bluuebunny/crossref_metadata_2025 huggingface dataset:
Exploration and Madness: Adjusting the Dual Strategy of an Independent for the 1990's
Authors: Byers D. G.
Published: December 2007

The paper discusses the context and factors which influenced the development of North Sea Independents, arguing that successful strategies combined exploration and corporate activity within a unifying business vision. The competitive pressures of the 1990's are leading Independents into global competition, demanding adjustments to strategy. Emphasis upon the competitive advantages of Independents and rigorous attention to "customer-values is advocated for success in the new decade.
Divestments: Evolution of a Business
Authors: Alexander R. C.
Published: December 2007

BP Exploration has participated in many disposal transactions over the last few years. This paper seeks to provide some insights into how BP manages the process from asset selection to closing the deal.

Disposals have evolved from a tactical activity designed to eliminate non-core assets to a business in its own right. Today, almost every E&P company includes "portfolio management" in its strategy as companies have recognised this activity can add value relative to holding the portfolio constant. This notion of disposals as a stand alone business provides an interesting framework for analysis and it is in this context that disposals are discussed.
An Interactive 3D Visualization Tool for Reservoir Simulation Data, Including Fluid Flow and Particle Tracking
Authors: Williams B. K. , Brown R. L.
Published: December 2007

The graphics workstation, with ever increasing power and decreasing cost, has provided the user community with a suitable platform for the investigation of reservoir simulation problems that are both CPU intensive and require more sophisticated methods of visualization.

Many commercially available visualization software systems provide a part of the functionality required by today's reservoir engineers, but none of those evaluated offered a seamless, advanced functionality environment with intuitive and ergonomic human-machine interface.

The decision was therefore taken to create a system for the preparation and visualization of reservoir simulation data on a graphics workstation, in particular, fluid flow and particle tracking data, using a high level graphical language which takes advantage of advanced hardware capability.

The requirements identified as necessary to provide the visualization support to practicing reservoir simulation engineers are described.

The package was developed as two separate tools, one for data preparation, the other for visualization. The method of data preparation for the fluid flow and particle tracking is described. The choice of programming language, graphics library and workstation platform is then presented, followed by the development and functionality of the visualization tool. Finally, examples of the use of the system in real field development studies are given.
RESVIEW: A Practical 3-D Tool for Reservoir Engineers
Authors: Kjørholt Odd
Published: December 2007

This paper describes a three dimensional (3-D) graphical system that is used as a pre- and post-processor in connection with reservoir simulation. The system is able to make 3-D presentations of reservoir simulation input and output data together with information from mapping packages. In addition, the simulation grid geometry may be modified interactively.

The main aim of the system is to improve quality assurance (QA) on simulation input and output data, and to help engineers get a better understanding of the 3-D geometry, property relationships, and fluid flows.
SPIS: A Production Profile Integration System
Authors: Kjørholt Odd , Aadland Atle
Published: December 2007

This paper describes a computer system (SPIS) that is able to integrate results from different reservoir simulation models into a common production profile. Also, production data from sub-areas which have not been simulated, may be included. In the integration process it is possible to set restrictions and requirements on production from different sub-areas.

This paper explains the SPIS philosophy, the user interface and gives an example of application to a large North Sea field.
Reservoir Characterization and Modelling Supported by Expert Knowledge Systems
Authors: Surguchev L. M. , Zolotukhin A. B. , Bratvold R. B.
Published: December 2007

Decisions conserning development and depletion of petroleum reservoirs must be made under uncertainty in the decision supporting information. The incomplete knowledge of the reservoir charactistics contributes significantly to this uncertainty. In addition, and this is particularly true for improved oil recovery (IOR) projects, the uncertainty in the operational environment makes hard to confirm and substantiate research efforts.

To address these issues a multicriterion model is introduced. The model is coupled with a reservoir simulator and is used to estimate the applicability and efficiency of various field development strategies.

The multicriterion model used here applies the methods of interval theory and fuzzy set logic. It permits the integration of geophysical data, the potential efficiency of various IOR methods and other resource requirements. A pre-modelling multicriterion analysis is used to optimize field scale reservoir simulations for IOR methods. Particular field case scenarios show how the reservoir description information and IOR experience and knowledge can be used for decision making support. This work demonstrates that a first-order screening decision making system combined with a field scale reservoir model can be used to further optimize the recovery while reducing the costs and uncertainty in the decision making.
Expert System for Simulation of Oilfield Development: EKRAMON
Authors: Maksimov M. M. , Tetelbaum Y. l.
Published: December 2007

The expert system EKRAMON for choosing of the oil field development method and simulation of the oil field development process, working in an interactive user dialog mode on the base of IBM/AT class personal computer with an extended memory and giving the consultation results without any sufficient delay, is described.

It can be reached by striving for a diminishing number of the rules entered in the system with the help of expert work proper organization and an interpretation of expert data, according the developed method of certainty factors using. The high trustworthiness of the variants to be chosen could be achieved with the help of using a fuzzy logic. Different knowledge bases of the considered expert system are described.
A Practical Artificial Intelligence Application in Well Test Interpretation
Authors: Allain Olivier , Houzé O. P.
Published: December 2007

The take-off in Artificial Intelligence (AI) in the last decade has led to the development of such software tools as expert system shells, causing a tremendous incentive for applying AI in the Industry. In many cases, however, the original enthusiasm has gradually faded away as the results obtained did not meet the original expectations1.

This paper deals with AI applications to welltest interpretation and presents what can be achieved practically today and what can be expected in the future. Most of the early work was focused on developing assistant programs, helping the interpretation engineer to select the appropriate solution model(s). The goal of this study is instead to facilitate and speed-up the task of the interpretation engineer. An interactive computer program developed in this framework is described and several real test examples are presented. The practical advantages and limitations of the program are described in detail.
Use of Pressure Gauge Differentials in Well Test Quality Control and Well Performance Evaluation
Authors: Cliff W. J. , Boertje Alexander , Fjaere Ole
Published: December 2007

Over recent years, Well Test Analysis techniques and software have developed to the stage where it is possible to match a wide range of pressure responses using one or more model solutions! However, experience in Shell Gabon has shown that the pressure correction from gauge to sandface, along the wellbore, should not be overlooked when analysing the observed gauge response.

This paper examines the use of procedures, based on time synchronisation and analysis of differences between pressures measured on tandem precision pressure gauges, to assist in understanding the wellbore environment, and therefore in making this correction. Extension of the methodology to analysis of bottom hole to surface pressure differentials can also be used to better understand and optimise well performance. Specially-written software has been developed to assist in this ‘Differential Pressure Analysis’.
Hydraulic Jet Drilling
Authors: Maurer William C. , Heilhecker Joe K.
Published: December 2007

As a result of a detailed survey of over 25 novel drilling techniques, a laboratory study of hydraulic jet drilling was made. In initial tests, a cannon was used to fire 1.45-gal water pulses at rocks at pressures up to 25,000 psi. These tests showed that a threshold nozzle pressure must be exceeded before hydraulic jets will drill rock. Water jets having diameters of 0.2- to 1-in. drilled holes with diameters ranging from 0.8 to 4 in. in sandstone and limestone. These holes, which were 1 to 3 in. deep, were drilled in 0.02 to 0.2 seconds. These tests showed that water jets can effectively drill sedimentary rocks.

Following these tests, a 2-in.-diameter hydraulic jet drill was tested in a laboratory rig. A high-pressure pump was used to pump water continuously through this drill at pressures up to 13,500 psi. This drill penetrated pressures up to 13,500 psi. This drill penetrated Carthage marble at 180 ft/hour, Indiana limestone at 280 ft/hour and Berea sandstone at 300 ft/hour. These tests showed that a full-scale hydraulic jet drill [3,000 hp] should drill 8-in.-diameter holes in average-strength sedimentary rocks at rates of 200 to 300 ft/ hour, These high drilling rates show that hydraulic jet drills have high potential for drilling oil wells economically.

Introduction

A survey of over 30 novel drilling techniques revealed that full-scale hydraulic jet drills [also drilled erosion drills] should have high drilling rates in oil wells. These hydraulic jet drills use high-pressure water jets [5,000 to 70,000 psi] to shatter rock and pump the debris from the hole bottom. pump the debris from the hole bottom. Following this survey, we measured hydraulic jet drilling rates and studied variables that affect hydraulic drilling rate. These tests showed that hydraulic jet drills can drill sedimentary rocks at high rates and that they have potential for drilling oil wells economically. Our results, along with a summary of the findings of other investigators, are presented in this paper.

BACKGROUND INFORMATION

Rock Removal Mechanism

A threshold nozzle pressure must be exceeded before water jets will effectively shatter and drill rocks. This threshold pressure increases with rock strength; many water pressure increases with rock strength; many water jets will effectively drill weak materials such as coal or concrete, but will not drill hard rocks such as granite or basalt. Abrasives [e.g., sand or steel shot] have been used in erosion jets operating below threshold pressure.
Review of New API-Recommended Practices for Petroleum Production Above Ground Storage Tank Installation, Inspection, and Repair
Authors: Hein N.W. , Loudermilk M.D.
Published: December 2007

Safe operation and mechanical integrity of above ground storage tanks are very important to the petroleum industry due to both environmental and financial considerations. Recent work by API and the industry resulted in new, consensus recommendations for production tanks. These recommended practices have been detailed in a new API document that covers installation, leak detection, inspection requirements, maintenance and repair of the above-ground production storage tanks. Also included in this document are qualification requirements for the three levels of personnel and the different inspections that they can do. This paper reviews the major, new recommended practices and changes to the previous edition of the API Recommended Practice 12R1.

Introduction

The 1988, diesel fuel tank failure in Pennsylvania spurred the petroleum production, refining and transporting industries to develop environmentally safe practices for the inspection and maintenance of above ground storage tanks (AGSTs).

Originally, the American Petroleum Institute (API), which coordinated the efforts for the petroleum industry, had the Refinery Department developing a document that could be used for the entire industry. This was undertaken since the majority of refineries are located near waterways, rivers, etc. and their large volume AGSTs posed a greater risk for environmental problems than storage tanks from the production side of the industry.

The Refinery Department's main document developed for maintenance and inspection of AGSTs was API Standard 653. While this document was being developed, the API had two independent studies conducted. The first was a survey of AGSTs. This survey developed estimates of the number and capacity of AGSTs in the petroleum industries. The results of this survey are shown in the following comparison table.
Innovative Treatment Alternatives for Oily Wastes Generated During the Exploration and Production of Oil and Gas
Authors: Kabrick R. M. , Rogers L. A.
Published: December 2007

The Exploration and Production (E & P) of oil and gas generates significant quantities of oily wastes, including oily drill cuttings, spent oil-based drilling muds, crude oil contaminated soils, crude oil tank bottoms, and reserve pit oily sludges. As E & P companies have become increasingly aware of environmental liabilities (past, present, and future) associated with E & P operations, they have sought alternatives to their present oily waste management practices. This paper discusses two innovative treatment alternatives for E&P oily wastes, thermal desorption and biological liquid/solids treatment. These two technologies are fully developed and have just recently been demonstrated at full-scale on refinery oily wastes and at pilot-scale on E & P oily wastes.

Results of pilot-scale testing indicate that biological liquid/solids treatment of E & P oily waste can significantly decrease the oil and grease (O & G) fraction of the waste in a reasonable time period and for a reasonable cost (<$75/yd3). O & G half-lives were measured at <15 days. Thermal desorption can reduce O & G to < 1% in oily drill cuttings at a cost of <$100/yd3. Both technologies are currently being applied to the treatment of refinery oily wastes. An overview of both treatment technologies is presented in this paper, including process fundamentals, operational considerations, and results of recent pilot-scale testing on E & P oily wastes.
Laminar Displacement in Annuli: A Combined Experimental and Theoretical Study
Authors: Tehrani Ahmadi , Ferguson John , Bittleston S. H.
Published: December 2007

The placement of cement in an annulus is a crucial operation in the life of an oil well. To ensure zonal isolation, the drilling mud must be completely displaced from the annulus. Poor displacements require remedial squeeze cementing which is both costly and time consuming. The process is complex, involving the time-dependent motion of multiple non-Newtonian fluids, with different densities and rheologies, flowing in a three dimensional well-bore. Hence, it is not surprising that there are conflicting views on the best possible way to control displacement.

This paper discusses the displacement process from both a theoretical and experimental points of view. A lab scale facility has been designed by applying dynamic similarity. This allows a careful investigation of displacement. A brief outline is given of a model for predicting the process. It is shown that the experiments and theory are in excellent qualitative agreement. We discuss some of the controlling mechanisms and show that under some circumstances azimuthal instabilities arise. Finally, we simulate a typical complicated situation and show the importance of good spacer design.
Field Testing of a Cationic Polymer/Brine Drilling Fluid in the North Sea
Authors: Beihoffer T. W. , Growcock F. B. , Deem C. K. , Dorrough D. S. , Bray R. P. , Munro Roderic , Guild G. J. , Hanni G. L. , Prewett H. H.
Published: December 2007

This paper discusses the field testing of a cationic polymer/brine drilling fluid (CBF) on seven wells drilled in the North Sea. Two wells were drilled in the Norwegian sector and five wells were drilled in the U.K. sector. Hole sizes on the wells varied from 17.5" to 6", hole deviations varied from vertical to 55 degrees and maximum TD was below 14,000 feet measured depth. Field data are presented along with a discussion of the performance of CBF, including benefits, limitations and costs as compared to oil-based and conventional water-based muds.

CBF appears to be more inhibitive than other water-based drilling fluids used in the area. The tests prove that CBF, while not as inhibitive as oil-based mud (OBM), is sufficiently inhibitive to be used as an alternative to OBM in many areas where OBM has previously been thought necessary.

Advantages of CBF over conventional water-based fluids include: Ease of maintenance: Tests have been developed to quantitatively measure the inhibitive components of the fluid. This allows the fluid to be run like a chemical process without guesswork.Contamination resistance: Large amounts of solids contamination can be tolerated without adverse changes in fluid rheology.The ability to independently control fluid properties: The major components of CBF work independently of each other, greatly simplifying maintenance. This is significantly different from conventional fluids where the addition of polymers to control fluid loss or improve inhibition often causes large changes in fluid rheology.

The information provided in this paper can assist operators in evaluating alternatives to oil-based fluids in areas where the use of OBM is restricted.
CO2 Foam Field Verification Pilot Test at EVGSAU: Phase II—Foam Injection Design and Operating Plan
Authors: Stevens J. E. , Harpole K. J. , Zornes D. R. , Martin F. D.
Published: December 2007

The East Vacuum Grayburg San Andres Unit (EVGSAU) operated by Phillips Petroleum, is the site selected for a comprehensive evaluation of the use of foam for improving the sweep efficiency of a CO2 flood. The four-year project is jointly funded by the EVGSAU Working Interest Owners (WIO), the U.S. Department of Energy (DOE), and the State of New Mexico. The Petroleum Recovery Research Center (PRRC), a division of the New Mexico Institute of Mining and Technology (NMIMT), is providing laboratory and research support for the project. A Joint Project Advisory Team (JPAT) composed of technical representatives from numerous major oil companies, PRRC, and DOE provides input, review and guidance for the project.

This paper is the second in a series of papers detailing various aspects of the CO2 Foam Field Verification Pilot test at EVGSAU. An earlier paper summarized the project plans and detailed the laboratory work leading to the selection of a surfactant for the field trial. This paper presents: 1) an overview of the operating plan for the project, 2) details of the foam injection schedule and design criteria, and 3) a discussion of the data collection program and performance criteria to be used in evaluating successful application of foam for mobility control in the EVGSAU CO2 project.

Specific items discussed in the foam injection design include the determination of surfactant volume and concentration, selection of the surfactant-alternating-gas (SAG) injection sequence for foam generation, field facilities, operations during foam injection, and contingency plans. An extensive data collection program for the project is discussed including production testing, injection well pressure and rate monitoring, injection profiles, production well logging, observation well logging program, and both gas and water phase tracer programs.
Cyclic CO2 Injection for Heavy-Oil Recovery in Halfmoon Field: Laboratory Evaluation and Pilot Performance
Authors: Olenick Steve , Schroeder F. A. , Haines H. K. , Monger-McClure T. G.
Published: December 2007

This paper describes an immiscible CO2 project conducted in Halfmoon field, Wyoming. Laboratory results indicated that CO2 could improve recovery of the asphaltic, 17 °API gravity crude. The primary project incentive was that a gas source existed in the field. Incremental oil was produced in the field, but the project was not economic at present oil prices.
Economic Shortsightedness: One Cause and Cure
Authors: Campbell J. M. , Campbell R. A.
Published: December 2007

Oil companies are currently being chastised by employees and investors for taking extremely shortsighted perspectives in both operations and investment practices. Such criticism is old hat for other industries in the Western world. Advocates of the Japanese business style actively promote radical restructuring of American business to force management to take a longer view, especially in the petroleum industry. Even as the flaws in the Japanese system become more apparent, raising some doubts about the Japanese ability to sustain future growth, the core question still remains: Is the petroleum industry taking a shortsighted view and if so, what are the causes?

Only one possible cause for shortsightedness is addressed in this article. Other causes certainly do exist and deserve discussion but are beyond the scope of this paper. The economic methodology forming the basis for investment and operating budgeting decisions provide is the only explanation discussed. The current methodology, in its myriad of applications, contains several fundamental assumptions whose implications for investment strategies are not well understood. This shortcoming causes some to favor extreme conservatism over a thoughtful, long-run strategic plan.

The background for the shortsightedness is reviewed first and the implications for petroleum investments summarized. One possible solution for the shortsightedness and the habit of multi-counted risk levels is outlined. No single measure of profit, however, can ever hope to encompass the vast range of risk and return issues facing companies today. To realize the limitation of any single profit measure is the first step toward a more thorough decision-making process.
Displacement by Foam in Porous Media
Authors: Liu Dianbin , Castanier L. M. , Brigham W. E.
Published: December 2007

In steam drives and certain gas injection projects, the use of foamers to reduce steam and gas mobility has become a common way of improving sweep efficiency. Although the process is widely used, no effective means have been available to optimize it because there is no convenient flow model that properly describes the displacement characteristics of foam flow the way Buckley-Leverett theory describes simple two phase flow.

To attempt to develop a useful model for foam displacement, a number of experiments were run using surfactant laden water displaced by air at a constant rate in linear sandpacks. To decouple the displacement problem from the heat transfer mechanisms, no steam was used in these experiments. The saturations were measured in situ using the Cat Scanner; and, in addition, production and pressure histories were measured for the overall system.

First, water containing various concentrations of surfactant was displaced by air. As expected, these displacements follow Buckley-Leverett theory with saturation distributions growing linearly with volume injected. Also, as expected, the effective mobility of the air was a strong function of surfactant concentration as well as the air/water saturations. In addition, irreducible water saturations were found to be a strong function of surfactant concentration. Analytic expressions were developed to describe the relative permeability relationships as a function of saturations and surfactant concentration.

Next, experiments were run where surfactant laden water and air were injected simultaneously into a porous medium filled with pure water. This process more closely resembles field applications. The displacement fronts were spread more than when the water in place contained surfactant. When multiple fronts of different concentrations were used to match the displacements, the calculations predicted the greater spread observed experimentally, but did not properly ape the effect of distance moved. These calculations, for example, predicted that the saturation dissipation length would double as twice as much fluid was injected. The experiments showed less growth than this.

This slower growth rate could be the result of a dispersion term in the displacement. An equation was developed which included such a term and its predictions were found to match the experiments. The in situ saturation distributions were matched with distance and time as well as the overall recovery histories of the displacements. Under the conditions of these experiments, about 20% of the total spread of the displacements was caused by dispersion, and the rest was caused by Buckley-Leverett spreading.

These modeling efforts have already resulted in insight for practical application. They predict that a large slug of surfactant solution at low concentration injected ahead of the steam will have a greater mobility control effect than will the same amount of surfactant injected simultaneously with steam.
Use of Pressure Transient Testing To Identify Reservoir Damage Problems
Authors: Kamal M. M. , Braden J. C. , Park Heungjun
Published: December 2007

This paper describes a model that was developed to interpret the pressure transient data from producing wells in the Prudhoe Bay waterflood area. The model provides a quantitative description of reservoir permeability as it changes with radius. The match between field data and the model quantifies the trend of the permeability distribution around the producing wells.

Some producing wells in the waterflood areas of the Prudhoe Bay field showed decline in oil and total fluid production rates with the onset of water breakthrough. Pressure buildup tests were run in an attempt to identify the cause of the production decline. Qualitative analysis of the signature of buildup tests was used to identify the most likely reservoir description that would produce similar results. That reservoir description was for a system of gradually decreasing permeability towards the wellbore.

After developing the model, it was added to a non-linear regression analysis program and the resulting package was used to determine the reservoir parameters. The excellent match between field and model results, obtained only from that model, helped identify the reason for declining production rates in the waterflood area of the field.

The solution presented in this paper can be used to analyze transient tests from reservoirs with damage problems or permeability variations with distance.
Horizontal Permeability Anisotropy Characterization by Pressure Transient Testing and Geological Data
Authors: Bandiziol Danilo , Massonnat Gerard
Published: December 2007

The anisotropy of horizontal permeability plays an important role in fluid flow distributions in reservoirs. However, it is rarely detected in the early stage of a reservoir study. Water break-through during production is usually the first evidence of such anisotropy. A technique to investigate the horizontal permeability has been developed, based on pressure transient analysis and geological data.

Anisotropy has been detected and quantified using a pressure transient analysis and a knowledge of the reservoir geometry derived from geological analysis. The results obtained are subsequently confirmed by petrophysical measurements on oriented cores. The use of these results has been of primary importance in matching the pressure history of the "full-field" numerical simulation.

The origin of the anisotropy was identified by a sedimentological study, based on core analysis and FMS interpretation. The anisotropy is related to the internal structure of the sandbodies (foresets), which were deposited in a shore-face environment. The azimuth of the paleo-coastline corresponds to the direction of the maximum value of permeability derived from the well-test analysis and the core measurements.
Acquisition of Wireline Formation Test Tool Data from Unconsolidated Turbidite Sediments, Deepwater Gulf of Mexico
Authors: Rollins D. R. , Crabtree P. T.
Published: December 2007

In this paper we discuss our experiences in acquisition of wireline formation test tool (FT) data. During 1984–1991, Shell Offshore Inc’s Deepwater Division has acquired over 1,500 wireline-conveyed formation test tool pressures and 50 FT samples in unconsolidated turbidite sand reservoirs at subsea depths between 10,000 and 20,000 feet. This FT data has been acquired in Gulf of Mexico wells in water depths as deep as 7,500 feet. This data set allows empirical estimates of the probability of success in acquiring sample and pressure information, as well as assessing the probability of the tool becoming stuck in the wellbore. We also include a brief discussion of experience regarding the operational parameters affecting data acquisition. The operational considerations discussed include the design and setup of the tools themselves and the mud systems and well designs used to optimize tool performance.

Our overall success rate in obtaining pressures is approximately 75%. The success rate for sampling is approximately 65%. Many factors combine to influence these success rates. We find that sticking of this tool is a problem in deviated wellbores, regardless of other factors such as overbalance and set time.
Integrating Seismic Data in Reservoir Modeling: The Collocated Cokriging Alternative
Authors: Xu Wenlong , Tran T. T. , Srivastava R. M. , Journel A. G.
Published: December 2007

The two sources of information commonly available for modeling the top of a structure, depth data from wells and geophysical measurements from seismic surveys, are often difficult to integrate. While the well data provide the most accurate measurements of depths there are rarely enough wells to permit an accurate appraisal from well data alone. On the other hand, the seismic data are generally less precise but more abundant. Two geostatistical methods, "external drift" and "collocated cokriging", are proposed to integrate the two sources of information. A case study is used to document the strengths and weaknesses of both approaches for constructing contour maps of the top structure and assessing the uncertainty on such maps through stochastic simulations.
Sucker-Rod Lift in Horizontal Wells in Pearsall Field, Texas
Authors: Cortines J. M. , Hollabaugh G. S.
Published: December 2007

Oryx Energy has been drilling horizontal wells in the Pearsall Field of South Texas since 1985. While many of these wells came in flowing at rates in excess of 1000 BO/D, it soon became apparent that the wells would need to be artificially lifted early in their life in order to maintain high production rates. Lifting these type wells has proven to be very challenging due to fluctuating rates, varying gas/oil ratios, offset interference and gas interference experienced across the field.

As production from these wells declined to rates below 100–200 BBL/D, Oryx started to aggressively pursue lowering the sucker rod pumps into the curved or lateral portion of the hole in order to reduce reservoir pressure and recover additional oil from the highly competitive Austin Chalk formation. This introduced new challenges as Oryx tried to determine the most economical and effective method and material to perform the job.

This paper reviews one operator's experience with sucker rod lift in the Pearsall Field and is based on data from over 150 wells, including over 80 which are pumping from the lateral section or "in the curve". Methods to reduce gas interference, increase pumping efficiency and extend the life of downhole equipment are addressed.
X-Ray CT Observations of Flow Distribution in a Shaped-Charge Perforation
Authors: Halleck P. M. , Atwood D. C. , Black A. D.
Published: December 2007

We have observed the distribution of flow into a perforation under simulated down-hole stress using an X-ray CT technique. Tests were performed in an Aluminum pressure vessel to allow collection of the X-ray data while maintaining confining pressure on the sample throughout the experiment. A Berea Sandstone target was placed under 500 psi confining pressure and perforated with a 6.5-g (explosive weight) perforator using overbalanced conditions. The perforation was cleaned and flow rate measured under radial-flow boundary conditions using odorless mineral spirits. Flow distribution observations consisted of slow injections of an X-ray opaque tracer followed by collection of X-ray CT image data. The advance of the clearly visible tracer flow front after each injection maps profiles of flow impedance along the perforation.

Observed radial flow rates are highest near the tip end of the perforation. This contradicts the conventional idea of uniform-thickness zone of reduced permeability around a perforation. The present observation suggests that damage is greater near the entrance hole and decreases toward the tip of the perforation. The observed profile can be explained by relating the extent and magnitude of permeability reduction to the amplitude and duration of the shock pressure caused by the impact of the shaped charge jet. Near the entrance hole, the rock is penetrated by the leading, high velocity portion of the jet, creating high shock pressures and more extensive damage. This view is also supported by indentation damage measurements reported elsewhere in this session.
Production Enhancement From Topsides Changes at an Offshore Gas Cycling Project
Authors: Miller J. H.
Published: December 2007

This document provides a case history illustrating how debottlenecking one vessel can significantly improve throughput. It also describes some of methods used to cope with the existing vessel while the case for the new, larger vessel was made and while it was under construction.

Vessel sizing theory is not the primary scope of this article, but the basic ideas are noted and enough data is presented to illustrate the problem.

Additional problems in commissioning natural gas liquid pumps to take full advantage of the increased throughput are also discussed.
Review of New API Pump Setting Depth Recommendations
Authors: Hein N. W. , Loudermilk M. D.
Published: December 2007

Proper design and selection of downhole sucker rod pumps are necessary to extend the life and reduce operating costs for this type of artificially lifted well. This paper presents the results of an API task group’s work analyzing the pertinent formulas, failure modes and necessary information needed to determine the theoretical setting depth limits for tubing and insert rod pumps. Burst, collapse, and fatigue considerations have been incorporated into the formulas. Based on these formulas, it will now be possible to consistently compare different manufacturer’s recommendations on setting depths for different sizes, types, and metallurgy of pumps.
Reservoir Monitoring Over a Producing Norwegian Oil Field
Authors: Johnstad S. E. , Dunlop K. N. B. , Uden R. C.
Published: December 2007

A pilot study over Norsk Hydro's Oseberg field was conducted to confirm that it is possible to monitor hydrocarbon fluid movement in this producing reservoir using repeat 3D seismic data and reservoir simulation.

Two 3D surveys were collected about 16 months apart using the same vessel and equipment and processed using identical parameters. It was important to maneuver the monitor survey in 3D space to the base survey to allow for an optimum comparison.

A detailed interpretation of both surveys were made and even intra-Brent events showed a high similarity between interpretations. The stratigraphie parameters of the geologic model and the related petrophysical parameters were used to build an acoustic model of the reservoir. Detail was added by seismic inversion such that the refined geologic model best fitted both the initial geologic model and the seismic data. The refined model was history matched with a reservoir simulator to estimate fluid saturations at dates corresponding to the two seismic surveys, and these saturations were used for comparison with the observed seismic differences.

The comparison showed a seismic anomaly between the two 3D surveys at a position where the Gas Oil Contact was expected to move. This had spatial continuity and extent, of a similar shape to the simulated saturation changes. The seismic data provided evidence of the configurations of fluid fronts between wells, and not directly observable from well data.
Using a Multilayer Reservoir Model To Describe a Hydraulically Fractured, Low-Permeability Shale Reservoir
Authors: Frantz J. H. , Gatens J. M. , Hopkins C. W.
Published: December 2007

This paper summarizes the development and application of a multi-layer reservoir description for the Gas Research Institute (GRI) Comprehensive Study Well 2 (CSW2), which is completed in the Devonian Shales and located in Calhoun Co., WV. We determined that a two-layer reservoir description best describes the complex reservoir and hydraulic fracture system of the CSW2. This reservoir description, determined using a numerical simulator, matched all the data collected, including pre- and post-fracture flow/buildup tests, multi-layer communication tests, individual-layer injection/falloff tests and pre- and post-fracture production data.

The results of this study indicate that a multi-layer reservoir description provides better estimates of post-fracture performance compared to a more conventional, single-layer reservoir description. This result also explains previous, optimistic estimates of post-fracture well performance which were based on single-layer interpretations of pre-fracture test data. This paper reviews and discusses briefly the many diagnostic tests performed on the CSW2, but focuses on the history match analysis and results determined with a two-layer reservoir model. The testing and analysis approach presented in this paper can be applied generally to other tight formations.
Case Study of Stevens Sand Horizontal Well
Authors: Marino A. W. , Shultz S. M.
Published: December 2007

The Yowlumne horizontal well was completed in March 1991 at a measured depth of 14,005’ (11,253’ true vertical depth). The 2252’ horizontal lateral developed a thin Stevens Sand interval that could not be economically developed using vertical wells. The increased pay exposure and drainage radius from a horizontal well provided higher rates and reserves, at lower capital and operating costs, than vertical wells. The horizontal well has produced at more than three times the rate of previous vertical wells in this part of the Yowlumne field.

At the time it was completed, the Yowlumne horizontal well was the most ambitious horizontal drilling project undertaken onshore in California. The well is noteworthy because it exploited a thin sandstone oil column in an active waterfiood, and has an effectively cemented completion. This paper provides a comprehensive analysis of the project’s design and results in three areas: reservoir engineering, drilling and completion.
Characterizing the Effects of Heterogeneity on Oil Recovery by Dry Gas Injection
Authors: Newley T. M. J. , Begg S. H.
Published: December 2007

This paper describes a conceptual study to assess the impact of small-scale heterogeneities on the vaporization by lean injected gas of residual oil remaining in a gas cap after gas cap expansion. Two heterogeneous reservoir elements have been considered, one with a rapidly varying distribution of porosity and permeability and the other with a more slowly varying distribution. The flow of lean gas through each element was modelled using a compositional reservoir simulation program.

The study shows that small-scale heterogeneities within a conventional simulation gridblock can have a significant impact on recovery of residual oil by lean gas. For the heterogeneities used in this study, recovery was reduced by up to one third of that obtained by assuming the gridblock has uniform properties.

The study also shows that the effect of small-scale heterogeneities can be accounted for in compositional simulation by treating the fluid in the gridblock as incompletely mixed.
Wired Pipes for a High-Data-Rate MWD System
Authors: Faÿ J. B. , Faÿ Hubert , Couturier Antoine
Published: December 2007

This paper describes a field drilling experiment in a preselected section of a well, performed to test an electric high-data-rate telemetry system.

The system uses wired pipes from the surface to an intermediate position and an electrical cable inside the drill pipes and the bottom hole assembly to complete the transmission link. Data are transmitted up from the downhole sensor package to the surface computer unit. The process enables continuous transmission of downhole data while drilling or not, at a sampling rate for instance of 360 times per second of four drilling parameters among the variables to be collected.

The field results indicate that this telemetry system is adaptable, reliable and able to transmit numerous and accurate data for hours.

The process should not be considered as a competitor with commercial MWD* systems, but, at a high rate and with greates accuracy, it enables an analysis to be made of downhole drilling variables such as drill string vibrations, actual environmental conditions or dynamic bit behavior.
The Selection of Downhole Annulus Systems for the Piper, Claymore, and Saltire Fields
Authors: Ward R. G. H. , Humphreys A. T. , Steele J. A.
Published: December 2007

The types of well that can benefit from downhole annulus safety systems (DBASS) are discussed. Platform gas lifted wells are treated in more detail because this technology is particularly appropriate to them.

The DHASS completion equipment that was available when Elf Enterprise Caledonia Ltd.(formerly Occidental Petroleum Caledonia Ltd.) first investigated its use is presented. The drawbacks of this equipment and the developments that have taken place since then due to cooperation between users and suppliers are discussed in relation to their desired features.

The types of equipment that have been selected by Elf Enterprise for its existing and new North Sea fields and some early operating history are discussed. Recommendations for additional work to further develop the systems are made.
Experience with Slimhole Gravel Packs
Authors: Gollob K. W.
Published: December 2007

This paper presents a case history of a slim hole gravel packing operation and completion. The gravel/water pack was carried out in a domestic oil well of OMV, Austria in the oil & gas province of the Vienna basin.

In the past, slim hole well completions being not common have kept most of the production & service engineers from putting any effort to design an inside casing gravel pack for slim holes to overcome the problem of sand production from unconsolidated sand formations.

With our experience, OMV is able to produce oil and gas from slim holes. Production history of our gravel- packed slim hole wells shows, that a proper design and a good on-site job execution made it possible to install successfully an inside casing gravel pack.

The gravel pack work string had to be redesigned and adapted for being applicable to slim hole conditions.

It is to be noted that the design and the manufacturing of all desired equipment was done inhouse using entirely OMV 's own resources without any outside help.

Drilling slim holes through unconsolidated hydrocarbon bearing formations is no more a disadvantage for producing these reservoirs. Inside casing gravel packing to prevent moveable sand from flowing can be successfully installed in slim hole sections.
A Practical Approach to a Software Activity Management Application to a Multipurpose Reservoir Simulator
Authors: Lefevre Didier , Labonne Marcel
Published: December 2007

This paper describes a general code management system which allows an exhaustive history control of all the software units and associated knowledge files. Practical examples related to its application to reservoir engineering software, mainly composed of a multipurpose reservoir simulator, are given.
An Adaptive Telemetry System for Hostile Environment Well Logging
Authors: Gardner W. R. , Goodman K. R.
Published: December 2007

The operation of hostile environment logging tools at temperatures up to 250° C stresses not only the tools, it also places severe demands upon the wireline telemetry due to the wide variations in the logging cable transmission characteristics. A robust adaptive wireline telemetry system for use in hostile environments has been developed that combines sophisticated digital communication methods with modern Digital-Signal-Processing (DSP) techniques. The downhole telemetry transmitter outputs a multilevel signal. The uphole receiver includes an adaptive transversal-filter equalizer (TFE) that is continually optimized to correct for changing signal distortion. The system was designed to operate robustly at high data rates over the temperature range of 0 to 250° C.
Optimising Field Design and Operational Requirements by Integrated Reliability and Maintenance Analysis
Authors: Ostebo Runar , Nerhus Olav , Heggland John
Published: December 2007

This paper outlines a toolkit for integrated availability and maintenance analysis of complex offshore field installations. The potential savings in capital and operating expenditures can be large by implementing effective and systematic analysis methods. This paper focuses especially on implications on maintenance costs and costs associated with production loss. Cost-effective availability performance of the platform requires therefore consideration to reliability performance, maintainability performance and maintenance support performance. The nature of these methods implies application from early field planning into operational stages of a field development.
Handling of Produced Water: Looking to the Future
Authors: Georgie W. J. , Bryne K. H. , Kjaerland Gunnar
Published: December 2007

An assessment of the produced water handling facilities has been determined on three offshore platforms, under different operational modes. Specific drawbacks have been defined for the oil removal equipment, caused by the methods, by which the produced water, drain water and fluids from the drilling operation are separated and processed offshore.

An integrated part in the handling problem of produced water in the North Sea, is the difficulty in characterisation of the water and determining the long term water production profile, in the early phase of the field development. By underestimating the handling aspects and volume of produced water, as well as the lack of understanding of the water chemistry, the processing of produced water will be the bottle neck in maintaining the oil production. This is caused by the difficulty in meeting the capacity demand and oil content in the discharged water. However, this problem may easily be overcome by establishing good understanding of fluid chemistry.

This paper will address issues related to improvements in the design criteria of handling produced water and in the selection of suitable equipment in treating produced water on platforms in the North Sea or elsewhere.

In addition, issues regarding the environmental and toxicity aspects of produced water have been assessed, as part of a long term evaluation programme of produced water. It was determined, that although certain chemicals are added to the produced fluid in order to control scale and corrosion, the toxicity of produced water is not necessarily influenced significantly by such chemicals.

As part of the long term environmental objectives in handling produced water, the re-injection of produced water has been assessed. The advantages and disadvantages of such an approach will be addressed.