operational safety and job efficiency and offers the most cost efficient services in well workovers.

The case histories will describe how the electromechanical intervention tools provide a cost-effective alternative to traditional cased-hole logging systems for many applications as well as many operations that traditionally had to be performed by other service options.
Production Response From Southeastern New Mexico Morrow Wells Stimulated with Binary Foams
Authors: Walser D. W. , Gerstner M. J.
Published: December 2007

For many years, local industry consensus and various authors1,2,3 have concluded that with few exceptions4, fracture-stimulation of the Morrow sand series in southeastern New Mexico is best undertaken utilizing fluids containing [at least] CO2, KCl, and methanol. Unfortunately, this conclusion originates from hearsay and limited studies that looked at only a few treatments. Difficulties with past efforts to verify and compare post-fracture well performance were centered on the inability to database naturally-occurring parameters for the majority of wells, as well as problems stemming from inaccurate and erroneous public data.

Localized successes with foams containing CO2, KCl, nitrogen, and methanol prompted a more comprehensive study of the area that attempted to address the problems associated with the evaluation of public production data.

A Graphical Information System5 was coupled with publicly available production data and internal pumping service company records6 to attempt to determine if one completion methodology was really any better than another. Production from wells treated with Binary foams over a four-year period (1996 – 1999) was compared to production from up to 19 offsets per well of interest. A set of relatively rigid criteria was set up and followed to ensure that the study was as objective as possible, given the constraints of working with public data. Although it was not possible to "normalize" the wells of interest or their offsets to account for differences in natural parameters, the large number of wells examined provided some degree of confidence in the validity of the process.

Conclusions are presented. The average first 90-day cumulative production from wells treated with Binary foam was higher than the average of wells that were stimulated with other systems. Evidence is also presented to suggest that it may be prudent to fracture-stimulate wells with high initial natural production.
An Innovative All Electric Well Production System
Authors: Rivenbark Mark , Khater Sami , Dietz Wesley , Steven Barnes
Published: December 2007

A major operator in the Middle East has been producing gas from the same formation for approximately 20 years. Traditionally, hydraulic actuators have been used to control the wellhead gate valves in these gas wells. These actuators have been operated from a hydraulic control panel that is pneumatically powered, and the compressors used to generate the instrument air are electrically driven. The existing systems have not only been inefficient, as they required electricity to power the hydraulic actuators, but they were also very maintenance intensive.

When the decision was made to begin a 5-year drilling program to develop additional gas reserves, an important part of the project development process was the investigation of alternatives to existing wellsite equipment. A unique system in which the gate-valve actuators, the control panel with a PLC as well as the pressure pilots, fusible plugs and ESD switches were electrically controlled, was chosen for testing. The system also incorporates a battery back up to maintain operation in the event of a power failure.

This paper will discuss the system and the testing program developed to assess its capabilities as well as the testing that was required to comply with other industry mandated testing. The paper will also delve into other ongoing projects using this technology and highlight the superiority of an electric system over more conventional hydraulic or pneumatic systems. For the project discussed in this paper, an existing well was converted to the all electric system, and a rigorous one year testing program was carried out by the operator. In addition to normal exposure to the elements and routine opening and closing of the well to meet production demands,

the test also included over 300 additional open and close cycles on each of the three electric actuators on the tree.

The operator estimates capital cost savings for the all electric system in excess of $200,000 per well over the present pneumatic/hydraulic systems. Additional savings would also be generated in the future from the manpower reductions planned when the system was fully proven. Finally, a reduction in maintenance would also impact operational costs.

In a recent analysis of the system capabilities to date, the operator specifically noted the following benefits: The operators were able to handle their duties much more easily since the system is all push button.The self-diagnostic features built into the panel allow quick troubleshooting of the system rather than requiring assessment of problems through trial and error.The maintenance record to date has shown that minimal maintenance has been required.

The results of this project have also shown that other potential applications such as unmanned platforms and pipelines could benefit from this all-electric system.
Automated Chemical Control of H2S Content of Natural Gas
Authors: Roth Dane , White Bob , Benavides Danny , Lame Charles , Arreola Rosendo
Published: December 2007

This paper introduces a new field application for the automation of hydrogen sulfide chemical scavenger injection systems in natural gas pipelines. The automated system combines currently available technology into a cost saving tool that has proven itself reliable in maintaining the level of hydrogen sulfide needed for contract gas sales. The benefits that an automated system provides are multi-faceted. These benefits are shown in the savings of man-hours, safety, and chemical usage optimization. Eliminating the need for intermittent checks of the hydrogen sulfide level and chemical pump adjustments saves employee time. Safety is improved due to the fact that the employee does not have to manually check the hydrogen sulfide level, thus not opening valves that would release natural gas containing hydrogen sulfide. The automated system also optimizes chemical usage by continually monitoring the system and maintaining the hydrogen sulfide content at the level needed for gas sales. The content of hydrogen sulfide in a natural gas gathering system is a dynamic and continually changing system due to several factors, i.e. new wells brought online, wells being shut in for various reasons, and the changing hydrogen sulfide level in individual wells. This system will automatically adjust for these continuous variations and lead to significant savings in hydrogen sulfide scavenger chemical applications.
Experience of Collecting Daily Production Data Using Handheld Devices and the Internet
Authors: Boone Douglas M.
Published: December 2007

This paper describes the experience of working with over a dozen companies in the design and implementation of a web-based field data collection system. Daily well, tank, and meter readings are entered in the field using a handheld computer in place of paper gauge sheets. The data is transmitted electronically to a database server on the Internet. A touch-tone telephone offers an alternative means for data entry. Users can display and plot the data using a PC application that accesses the data across the Internet.

This paper will review the experience gained in the following areas: Field operations and system designHardware durability in the fieldInterfaces for pumpersAlternative data entry systemsCommunications in rural areasInternet database and engineering applicationsTraining and supportCost-benefit analysis
The Historical 20th Century and the Future 21st Century of Petroleum Engineering Professional Registration
Authors: Wines G. Bing
Published: December 2007

Professional recognition for the Petroleum Engineering profession began developing in the early 20th century1,2. Professional Registration for the Petroleum Engineer has seen some drastic changes since its implementation unto the national scene in 1907. Most of these changes occurred through the nationally administered National Council of Engineering and Land Surveyors (NCEES). The national Petroleum Engineering Professional Exam began in 1973 when NCEES started offering it to all states. The requirements to become registered gradually became stiffer. The advent of the Sunset Legislation fad in the 1980's really changed the state requirements. In 1973, the PE Exam began as a twenty problem offered, choose eight to work, objective style exam. By 1999, it had evolved to an eighty question, no choice, all multiple choice exam. As we enter the 21st century, computers will eventually administer the PE Exam.
Best Practices in the Preston Spraberry Unit
Authors: Long Scott W. , Smith Elton J. , Hoff Charlie R. , Garza Albert A.
Published: December 2007

During the last several years the Petroleum Industry has adopted the term "Best Practices" to describe an efficient method of producing oil and gas. The definition of this "method" is very subjective and is continually changing with acceptance of new improved and proven rod pumping knowledge. The best way to describe the term Best Practices is by using the phrase "Work in Progress" or "Continuous Improvement."

This paper describes and presents the implementation of a Best Practices program in the Preston Spraberry Unit located in West Texas. This accepted Best Practices program is presented as follows: Complete initial pumping well analysis.Matching lift operations to current producing rates by optimizing the following: plunger diameter, strokes per minute, stroke length, tubing anchor catcher, and downhole gas separation.Managing downhole rodstring buckling by re-evaluation of rodstring designs and installation of sinkerbars.Installing pump-off controllers to manage production rates, optimize run times and monitor equipment performance.Follow-up well-site diagnostic analyses after several months of operation to evaluate initial well analysis and original well work, and implement further modifications.

Due to the successful implementation of this Best Practices program, tubing leaks were reduced by 61%, rod part replacements were reduced by 35%, and pump repairs were reduced by 6% during the two-year test period.

Recognition and continued development of these successful Best Practices will provide the oil and gas industry with improved artificial lift guidelines. Implementation of these guidelines will allow for more effective use of all valuable resources to more efficiently produce oil and gas.
Enhanced Oil Recovery with Downhole Vibration Stimulation
Authors: Westermark R. V. , Brett J. F. , Maloney D. R.
Published: December 2007

The use of vibration to improve oil recovery has long been investigated. The background for this novel technology is reviewed along with the project rationalizations, designs considerations, and measurements performed in advance of a downhole vibration stimulation field test. This field demonstration will pilot test the potential of downhole vibration to enhance oil recovery from a shallow oilfield in Osage County, Oklahoma. The project is supported by the Department of Energy (DOE), Seismic Recovery LLC, Phillips Petroleum Co., and Grand Resources, Inc. Recent literature has reported successful vibration stimulation in shallow reservoirs with high water oil ratios (WOR). Osage County has, like many areas of the United States, numerous old fields under waterflood, with many wells producing marginal oil with substantial water production.
Two Methods for Achieving a Dual Gradient in Deepwater
Authors: Herrmann Robert P. , Shaughnessy John M.
Published: December 2007

The advantages of a dual gradient mud column have been well documented. Significant work has been done on the riserless drilling systems by several different companies. This paper will propose two methods to achieve the same dual gradient. Nitrogen Injection: Building from proven air drilling procedures and underbalanced techniques nitrogen can be used to cut the mud weight back in the riser above the seafloor or the cut can be made deeper by combination with a concentric riser.Floating Mud Cap: A dual activity rig can use a casing riser linked to the adjacent marine drilling riser. A submersible pump in the casing riser regulates returns that will set the mud cap level in the drilling riser. A pressure sensor in the subsea BOP allows monitoring the effective hydrostatic pressure. This approach again combines field proven procedures and hardware in the deepwater environment.

Both methods will be presented with emphasis on the hardware and operational procedures required to successfully implement them. Both of the methods employ existing equipment and procedures.
Advances in Expandable Tubing – A Case History
Authors: Ruggier Michael , Benzie Scott , Urselmann Rob , Mosser Henrik , van Noort Roger
Published: December 2007

The paper describes the world’s first use of expandable solid tubing to close off perforations. The development and testing of the system leading up to the two field installations is described with the execution and validation process.

The fundamental concept of solid tubular expansion had been proven to be sound, but four main development hurdles needed to be overcome. Extensive innovation in design and material selection culminated in two main applications being fulfilled, with subsequent testing proving the absolute success of the technology. These first few steps pave the way to a number of existing commercial applications and our ultimate goal of mono-diameter wells.
A Novel, Surface Sensitive Approach to Quantitatively Measure the Prediction and Inhibition of Scale Growth
Authors: Wylde J. J. , Allen G. C. , Collins I. R.
Published: December 2007

A novel approach to measure mineral scale growth has been developed which is not only quantitative but also surface sensitive. In this study, a glass flow cell was used in conjunction with Laser Raman Spectroscopy to record the in-situ growth of mixed barium and strontium sulphate scale on the surface of 316 stainless steel. Studies of both uninhibited and inhibited growth are reported as well as the influence of specific ions. All experiments have been performed at room temperature and pressure and at constant solution pH.

In order to quantify these measurements, Secondary Ion Mass Spectrometry (SIMS) has been used to etch the precipitated scale from the surface of the steel. As the scale is removed, an elemental analysis of the sputtered ions is performed, resulting in a depth profile, which is sensitive to the presence of scale mineral ions on the steel surface. The etches were then imaged using Scanning Electron Microscopy (SEM).

Our data suggests that there was a large surface influence upon inhibition efficiency when compared with previously presented results (e.g. Yuan, 2000). A much higher concentration of inhibitor was required to prevent scale build up, compared with values determined in bulk precipitation tests, indicating the formation of inhibitorsurface complexes.

Most previous studies are non-surface sensitive and have utilised aqueous precipitation experiments to evaluate scale inhibition efficiency (Graham et al., 1997). Previous surface sensitive methods have used Atomic Force Microscopy (AFM) to observe scale precipitation and to measure the effect that nhibitors have upon the nature of crystal growth; however, this technique is not rate sensitive and thus the kinetics of scale build up have not been previously obtained (Bosbach et al., 1998).
Quantitative Prediction of Scale Depositions Induced by Oil Production: Application of the Thermo-Kinetic Software SCALE2000
Authors: Azaroual M. , Hurtevent C. , Kervévan C. , Brochot S. , Durance M.-V.
Published: December 2007

The SCALE2000 (V2.0) software (under Windows 95/98/NT) was specifically developed to predict quantitatively scale deposits induced by oil production operations. The conceptual model is based on the Pitzer's specific ion interaction formalism for Na-K-Ca-Mg-Sr-Ba-Fe-Cl-SO4-OH-H-Ac-CO3-HCO3-CO2-AcH-SiO2-H2O system under 25 - 250°C and 1 - 1000 bar conditions. SCALE2000 enables to perform four main kinds of calculations including solubility of the main known minerals responsible for scale problems in geothermal energy and oil productions (carbonates, sulphates, silicates, …), effect of temperature and pressure on the scale precipitations, effect of binary mixing of physico-chemical contrasted waters, quantitative predictions of scale formation based on a detailed kinetic formalism. As it was demonstrated by petroleum engineers, carbonate system is crucial for precise scale risk predictions. The reliability of SCALE2000 results was checked against measurements of individual mineral solubilities and kinetics found in the literature.

In this study, SCALE2000 was applied to the actual high temperature (164°C), high salinity (~ 84 g/l) and high pressure (320 bar) data of the Block 3 (Angola) oil-field. In agreement with observations, the precipitation of barite was predicted by SCALE2000. The mineralogical nature of deposits was intimately dependent on the reservoir water/seawater ratio. SCALE2000 simulations of the sulphate depositions on the tubing wall of the PAC 302B Pacassa well (block 3, Angola), as a function of the water produced, has permitted to predict the kinetics of barite precipitation for production P-T conditions (180 bar; 140°C). Simulation results were in good agreement with field observations.
Calcium Carbonate and Naphthenate Mixed Scale in Deep-Offshore Fields
Authors: Rousseau Guy , Zhou Honggang , Hurtevent Christian
Published: December 2007

Many of the fields that have been or will be discovered in the near future show signs of biodegradation of the crude oil. The result of such biodegradation is a decrease in the amount of the paraffins associated with the formation of naphthenic acids. Some of these crude oils may have a Total Acid Number (TAN) close to 5mg/g. When the reservoir fluid contains a significant amount of CO2, one can expect to find mixed scale of calcium carbonate and naphthenate. The aim of the work conducted was to assess the various factors which affect the formation of mixed scale.

We studied, in particular, the consequences arising from the formation of highly surface-active naphthenates which, depending on the nature of the cations in the formation water, can form stable emulsions, calcium naphthenate deposits or mixed scale of calcium carbonate and calcium naphthenate.

This paper presents the ways to prevent emulsions or deposits resulting from the formation of naphthenates. Chemical prevention is the most commonly used method but problems can sometimes be solved by modifying the way crude is processed. We will also describe an example of a modified process that we plan to use.
SQUEEZE Modelling: Current Best Practice and New Capabilities
Authors: Mackay E. J.
Published: December 2007

Various general-purpose software packages can be used to optimise the design of scale inhibitor squeeze treatments. However, the versatility and cost of these codes typically makes them cumbersome and expensive to use for optimising routine squeeze treatments. Conventional treatments should be modelled using purpose designed squeeze simulators that minimise data entry and facilitate quick extraction of results. However, misapplication of even a fit-for-purpose simulator can lead to incorrect treatment design. This problem is compounded by the fact that squeeze strategies are always being developed and refined, and the software must be developed to keep pace with these changes in technology if it is going to be applied correctly.

To deal with these twin issues, this paper will first describe how a squeeze simulator should be correctly applied, and what information may and may not validly be extracted. Potential pitfalls will be highlighted, as well as techniques for optimising the model set-up to ensure that the maximum amount of relevant data is utilised. Experience gained from use of the SQUEEZE V software for modelling core floods, single and multi-layer radial well models will be discussed, and the rationale for making certain decisions when building a model will be highlighted. Secondly, new features being introduced into this code are discussed, together with the impact these may have. The new facilities include two-phase flow, with the potential for component transport in the oleic phase, and full crossflow within the formation in addition to the well. Finally, the paper will present planned future developments that should improve the applicability and scope of the code, without increasing the difficulty of use unduly.
Integrating Well Production Data and 3D Seismic AVO Classification
Authors: Reymond S. B. , Matthews E. , Sissons B.
Published: December 2007

The Ngatoro Field in Taranaki, New Zealand has been producing for (9) nine years. Currently the field is producing 1000 bopd from 7 wells at 3 surface locations down from a peak of over 1500 bopd. The field has been analysed using new techniques in 3D seismic imaging to locate by-passed oil, and identify undrained pools. Three questions define the objectives of the study: Can we image reservoir pools in a complex stratigraphic and structural environment where conventional grid-based interpretation is not applicable due to lack of lateral continuity in reservoir properties?Can we distinguish fluids within each reservoir pools?Can extrapolate reservoir parameters observed at drilled locations to the entire field using 3D seismic data to build a 3D reservoir model?

This case study illustrates how 3D generalised inversion of seismic facies for reservoir parameters can be successfully applied to image and laterally predict reservoir parameters in laterally discontinuous turbidite depositional environment where hydrocarbon pools are located in complex combined stratigraphic-structural traps. Such conditions mean that structural mapping is inadequate to define traps and to estimate reserves in place. Conventional seismic amplitude analysis has been used to aid definition but is not sufficient to guarantee presence of economic hydrocarbons in potential reservoir pools.

Using new 3D seismic attributes such as bright spot indicators, attenuation and edge enhancing volumes coupled with 6 AVO (Amplitude Versus Offset) volumes integrated into a single class cube of reservoir properties, made the mapping of reservoir pools possible over the entire data set. In addition, 4 fluid types, as observed in more than 20 reservoir pools were validated by final inverted results to allow lateral prediction of fluid contents in un-drilled reservoir targets.

Well production data and 3D seismic inverted volume were later integrated to build a 3D reservoir model to support updated volumetrics reserves computation and to define additional targets for exploration drilling.
Umm Gudair Dumpflood Pilot Project, The Applicability of Dumpflood to Enhance Sweep & Maintain Reservoir Pressure
Authors: Quttainah R. , Al-Hunaif J.
Published: December 2007

Historical production (spanning almost 30 years) has confirmed that the UG (MO) reservoir receives very little natural pressure support in some areas. This has resulted in a declining reservoir pressure (from 4050 to 3200 psi) and low recovery factor and also, areas of poor water sweeping. The remedial plan is to initiate a full field water injection project to increase reservoir pressure, improve sweep and enhance oil recovery.

A dumpflood pilot project was initiated to prove the viability of and quantify sweep benefits of water injection in the B-zone of the MO reservoir. The dumpflood Pilot aims to prove that water flooding can enable this unswept oil to be produced and provide data to support the design of future Full Field Water Injection Project.

A dumpflood operation is basically injecting water into the recipient reservoir from a water source reservoir by the natural force of gravity and the pressure differential of the two reservoirs using the same well. In the Umm Gudair Dumpflood Pilot, the water bearing source reservoir is the Zubair formation. The recipient reservoir is the B-zone in the MO. And since the Zubair is structurally higher than the MO, and the reservoir pressure of the Zubair is higher than the MO, water was being produced from the Zubair and injected into the MO by the natural force of gravity and the pressure differential between the two reservoirs.

A location in the east flank of east UG field was chosen to allocate the dumpflood pilot well. This was done after going through 4 different locations in the field to allocate the most suitable field location.

Surveillance requirements have been identified for the UG dumpflood pilot. This surveillance plan involves the dumpflood injection well and 4 other observation wells. In addition to regular PLT surveys, to determine zonal injection profiles and ongoing corrosion surveillance in the Dumpflood well, additional pressure surveys on adjacent wells were planned. It was also planned to utilize radioactive tracers to monitor breakthrough and develop an understanding of the pattern of sweep.

Technical Contributions:

Demonstrated the design of a water dumpflood method to analyze injectivity & water sweep. Established a cost-effective technique to quantify injectivity and water sweep. Demonstrated the applicability of dumpflood to re-pressurize a constantly depleting reservoir.
Surfactants Oil Displacement System in High Salinity Formations
Authors: Wang Yefei , Li Jiyong , Zhao Fulin
Published: December 2007

Aimed for the need of oil displacement in high salinity formations where the normal nonionic and anionic surfactants are inefficient because of salting out or cloud point phenomena[1], A novel structure surfactant(LF) with nonionic and anionic hydrophilic group is put forward and synthesized. The said surfactant is soluble in 30% NaCl brine, and shows good surface activity in brine with 100,000mg/L salinity concluding 5,000mg/L CaCl2. By analysizing the volume fraction-salt concentration phase graph, the salt tolerance property of LF, petroleum sulfonate and their combined system is comparatively studied, LF is excellent, the proportional increment of LF in combined system will improves salt tolerance property of the combined system. In any different brine, water/n-decane Interfacial tension is high if only LF or petroleum sulfonate is used, but Interfacial tension will reach super low if the combined system is appropriately used as long as water salinity is enough high(higher than 20,000mg/L). By adjusting the proportion of LF and petroleum sulfonate in combined system, water/oil Interfacial tension can always reach super low regardless of water salinity, so the system can be particularly used as oil displacement agent in high salinity formations. The paper presents three oil displacement and one chemical tuff and puff formulations consisted of LF and KPS, which were suitable for high salinity formations in Zhongyuan oil field.

The temperatures of four test zone are 86.9°C, 65.0°C, 82.5°C and 82.5°C, the salinities are 88,540 mg/L, 55,028 mg/L, 14,9127mg/L and 195,000 mg/L, the room recovery improvement all exceed 19%.

Now the four field tests get along favorably, verifying good result and indicating bright application prospect.
Evaluation of a New Thermally Stable Polycrystalline Diamond Material
Authors: Zacny K. A. , Cooper G. A.
Published: December 2007

Comparative wear tests were carried out on different composites of synthetic diamond bonded by silicon carbide, by machining rock cylinders in an instrumented lathe. The composites included Syndax3, ‘Polycubes(TM)’ from Didco Inc, and a new material known as ScD from Skeleton Technologies Inc. The different materials show different wear behavior. In particular, Syndax3 wears slowly, by a process that involves predominantly a polishing of the cutter surface. The result is that although the wear rate is low, the cutter points eventually become polished and the cutters lose performance. In contrast, the ScD material wears more rapidly, but maintains a more aggressive behavior since new, sharp diamonds are continuously being exposed. As a result, it keeps an ability to cut rock effectively at much greater states of wear. The material from Didco Inc has a behavior that is intermediate between that of the other two types.
A New Analytical Model for the Prediction of Fluid Production and Gas Consumption of Gas Chamber Pumps
Authors: Hernandez Ali , Caicedo Sergio , Marcano Luisana , Brown Juan
Published: December 2007

Recent experimental studies on intermittent gas lift have shown that the lift efficiency of this method decreases drastically as the viscosity of the fluid to be lifted increases. As the viscosity increases more gas is needed to keep the fallback losses at a minimum. One way to get around this problem and eliminate fallback losses is to implement the use of Gas Chamber Pumps (GCP's).

GCP's are highly appropriate for shallow wells producing heavy oil in places where high-pressure injection gas is available. That is the case of some wells in Lake Maracaibo and in some places in the eastern oil fields in Venezuela that are currently producing oil of 14 to 23°API from reservoirs located at depths between 2000 and 3500 ft.

A variety of different GCP configurations can be found in the literature, from highly complex and compact units to simple types of completion that can be implemented with minor changes of current gas lift completions. The advent of simple and highly reliable programmable surface controllers is making it possible to simplify subsurface completion. The simplicity of these new completions implies a new and economical way of implementing GCP's where they are appropriate.

A description of how different GCP's work and the most popular configurations are given in this paper. It is also explained in detail a new and simple engineering procedure to estimate the liquid production and gas consumption of a well producing with a GCP. This procedure takes into account the inflow capability of the well and couples this capability with the pressure losses across the different parts of the completion and the flow and pressure capacity of the gas lift system.
New Gas-Lift Pilot Valve Increases Gas-Lift Efficiency
Authors: Hernandez Ali , Perez Cesar , Villalobos Balmiro , Romero Analis , Wildman Sam
Published: December 2007

The most important component in an intermittent gas lift installation is the pilot valve. Its selection and proper calibration determine the success of the gas lift design. Recent tests performed in a field scale installation equipped with an experimental well and careful observations of the performance of real wells on intermittent gas lift in Lake Maracaibo have shown the importance of the proper selection of the area ratio of the pilot section and the main port diameter. Usually, the designer has a variety of area ratios of the pilot section to choose from and its selection will depend on the type of gas lift operation, choke controlled or use of time-cycle controllers, and the volume of gas needed per cycle. In some cases, the lowest commercially available area ratio will still be too large with the result of not being able to inject below a certain volume of gas per cycle. The over-injection per cycle takes place because the minimum spread attainable is greater than needed. This situation occurs when the tubing-casing annulus is large and the valve size that can be installed in the well is smaller than the 1 1/2-inch valve. Hundreds of wells in Lake Maracaibo with 7-inch casings and 2 7/8-inch tubing can not be efficiently lifted because of the lack of commercially available pilot valves with small area ratios.

The diameter of the main gas injection orifice is a fixed value for a particular valve model. The size of this orifice is important for two reasons: The size of the injection orifice, together with the injection pressure and tubing load, determines the velocity of the liquid slug being lifted. If the size of the orifice is too small, which is usually the case for 1-inch size valves, the liquid fallback is increased due to low liquid slug velocities.Small injection orifice diameters increase gas injection time and therefore limit the liquid production of the well, especially if the optimum cycle time is of short duration.Tests performed in an experimental well, and presented in this paper, show how a new 1-inch pilot valve design was able to increase the gas lift efficiency. The main features of the new gas lift valve, its calibration procedure and its performance in several real wells are also presented in this paper.
Downhole Oil/Water Separation System – Field Pilot – Secondary Recovery Application Project
Authors: Scaramuzza J. L. , Fischetti H. , Strappa L. , Figliuolo S.
Published: December 2007

It is widely known the adverse impacts that the continuous increase in the volume of produced water has on oil production operation and reserves recovery.

New technologies have been successfully developed and implemented to minimize de economic and environmental consequences of water production.

The Down hole oil/water separation system (DOWS), which was developed by the Centre for Engineering Research Inc. (CFER), allows to separate the produced water down hole and its later injection on the same well.

The system has proved to be technically and economically profitable in mature reservoirs reducing the lifting cost, production facilities cost and environmental risk associated with the handling of large volumes of produced water at surface.

Repsol-YPF produce, separate, treat and dispose of over half million barrels of water per day in La Ventana and Vizcacheras fields in the Cuyo basin in Mendoza province. They produce 29 and 30 °API oil respectively with a high percentage of water.

A pilot field trail was carried out in these fields using DOWS technology. This equipment was installed on two wells producing with electrical-submersible pumps, one in VM-097 well (La Ventana) and the other in Vi-284 well (Vizcacheras).

This report describes the separation system implemented, the candidate wells selected, the results of the pilot field trails and the current flooded project based on Vizcacheras pilot result.
Tácata Field: Discovering Oil in a Subthrust Triangle Zone
Authors: Sadler Peter , Manceda Rene , Franco Alejandro , Vukelic Miguel , Coria Carlos
Published: December 2007

The Tácata Field lies some 30 km west of the prolific El Furrial trend of oil fields in the Eastern Venezuela Basin, and was discovered in 1997. It lies within a recently active triangle zone and presents significant problems to seismic imaging. Pre-stack depth migration and map migration techniques have been employed, the latter with particular success. The seismic interpretation is constrained within the framework of a three dimensional balanced structural model.
A Decision-Making Expert System for the Oil Transport System
Authors: Abdulah Abdulatif , Islam Rafiqul
Published: December 2007

The problem of pipeline corrosion within the oil and gas industry costs the world economy billions of dollars every year in maintenance, repairs and too often in damage control. These costs are passed on, reflected in increased prices to the world's petroleum product consumers. With the advent of widely available computing and communications technology, it is logical that we should seek relief from corrosion and maintenance problems in the form of a high-tech solution. To this end the authors have developed an expert system, the Petroleum Corrosion and Coating Expert System (PCCES) equipped with an extensive knowledgebase of physical and chemical phenomena and the metallurgical characteristics of the pipes themselves. Essentially a complex decision tree, the expert considers factors in a real-world situation and attempts to produce appropriate conclusions based on inference from the knowledgebase. For greater ease of use, the expert system relies on a Java applet design, eliminating the need for proprietary client-side software.